[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 [www.gpo.gov]
[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. www.regulations.gov (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 www.regulations.gov/, including any personal 
information provided. For detailed instructions on sending comments and 
additional information on the rulemaking process, see the ``Public 
Participation'' heading of the SUPPLEMENTARY INFORMATION section of 
this document.
    The virtual hearing, if requested, will be held using an online 
meeting platform, and the EPA will provide information on its website 
(www.epa.gov/ghgreporting) 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: [email protected]. 
For technical information, please go to the Greenhouse Gas Reporting 
Program (GHGRP) website, www.epa.gov/ghgreporting. 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 www.epa.gov/ghgreporting.

SUPPLEMENTARY INFORMATION: 
    Written comments. Submit your comments, identified by Docket Id. 
No. EPA-HQ-OAR-2023-0234, at www.regulations.gov (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 www.regulations.gov 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 www.epa.gov/dockets/commenting-epa-dockets 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 
(www.epa.gov/ghgreporting) 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 
www.epa.gov/ghgreporting or contact us by email at 
[email protected]. 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: www.epa.gov/ghgreporting.
    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 [email protected]. 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 www.epa.gov/ghgreporting. While the EPA expects the 
hearing to go forward as set forth above, please monitor our website or 
contact us by email at [email protected] 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)
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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 
(CH4) 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 (mtCO2e) 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 
CH4 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 CH4 
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 CH4emissions under 
subpart W (and corresponding waste emissions charges under CAA section 
136) is based on empirical data, accurately reflects the total 
CH4 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 
CH4 emissions from the oil and gas sector. It accomplishes 
this in multiple ways. First, it provides incentives for CH4 
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 
CH4 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 CH4 
emissions monitoring authorized under CAA section 103 subsections (a) 
through (c). Additionally, financial and technical assistance can be 
provided to: reduce CH4 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 
CH4 and other GHG emissions and waste; support innovation in 
reducing CH4 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 CH4 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.
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    \3\ Docket ID No. EPA-HQ-OAR-2022-0875.
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    The EPA is moving expeditiously to implement the incentives for 
CH4 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 CH4 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 
mtCO2e 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 CH4 
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 CH4 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 
CH4 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 CH4 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 CH4 emissions under subpart W and whether 
there were methodologies available to calculate those emissions.
    The proposed amendments include:
     Revisions to expand reporting to include new emission 
sources, in order to accurately reflect total CH4 emissions 
reported to the GHGRP.
     Revisions to add emissions calculation methodologies to 
incorporate additional empirical data and improve the accuracy of 
reported emission data.
     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.
     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:
     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.
     Addition of data elements related to emissions from 
plugged wells.
     Addition or clarification of throughput-related data 
elements for subpart W industry segments.
     Revisions to data elements or recordkeeping where the 
current requirements are redundant or alternative data would be more 
appropriate for verification of emission data.
     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 CH4 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 CH4 and waste emissions at an 
individual facility, whether the existing methodologies used empirical 
data, e.g., direct emissions measurements or monitoring of 
CH4 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 (https://sales.gastechnology.org/).
---------------------------------------------------------------------------

    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 
CH4 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 CH4 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 CH4 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 CH4 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 https://www.ghgsat.com/upload/misc/GHGSAT_MEDIAKIT_2021.pdf; 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 https://doi.org/10.1073/pnas.1908712116; 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 https://doi.org/10.5194/acp-22-9617-2022; 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 https://doi.org/10.1007/s00484-020-02063-z. 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 
https://doi.org/10.1016/j.rse.2023.113499. 2023; Duren, R. M., et 
al. ``California's methane super-emitters.'' Nature, Vol. 575, Issue 
7781, pp. 180-184, available at https://doi.org/10.1038/s41586-019-1720-3. 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 https://doi.org/10.5194/amt-10-3833-2017. 2017; Staebell, C., et al. ``Spectral calibration of the 
MethaneAIR instrument.'' Atmospheric Measurement Techniques, Vol. 
14, Issue 5, pp. 3737-3753, available at https://doi.org/10.5194/amt-14-3737-2021. 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, https://doi.org/10.5194/amt-15-2177-2022, 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: https://doi.org/10.1525/elementa.373. 
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

    There have been several studies asserting that bottom-up 
CH4 emission estimates reported by subpart W facilities 
underestimate annual CH4 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 https://doi.org/10.1073/pnas.1316546111. 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 https://doi.org/10.1126/science.aar7204. 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 
https://doi.org/10.1126/sciadv.aaz5120. 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 https://doi.org/10.1073/pnas.1522126112. 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 https://doi.org/10.1021/acs.estlett.1c00173. 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 https://doi.org/10.1021/acs.est.1c06458. 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 https://doi.org/10.1021/acs.est.2c06211. 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 https://www.epa.gov/system/files/documents/2022-04/2022_ghgi_update_-_blowouts.pdf and in the docket for this rulemaking, Docket Id. No. 
EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    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 CH4 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 CH4 
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.
---------------------------------------------------------------------------

    \16\ Duren, et al. ``California's methane super-emitters.'' 
Nature, Vol. 575, Issue 7781, pp. 180-184, available at https://doi.org/10.1038/s41586-019-1720-3. 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 ``Tt'' 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.
---------------------------------------------------------------------------

    \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. https://ccdsupport.com/confluence/pages/viewpage.action?pageId=198705183. 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 
(CO2) 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 CO2 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 CO2 and/or hydrogen sulfide and/or they are 
capturing CO2 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 mtCO2e. If the same 
owner or operator has other gathering and boosting operations in the 
same basin that have emissions less than 25,000 mtCO2e, 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 CH4 emission rate 
threshold of 100 kg/hr, in addition to the 250 mtCO2e 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.
---------------------------------------------------------------------------

    \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, https://doi.org/10.1038/ncomms14012; Alavarez, R.A., et al., 2018, Assessment of methane 
emissions from the U.S. oil and gas supply chain, Science 361(6398) 
186-188, https://www.science.org/doi/10.1126/science.aar7204; 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, https://doi.org/10.1021/acs.est.1c06458. Available in the docket for this 
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    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 
CH4 between October 2015 and February 2016 \21\ and a well 
blowout in Ohio released an estimated 40,000 to 60,000 tons of 
CH4 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.
---------------------------------------------------------------------------

    \21\ California Air Resources Board. 2016. Determination of 
Total Methane Emissions from the Aliso Canyon Natural Gas Leak 
Incident. Available at https://ww2.arb.ca.gov/sites/default/files/2020-07/aliso_canyon_methane_emissions-arb_final.pdf. 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. https://doi.org/10.1073/pnas.1908712116. 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 https://www.epa.gov/system/files/documents/2022-04/2022_ghgi_update_-_blowouts.pdf 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. https://doi.org/10.1088/1748-9326/ac8069. 
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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 https://doi.org/10.1021/acs.est.1c06458. 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 https://doi.org/10.1021/acs.est.2c06211. 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. https://www.cpuc.ca.gov/regulatory-services/safety/gas-safety-and-reliability-branch/aliso-canyon-well-failure; 
Cusworth, et al., 2021, Multisatellite imaging of a gas well blowout 
enables quantification of total methane emissions. Geophysical 
Research Letters, 48, e2020GL090864. https://doi.org/10.1029/2020GL090864; 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. https://doi.org/10.1016/j.rse.2021.112755. Available in the docket for this rulemaking, 
Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    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 mtCO2e per event or have a CH4 emission 
rate of 100 kg/hr or greater at any point in time. The 250 
mtCO2e 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 CO2e 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 mtCO2e 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 mtCO2e to be a reasonable emissions threshold for a 
``large'' event.
---------------------------------------------------------------------------

    \27\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and 
Sinks 1990-2014. EPA 430-R-16-002. April 2016. Available at https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2014 and in the docket for this rulemaking, Docket Id. 
No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    While 250 mtCO2e is much lower than the emissions from 
the Aliso Canyon or Ohio well blowout releases, we determined that a 
250 mtCO2e 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 
mtCO2e 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 mtCO2e 
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 mtCO2e 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 mtCO2e 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 CH4 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 
CH4 emission threshold be applied as an instantaneous 
emissions rate threshold, such that any emissions from any other large 
release event that emits CH4 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 CH4 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 
mtCO2e per event threshold, which would be approximately 
equivalent to a 3 million cubic feet release of natural gas. We request 
comment on whether the CO2e 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 mtCO2e event that spans two calendar years, 
with 200 mtCO2e 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 mtCO2e event that spanned 2 calendar years 
resulted in 40 mtCO2e of emission in reporting year 1 and 
360 mtCO2e 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 mtCO2e 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 mtCO2e or more on a 
per event basis, or 100 kg/hr of CH4 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 mtCO2e 
or more, or 100 kg/hr of CH4 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 CO2 
and CH4 in the gas released, and CO2 and 
CH4 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 CH4 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 https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2020 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 https://www.api.org/-/media/files/policy/esg/ghg/2021-api-ghg-compendium-110921.pdf. 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 CO2, CH4, and nitrous 
oxide (N2O) 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.

 Onshore petroleum and natural gas production: Blowdown vent 
stacks
 Onshore natural gas processing: Natural gas pneumatic device 
venting, Hydrocarbon liquids and produced water storage tank emissions
 Onshore natural gas transmission compression: Dehydrator vents
 Underground natural gas storage: Dehydrator vents, Blowdown 
vent stacks, Condensate storage tanks
 LNG storage: Blowdown vent stacks, Acid gas removal unit vents
 LNG import and export equipment: Acid gas removal unit vents
 Natural gas distribution: Natural gas pneumatic device 
venting, Blowdown vent stacks
 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 
CH4 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 CH4 
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 CH4 (EPA 2005).\39\ Optimization of the 
nitrogen removal unit can reduce CH4 in the outlet nitrogen 
stream to 2 percent (EPA 2005) and even to 1 percent CH4 by 
volume.\40\ The EPA GasSTAR program already accounts for CH4 
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 CH4 per year. For more information on 
the estimation of potential CH4 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 CH4 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 CH4 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 CO2). 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 
CH4 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 CH4 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 (CO2, CH4, and 
N2O) would be reported under proposed 40 CFR 98.236(n) 
separately from vented nitrogen removal unit emissions 
(CH4). 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 
CH4 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 CH4 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 CH4 emissions from produced water 
tanks associated with natural gas wells and 88,600 mt CH4 
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 CH4 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 CH4 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 CH4 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 CH4 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 CH4 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 
(https://www.bre.com/).
    \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 CH4 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 
CH4 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 CH4.\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 
CH4 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 CH4 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 CO2 emissions 
from this source. Based on available research, it appears that 
CH4 is the primary GHG emitted from this source, while 
emissions of CO2 are expected to be very small. However, as 
noted later in this section, the EPA is seeking comment on requiring 
reporting of CO2 emissions from mud degassing, including 
comment on the expected magnitude of CO2 emissions from mud 
degassing and appropriate calculation methods for CO2 
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 CH4 
and can contain other pollutants such as volatile organic compounds 
(VOC) and possibly CO2, 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 CH4 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 CH4-specific emission factors are 0.2605 
mt CH4 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 CH4 in the gas 
stream vented from mud degassing. The CenSARA methodology does allow 
for adjustment of the CH4 default emission factors to local 
conditions by multiplying the nationwide emission factor to the ratio 
of the local CH4 mole percent of vented gas to the mole 
percent of CH4 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  
https://www.deq.ok.gov/wp-content/uploads/air-division/EI_OG_Final_Report_CenSara_122712.pdf 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 CH4 emission factor of 0.2605 mt 
CH4 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 
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 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 CH4 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 CH4 per drilling day for water-based drilling 
muds and 0.07 mt CH4 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 
CH4 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 https://www.epa.gov/sites/default/files/2020-09/documents/ghgi-webinar2020-degassing.pdf and 
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-
0234.
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    Separately, API published updated CH4 and whole gas 
emission factors based on the emission factors from the 1977 EPA 
publication in their 2021 API Compendium.\56\ API's updated 
CH4 emission factors are based on a gas content of 65.13 
weight percent CH4, derived from sample data provided in the 
1977 EPA publication. While including the same THC and CH4 
emission factors as CenSARA, API specifies that these are for offshore 
drilling only. The API Compendium presents lower emission factors for 
onshore drilling. In the 2021 API Compendium, API stated that it 
adjusted the 1977 EPA values for borehole size and porosity to better 
reflect those used in onshore drilling. API's onshore production 
CH4 emission factors are 0.0458 mt per drilling day for 
water-based mud and 0.0103 mt per drilling day for oil-based and 
synthetic muds. Similar to CenSARA, the API methodology allows for the 
nationwide emission factors to be adjusted to local conditions by 
applying a ratio of the mole percent in vented gas from degassing at 
local operations to the nationwide mole percent of 83.85.
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    \56\ 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 https://www.api.org/-/media/files/policy/esg/ghg/2021-api-ghg-compendium-110921.pdf and in the docket for this rulemaking, Docket Id. No. 
EPA-HQ-OAR-2023-0234.
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    Although most efforts have focused on the development of emission 
factors for mud degassing, the 2021 API Compendium also encourages 
operators to use site-specific CH4 (and CO2 if 
present) measurements to estimate emissions if possible. Generally, 
measured data would involve use of mud-logger services with hydrocarbon 
gas sensors. In some cases, operators may use gas chromatography, but 
gas chromatography alone does not allow calculation of gas 
concentration in the mud. Gas emissions would be determined by using 
the volumetric flowrate of the mud, the amount of time of mud flow and 
the concentration of CH4 and CO2 in the mud.
    After careful consideration of the available literature and well 
drilling and mud degassing practices, the EPA is proposing two options 
in a new paragraph (40 CFR 98.233(dd)) to measure CH4 
emissions from drilling mud degassing: use of measurements taken 
through mudlogging and gas detection at representative wells and use of 
emission factors and activity counts.
    Calculation Method 1 would require the reporter to calculate 
CH4 emissions from mud degassing for a representative well. 
To qualify as a representative well, the well would be required to be 
drilled in the same sub-basin and at the same targeted total depth from 
the surface as the wells it is representative of. Calculation Method 1 
would be required to be used when the reporter has taken mudlogging 
measurements, including gas trap-derived gas concentration and mud 
pumping rate, for at least one well in the sub-basin at the approximate 
total depth. A CH4 emissions rate from mud degassing would 
be calculated for the representative well and the CH4 
emission rate for the well would be applied to the total time drilling 
mud is circulated through the wellbore during drilling for each of the 
other wells drilled in the same sub-basin and targeting the same 
approximate total depth from surface in the reporting year.
    The operator would be required to identify and calculate natural 
gas emissions for a new representative well at least once every 2 years 
for each sub-basin and targeted depth within the facility to ensure 
that the emissions from representative wells are representative of the 
operating and drilling practices within each applicable sub-basin in 
the facility. In the Onshore Petroleum and Natural Gas Production 
industry segment, facilities are defined at the basin-level. In the 
first year of reporting, however, the operator may use measurements 
from the prior reporting year if measurements from the current 
reporting year are not available.
    Proposed Calculation Method 1 uses a three-step approach to 
calculate emissions from mud degassing for each well in a particular 
sub-basin and at the same approximate total targeted depth. In the 
first step, reporters would calculate CH4 emissions for the 
representative well using proposed equation W-41. For this step, the 
reporter would need to know the average efflux mud rate from the mud 
pump in gallons per minute (gpm),

[[Page 50307]]

``MRr''; the total amount of time in minutes that drilling 
mud is circulated in the representative well, ``Tr''; the 
percentage of the fluid flow that is gas, ``Xn''; and the 
measured mole concentration of CH4, ``GHGCH4.'' 
If a representative well cannot be identified because mudlogging was 
not used for any well within the same sub-basin and at the same 
targeted approximate total depth, the reporter may choose a 
representative well within the facility that is drilled into the same 
formation and at the same approximate total depth.
    In the second step, reporters would calculate the CH4 
emissions rate for the representative well using proposed equation W-
42. The emissions rate would be derived by dividing the representative 
well's total annual CH4 emissions, ``Es,CH4,r,'' 
by the total time that drilling mud is circulated in the representative 
well, ``Tr.'' In the third step, reporters would apply the 
CH4 emissions rate calculated in the second step to other 
wells in the sub-basin that are at the same approximate total depth to 
derive the total volume of CH4 emissions for each well at 
that depth. In this step, the reporter would calculate total 
CH4 emissions for each well, ``p,'' in the same sub-basin 
and at the same approximate total depth as the representative well 
using proposed equation W-43, where the total time drilling mud is 
circulated in the well would be multiplied by the representative well's 
emissions rate, ``ERs,CH4,p,'' determined using equation W-
42 in step 2.
    If mudlogging measurements were not taken, the EPA is proposing 
that reporters would use Calculation Method 2 and determine emissions 
from mud degassing using proposed equation W-44, which incorporates the 
nationwide emission factors provided by the CenSARA study. 
Specifically, the EPA is proposing an emission factor of 0.2605 mt 
CH4 per drilling day per well for water-based mud and a 
factor of 0.0586 mt CH4 per drilling day per well for oil-
based and synthetic drilling muds. As noted by New York state, there 
are limited data and few studies on mud degassing emissions. The EPA is 
proposing these emission factors as an alternative calculation method 
because our assessment of the available literature is that these 
proposed emission factors are generally appropriate if measurements are 
not available. In addition, the emission factors proposed are 
consistent with those of several organizations that calculate and 
publish emissions from mud degassing in their inventories. As noted 
previously in this section, these factors are based on a CH4 
mole percent of 83.85 in the gas stream vented from mud degassing. The 
EPA is not proposing to allow adjustment of the emission factors for 
local conditions under proposed Calculation Method 2 because the use of 
emission factors under this proposed calculation method would only be 
allowed if the operator did not have site-specific measurements (i.e., 
would not have the measurement that would be the basis of such an 
adjustment).
    Although the EPA is proposing to use the nationwide emission 
factors provided by the CenSARA study, the EPA is proposing to define 
the number of drilling days differently than the study. Rather than 
considering the first drilling day to be the day the well is spudded, 
we are proposing that the total number of drilling days is the sum of 
all days from the first day that the borehole penetrates the first 
hydrocarbon-bearing zone through the completion of all drilling 
activity. The EPA believes that penetration of the first hydrocarbon-
bearing zone more accurately reflects the point in time where 
CH4 will start becoming entrained in drilling mud. The EPA 
is also defining the last drilling day as the day drilling mud ceases 
to be circulated in the well. Reporters would calculate emissions for 
each well by multiplying the emission factor by the number of drilling 
days per well per year.
    The EPA is seeking comment on these calculation methodologies, 
including whether there are calculation methodologies other than the 
proposed methods that the EPA should consider for calculating 
CH4 emissions from mud degassing. The EPA is also seeking 
comment on CO2 emissions from mud degassing, including the 
magnitude of CO2 emissions from this source type, whether 
emissions of CO2 should be reported, and suggested 
calculation methods for CO2 emissions. The EPA is also 
seeking comment on whether to consider mud weight balance in the 
derivation of emission factors, and if so, how to incorporate such 
considerations. Underbalanced, balanced, and overbalanced all lead to 
varying hydrostatic weights of the mud and could affect the flow of 
hydrocarbons into the well bore, possibly impacting emissions 
calculations. However, we are not aware of any studies to date that 
have considered mud weight balance.
    In addition to the calculation requirements, the EPA is proposing 
corresponding reporting requirements for emissions by well in 40 CFR 
98.236(dd). Specifically, for all wells with mud degassing emissions 
that use Calculation Method 1, the reporter would report the well ID 
number for each well for which mud degassing emissions are calculated, 
the approximate total depth of the well in feet below surface, and the 
total time in minutes that drilling mud is circulated in the well. 
Reporters would also report whether the drilling mud used was water-
based, oil-based, or synthetic. Additionally, for a well that is not a 
representative well, reporters would report the well ID number of the 
representative well that was used to derive the CH4 
emissions rate used to calculate emissions from the non-representative 
well.
    For reporters using Calculation Method 1, the EPA is also proposing 
to require additional data on representative wells, including the 
average mud flow rate in gpm, the concentration of natural gas in the 
drilling mud, the measured mole fraction of CH4 in the 
drilling mud, and the CH4 emissions rate. For reporters 
using Calculation Method 2, the EPA is proposing that reporters would 
report the well ID number for each well for which mud degassing 
emissions are calculated, the total number of drilling days at each 
well, and whether the drilling mud used was water-based, oil-based, or 
synthetic. Annual CH4 emissions in mt CH4 would 
be reported for each well whether emissions were calculated using 
Calculation Method 1 or Calculation Method 2.
    To clearly define the emission source type and parameters to use in 
the emissions calculations, the EPA is proposing to define three new 
terms in 40 CFR 98.238. The EPA is proposing to define ``drilling mud'' 
as a mixture of clays and additives with water, oil, or synthetic 
materials continuously pumped through the drill string and out the bit 
while drilling to cool and lubricate the drill bit and to move cuttings 
through the wellbore to the surface. The EPA is proposing to define 
``drilling mud degassing'' as the practice of safely removing pockets 
of free gas entrained in the drilling mud once it is outside of the 
wellbore. ``Mud rate'' is proposed to mean the pumping rate of the mud 
by the mud pumps, usually measured in gpm. The mud rate would be an 
input to proposed equation W-41.
    Finally, we note that in proposing these new requirements, we 
considered adding mud degassing emissions to two existing source 
categories in the Onshore Petroleum and Natural Gas Production industry 
segment, well completions and workovers with hydraulic fracturing and 
well completions and workover without hydraulic fracturing, rather than 
proposing calculation and reporting

[[Page 50308]]

requirements for mud degassing as a new emissions source. Upstream oil 
and gas development is undertaken in two stages, exploration and 
production. The exploration stage consists of well drilling followed by 
well completion, including casing of the well and hydraulically 
fracturing the well (in the case of hydraulically fractured 
completion). However, for purposes of this proposal, the EPA has 
determined that well drilling activities are a distinct activity 
separate from well completion. For example, a common practice in the 
oil and gas industry is to drill a well but leave the borehole 
uncompleted (referred to in the oil and gas industry as ``drilled but 
uncompleted''). These boreholes are left uncompleted for a period of 
time until economic conditions improve, completion crews are available, 
or for other reasons. Even without completion, the drilling activity 
still has the potential to produce emissions. Therefore, the EPA is 
proposing drilling mud degassing as a new emissions source type source 
for onshore petroleum and natural gas production facilities.
5. Crankcase Venting
    The EPA is proposing to add calculation and reporting requirements 
for CH4 emissions from a new emission source type, crankcase 
ventilation from RICE or GT used in the Onshore Petroleum and Natural 
Gas Production, Onshore Natural Gas Processing, Onshore Natural Gas 
Transmission Compression, Underground Natural Gas Storage, LNG Storage, 
LNG Import and Export Equipment, Natural Gas Distribution, and Onshore 
Petroleum and Natural Gas Gathering and Boosting industry segments. 
Crankcase ventilation is the process of venting or removing blow-by 
from the void spaces of an internal combustion engine outside of the 
combustion cylinders to prevent excessive pressure build-up within the 
engine.\57\ This proposed source does not include ingestive systems 
that vent blow-by into the engine where it is returned to the 
combustion process.\58\
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    \57\ Cox, J. ``Managing Engine Blow-by with Crankcase 
Ventilation Systems.'' The Solberg Blog, June 17, 2022. Available at 
 https://www.solbergmfg.com/en/resources/blog/crankcase-ventilation-system-for-engine-in-the-pow and in the docket for this rulemaking, 
Docket Id. No. EPA-HQ-OAR-2023-0234.
    \58\ See, e.g., Caterpillar. Application & Installation Guide: 
Crankcase Ventilation Systems. LEBW4958-04. 2015. Available in the 
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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    The EPA first proposed including ``crankcase vents'' in subpart W 
in the January 2016 proposal to add leaker emission factors (81 FR 
4987, January 29, 2016). At that time in 2016, the EPA proposed to add 
new monitoring methods for detecting leaks from oil and gas equipment 
in the petroleum and natural gas systems source category consistent 
with the leak detection methods in the then proposed NSPS OOOOa (80 FR 
56593, September 18, 2015). Specifically, in 2016, the EPA proposed 
aligning subpart W equipment components with the 2015 proposed NSPS 
OOOOa definition of ``fugitive emissions component,'' which was ``any 
component that has the potential to emit fugitive emissions of 
[CH4] or VOC at a well site or compressor station site, 
including but not limited to valves, connectors, pressure relief 
devices, open-ended lines, access doors, flanges, closed vent systems, 
thief hatches or other openings on storage vessels, agitator seals, 
distance pieces, crankcase vents, blowdown vents, pump seals or 
diaphragms, compressors, separators, pressure vessels, dehydrators, 
heaters, instruments, and meters'' (80 FR 56593, September 18, 2015). 
The proposed NSPS OOOOa definition of ``fugitive emissions component'' 
also indicated that it did not include devices that ``vent as part of 
normal operations.'' Commenters on the proposed NSPS OOOOa indicated 
that some of the examples listed within the proposed definition of 
``fugitive emissions component'' did include devices that vent as part 
of normal operations, including crankcase vents.\59\ As a result of 
these comments, the final definition for ``fugitive emissions 
component'' in the NSPS OOOOa (81 FR 35824, June 3, 2016) did not 
include the reference to ``crankcase vents'' or other types of devices 
that vent as part of normal operations, consistent with the EPA's 
stated intent in the 2015 NSPS OOOOa proposal not to include those 
devices in the definition. The 2016 promulgated amendments to subpart W 
for fugitive emissions aligned with the definition of ``fugitive 
emissions component'' in the final NSPS OOOOa.
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    \59\ U.S. EPA. EPA's Responses to Public Comments on the EPA's 
Oil and Natural Gas Sector: Emission Standards for New, 
Reconstructed, and Modified Sources. Chapter 4--Fugitives 
Monitoring. May 2016. Available as EPA-HQ-OAR-2010-0505-7632 and in 
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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    We have estimated sector-wide emissions from crankcase ventilation 
using data from a 2015 study published by Johnson et al., Methane 
Emissions from Leak and Loss Audits of Natural Gas Compressor Stations 
and Storage Facilities.\60\ In this study, the audit of three natural 
gas compressor stations and two natural gas storage facilities yielded 
an average ratio of crankcase-to-exhaust emissions of 14.4 percent. The 
study authors compared total emissions rate (crankcase plus exhaust) 
against literature values of a four-cylinder lean burning engine in 
EPA's Compilation of Air Pollutant Emission Factors (AP-42).\61\ The 
literature value overpredicted the combined emissions by 11.4 percent, 
which slightly exceeded the calculated uncertainty for exhaust 
emissions of 7.2 percent. This comparison indicates the measured value 
offers a reasonable estimate of CH4 loss from natural gas 
compressor stations and storage facilities. Based on this study, the 
EPA conservatively estimates that the total CH4 emissions 
from crankcase ventilation that could be reported to the GHGRP would be 
approximately 800,000 mt per year, assuming crankcase emissions are 
14.4 percent of combustion emissions from all proposed industry 
segments. For more information on the estimation of potential 
CH4 emissions from crankcase venting, see the subpart W TSD, 
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-
2023-0234.
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    \60\ Johnson, D.R., et al. 2015. ``Methane Emissions from Leak 
and Loss Audits of Natural Gas Compressor Stations and Storage 
Facilities.'' Environ. Sci. Technol. 2015, 49, 13, 8132-8138. July 
4, 2015. Available at https://doi.org/10.1021/es506163m and in the 
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    \61\ U.S. EPA. AP-42 Compilation of Air Pollutant Emission 
Factors, 5th ed. Volume I, Chapter 3: Stationary Internal Combustion 
Sources: Section 3.1 Stationary Gas Turbines and Section 3.2 Natural 
Gas-fired Reciprocating Engines. Available at https://www.epa.gov/air-emissions-factors-and-quantification/ap-42-fifth-edition-volume-i-chapter-3-stationary-0 and in the docket for this rulemaking, 
Docket Id. No. EPA-HQ-OAR-2023-0234.
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    The API provided an emission factor for CH4 from 
crankcase ventilation in their 2021 API Compendium.\62\ API's emission 
factor was developed from results from Phase II of a comprehensive 
measurement program conducted to determine cost-effective directed 
inspection and maintenance control opportunities for reducing natural 
gas losses due to fugitive equipment leaks and avoidable process 
inefficiencies. Phase II of the program was conducted at five gas 
processing plants, seven gathering compressor stations, and twelve well 
sites during 2004 and 2005.\63\
---------------------------------------------------------------------------

    \62\ 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 https://www.api.org/-/media/files/policy/esg/ghg/2021-api-ghg-compendium-110921.pdf and in the docket for this rulemaking, Docket Id. No. 
EPA-HQ-OAR-2023-0234.
    \63\ Cost-Effective Directed Inspection and Maintenance Control 
Opportunities at Five Gas Processing Plants and Upstream Gathering 
Compressor Stations and Well Sites. EPA Phase II Aggregate Site 
Report prepared for U.S. EPA Natural Gas STAR Program by Natural Gas 
Machinery Laboratory, Clearstone Engineering Ltd., and Innovative 
Environmental Solutions, Inc. March 2006. Available at https://www.epa.gov/sites/default/files/2016-08/documents/clearstone_ii_03_2006.pdf and in the docket for this rulemaking, 
Docket Id. No. EPA-HQ-OAR-2023-0234.

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[[Page 50309]]

    Based on the information provided in this section, the EPA is 
proposing to add 40 CFR 98.233(ee) to provide a component-level average 
emission factor approach for estimating emissions for crankcase 
ventilation based on the number of crankcase vents on RICE or GT in the 
facility. The proposed CH4 emission factor for crankcase 
ventilation is 2.28 standard cubic feet per hour per source, as 
provided in the 2021 API Compendium. The 2021 API Compendium emission 
factor was selected as representative because it was developed from 
results of the most comprehensive field study of crankcase ventilation 
in the oil and natural sector available to date. Site-specific 
information required for the emission calculation would include the 
number of crankcase vents on RICE or GT, the operating time of each 
engine or GT, and the concentration of CH4 in the gas stream 
entering the engines or GT. If site-specific CH4 
concentration is unknown, the proposed provision includes an option to 
determine the CH4 concentration in the gas stream using 
either engineering estimates based on best available data or the 
provisions of 40 CFR 98.233(u)(2). The EPA is seeking comment on 
whether this calculation method is appropriate and whether there are 
other methodologies that we should consider providing, including 
details on how those additional methods would be applied to this 
source. For reporting, the EPA is proposing to add 40 CFR 98.236(ee) to 
require reporters to provide emissions, the number of crankcase vents 
at the facility, and engine or GT operating hours.

D. Reporting for the Onshore Petroleum and Natural Gas Production and 
Onshore Petroleum and Natural Gas Gathering and Boosting Industry 
Segments

    Within the Onshore Petroleum and Natural Gas Production and Onshore 
Petroleum and Natural Gas Gathering and Boosting industry segments, GHG 
emissions and activity data are currently generally reported at the 
basin, county/sub-basin, or unit level, depending upon the specific 
emission source. Examples of emission sources that report at the sub-
basin or county level include liquids unloading, completions and 
workovers with hydraulic fracturing, and storage tanks. Sources that 
report at the facility (basin) level include natural gas pneumatic 
devices, blowdown vent stacks, and equipment leaks. The current 
aggregation of data reported within the Onshore Petroleum and Natural 
Gas Production and Onshore Petroleum and Natural Gas Gathering and 
Boosting segments can present challenges in the process of emissions 
verification, with corresponding potential impacts on data quality, and 
it also limits data transparency.
    In order to address these concerns and improve data quality 
consistent with section II.C of this preamble, 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. As a first step, the EPA is proposing 
to revise the reporting requirements to be more explicitly consistent 
with the current reporting form structure for the well identification 
(ID) numbers at the facility, with two proposed changes and one 
addition. Currently, for certain emission sources directly related to 
wells (liquids unloading, completions and workovers with hydraulic 
fracturing, completions and workovers without hydraulic fracturing well 
testing, and associated natural gas), subpart W requires reporters to 
provide a list of well ID numbers in each sub-basin that contributed to 
the emissions (e.g., a list of well IDs that had completions or 
workovers with hydraulic fracturing). Under existing 40 CFR 
98.236(aa)(1)(ii)(D) through (H), reporters are also asked to provide 
the counts of wells that were producing, acquired, divested, completed, 
and/or permanently taken out of production for each sub-basin, along 
with a list of well ID number for the wells in each of those 
categories. For the subpart W reporting form, these requirements were 
implemented through addition of a single table, in which reporters 
provide a list of all well ID numbers, the sub-basin, the operating 
status per 40 CFR 98.236(aa)(1)(ii)(D) through (H), and any well-
specific information required for the emission source types directly 
related to wells. The EPA is proposing to revise 40 CFR 
98.236(aa)(1)(ii) and add requirements to 40 CFR 98.236(aa)(1)(iii) 
that reflect this reporting form structure, with two notable changes. 
First, the EPA is proposing to no longer require reporting of the sub-
basin ID for each well. Instead, reporters would report the sub-basin 
ID by well-pad and then report the well-pad ID on which the well is 
located. The well-pad ID is a new proposed data element and is 
described in the following paragraph. Second, the EPA is proposing to 
revise the requirements to provide a list of well IDs for the five 
emission source types directly related to wells (currently required in 
40 CFR 98.236(f)(1)(ii), (f)(2)(i), (g)(1), (h)(1)(i), (h)(2)(i), 
(h)(3)(i), (h)(4)(i), (l)(1)(ii), (l)(2)(ii), (l)(3)(ii), (l)(4)(ii), 
(m)(1), (m)(7)(i), and (m)(8)(i)) to instead specify that reporters 
should report emissions and activity data for each of those emission 
source types by well within the source-specific reporting requirements, 
as described later in this section.
    Second, the EPA is proposing to add the following data elements: 
well-pad ID (for Onshore Petroleum and Natural Gas Production segment) 
and gathering and boosting site ID (for Onshore Petroleum and Natural 
Gas Gathering and Boosting). These proposed data elements are hereafter 
collectively referred to as ``site-level IDs.'' The EPA is proposing to 
add to 40 CFR 98.236(aa)(1)(iv) (for Onshore Petroleum and Natural Gas 
Production) and 40 CFR 98.236(aa)(10)(v) (for Onshore Petroleum and 
Natural Gas Gathering and Boosting) requirements for reporting of 
information related to each well-pad ID and gathering and boosting site 
ID, respectively. The proposed reporting elements for each well-pad ID 
include a unique name or ID for each well-pad, the sub-basin ID, and 
the location (i.e., representative latitude and longitude coordinates).
    For the Onshore Petroleum and Natural Gas Gathering and Boosting 
industry segments, the EPA is proposing at 40 CFR 98.236(aa)(10)(v) to 
require reporters to provide a unique name or ID, the site type, and 
the location for each gathering and boosting site. For the ``site 
type'' for each gathering and boosting site, the EPA is proposing that 
reporters would select between ``gathering compressor station,'' 
``centralized oil production site,'' ``gathering pipeline site,'' or 
``other fence-line site.'' The EPA is proposing a definition of 
``gathering compressor station'' in 40 CFR 98.238 to be used for the 
purposes of this reporting requirement and to differentiate gathering 
compressor stations from other types of compressor stations in subpart 
W (e.g., transmission compressor stations). The Onshore Petroleum and 
Natural Gas Gathering and Boosting industry segment also includes 
centralized oil production sites that collect oil from multiple well-
pads but that do not have compressors (i.e.,

[[Page 50310]]

are not ``compressor stations''). The EPA is also proposing to add a 
definition of a ``centralized oil production site'' in 40 CFR 98.238 to 
be used for the purposes of this reporting requirement. For gathering 
pipelines, the EPA is proposing a definition of ``gathering pipeline 
site'' to specify that it is all the gathering pipelines at the 
facility within a single state. In addition, the EPA has received 
information from stakeholders noting that there are facility 
configurations that would not clearly fit within the proposed 
definition for ``gathering compressor station'' or ``centralized oil 
production site,'' including, but not limited to, booster stations, 
dehydration facilities, and treating facilities.\64\ The EPA is 
proposing to provide the ``other fence-line site'' site type to cover 
these types of sites. For gathering pipelines, the EPA is proposing 
within the definition of ``gathering and boosting site'' that a 
gathering pipeline site is all the gathering pipelines at the facility 
within a single state. For the ``location'' reported for each gathering 
and boosting site, the EPA is proposing that reporters would provide 
the representative latitude and longitude coordinates where the site 
type is a gathering compressor station, centralized oil production site 
or other fence-line facility, and the state where the site type is a 
gathering pipeline.
---------------------------------------------------------------------------

    \64\ Letter from Angie Burckhalter, The Petroleum Alliance of 
Oklahoma, to Administrator Michael S. Regan, U.S. EPA, Re: Docket 
Id. No. EPA-HQ-OAR-2019-0424; Revisions and Confidentiality 
Determinations for Data Elements Under the Greenhouse Gas Reporting 
Rule. October 6, 2022. Available in the docket for this rulemaking, 
Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    For the emission source types in the Onshore Petroleum and Natural 
Gas Production industry segment directly related to wells that 
currently report by sub-basin (i.e., well venting for liquids 
unloading, completions and workovers with hydraulic fracturing, 
completions and workovers without hydraulic fracturing, and associated 
gas venting or flaring) or by calculation method and use of a flare 
(i.e., well testing), we are proposing to require reporting of 
emissions and activity data for each individual well instead of in the 
current aggregations (e.g., by sub-basin). Where the current emission 
source-level provisions of 40 CFR 98.236 for the Onshore Petroleum and 
Natural Gas Production industry segment and the Onshore Petroleum and 
Natural Gas Gathering and Boosting industry segment require reporting 
at either the facility or the sub-basin level (other than the emission 
source types directly related to wells), we are proposing to no longer 
require reporting at the sub-basin level and instead require reporters 
to provide emissions and activity data by well-pad ID or gathering and 
boosting site ID for each facility. For emission source types that 
report at the unit level (e.g., AGRs, dehydrators, and flares), we are 
proposing to maintain reporting at that level but are proposing to also 
require the reporter to identify the well-pad ID or gathering and 
boosting site ID. This proposed requirement would take the place of the 
reporting of the county or sub-basin ID, if applicable. The EPA is 
seeking comment as to whether the lower levels of aggregation of 
activity data to the site level within the Onshore Petroleum and 
Natural Gas Production and Onshore Petroleum and Natural Gas Gathering 
and Boosting segments would cause data elements that are currently not 
entitled to confidential treatment (i.e., data elements that are not 
considered ``emissions data'' as described in section V of this 
preamble) to become entitled to confidential treatment. See section V 
of this preamble for further information about the proposed 
confidentiality determinations and reporting determinations for inputs 
to emissions equations.
    In addition, the EPA is proposing revisions to the language of 
existing reporting requirements and proposing to require specific 
throughput data elements related to wells permanently shut-in and 
plugged during the reporting year. First, the EPA is proposing to 
revise the phrase ``permanently taken out of production (i.e., plugged 
and abandoned)'' in proposed 40 CFR 98.236(aa)(1)(ii)(D) and (H) to 
read ``permanently shut-in and plugged'' for consistency with the 
language used in CAA section 136. This proposed amendment is for 
consistency in language rather than any expected difference in the 
wells to be reported or the interpretation of the terms. Second, the 
EPA is proposing to require reporting of the quantities of natural gas, 
crude oil and condensate produced that is sent to sale during the 
reporting year for each well that is permanently shut-in and plugged in 
40 CFR 98.236(aa)(1)(iii)(C) through (E) for the Onshore Petroleum and 
Natural Gas Production industry segment and 40 CFR 98.236(aa)(2)(iv) 
through (vi) for the Offshore Petroleum and Natural Gas Production 
industry segment. Third, for each Onshore Petroleum and Natural Gas 
Production well-pad with a well that was permanently shut-in and 
plugged the EPA is proposing to require reporting of the total 
quantities of natural gas, crude oil and condensate produced that is 
sent to sale in the reporting year for the wells on that well-pad. 
These proposed data elements, if finalized, are anticipated to be 
useful in the future evaluation of the plugged well provisions of CAA 
section 136(f)(7).

E. Natural Gas Pneumatic Device Venting and Natural Gas Driven 
Pneumatic Pump Venting

    Subpart W currently requires calculation of GHG emissions from 
natural gas pneumatic device venting (existing 40 CFR 98.233(a)) and 
natural gas driven pneumatic pump venting (existing 40 CFR 98.233(c)) 
using default population emission factors multiplied by the number of 
devices and the average time those devices are ``in-service'' (i.e., 
supplied with natural gas). In our 2022 Proposed Rule, we proposed to 
update the population emission factors for pneumatic devices based on 
recent study data. Consistent with section II.B of this preamble, we 
are proposing calculation methods based on measurements and leak 
screening for each source type as described in this section. Under the 
proposed calculation methods for pneumatic devices, the existing 
default population emission factors for intermittent bleed natural gas 
pneumatic devices would no longer be applicable and the default 
population emission factors for continuous bleed natural gas pneumatic 
devices would only be applicable for the leak screening method 
(proposed Calculation Method 3).
1. Direct Measurement Methods for Natural Gas Pneumatic Devices and 
Natural Gas Pneumatic Pumps
    Consistent with section II.B of this preamble, we are proposing to 
provide a calculation method based on direct measurement of natural gas 
supplied to pneumatic devices in proposed 40 CFR 98.233(a)(1) and 
supplied to pneumatic pumps in proposed 40 CFR 98.233(c)(1). We are 
proposing that, if a flow monitoring device is installed on the natural 
gas supply line dedicated to one or a combination of pneumatic devices, 
or the natural gas supply line dedicated to one or more pneumatic 
pumps, that are vented directly to the atmosphere, then the measured 
flow must be used to calculate the emissions from the pneumatic devices 
or pneumatic pumps, as applicable, downstream of that flow monitor. We 
are also proposing to require this calculation method when the flow is 
continuously measured in a supply line that serves both pneumatic 
devices and natural gas driven pneumatic pumps that are all vented 
directly to the atmosphere. The

[[Page 50311]]

flow monitor would be required to meet the requirements specified in 
existing 40 CFR 98.234(b). We are proposing to denote this natural gas 
supply measurement as Calculation Method 1 for pneumatic devices and 
pneumatic pumps. We are also proposing to add reporting requirements 
for each measurement location to report the type of flow monitor, the 
number of each type of pneumatic device being monitored at that 
location, and an indication of whether any natural gas driven pneumatic 
pumps are also monitored at that location, and the CH4 and 
CO2 emissions calculated for that monitoring location in 
proposed 40 CFR 98.236(b)(3). Comparable reporting requirements for 
natural gas driven pneumatic pumps are specified in proposed 40 CFR 
98.236(c)(3).
    For natural gas pneumatic devices that do not have or do not elect 
to install a flow meter dedicated to measuring the flow of natural gas 
supplied to one or a combination of pneumatic devices that are vented 
directly to the atmosphere, we are proposing in 40 CFR 98.233(a)(2) to 
allow reporters to measure the natural gas emissions from each 
pneumatic device vented directly to the atmosphere at the well-pad, 
gathering and boosting site, or facility, as applicable, using one of 
the measurement methods in existing 40 CFR 98.234(b) through (d). We 
are proposing to refer to the vent measurement method as Calculation 
Method 2 for pneumatic devices. For natural gas driven pneumatic pumps 
that do not have or do not elect to install a flow meter dedicated to 
measuring the flow of natural gas supplied to one or a combination of 
pneumatic pumps vented directly to the atmosphere, we are proposing to 
require that the reporter either measure the natural gas emissions from 
each such pneumatic pump at the facility as specified in proposed 40 
CFR 98.233(c)(2) or calculate emissions from each such pneumatic pump 
at the facility using the default emissions factor as specified in 
proposed 40 CFR 98.233(c)(3). The proposed measurement option is 
referred to as Calculation Method 2 for pumps and is similar to the 
proposed Calculation Method 2 for pneumatic devices. The proposed 
pneumatic pump method based on a default emission factor is the same as 
the methodology in 40 CFR 98.233(c) of the existing rule and is 
referred to as Calculation Method 3 in the proposed rule.
    If Calculation Method 2 is elected for pneumatic devices, we are 
proposing that all pneumatic devices that are vented directly to the 
atmosphere present at the facility (except those for which natural gas 
supply is measured according to Calculation Method 1) would have to be 
measured at regular intervals and that for a well-pad, gathering and 
boosting site, or facility, as applicable, selected to be measured that 
year, all pneumatic devices that vent to the atmosphere must be 
measured according to Calculation Method 2 (except those for which 
natural gas supply is measured according to Calculation Method 1). For 
facilities in the Onshore Petroleum and Natural Gas Production and in 
the Onshore Petroleum and Natural Gas Gathering and Boosting industry 
segments, a complete cycle of measurements would be required to be 
completed in no more than 5 years, and we are proposing that the number 
of pneumatic devices measured each year be approximately equal. We 
selected a 5-year interval for Onshore Petroleum and Natural Gas 
Production and Onshore Petroleum and Natural Gas Gathering and Boosting 
facilities because of the high number of devices at these facilities 
and the time needed to measure all natural gas pneumatic devices. 
Additionally, we are proposing that when measurements are conducted at 
a particular well-pad or gathering and boosting site, all pneumatic 
devices at that well-pad or gathering and boosting site must be 
measured in the same year. This would help enhance the 
representativeness of the measurement data.
    For facilities in the Onshore Natural Gas Processing, Onshore 
Natural Gas Transmission Compression, Underground Natural Gas Storage, 
and Natural Gas Distribution industry segments, we are proposing the 
measurement interval to be dependent on the number of devices at the 
facility. For facilities with 25 or fewer natural gas pneumatic 
devices, we are proposing measurement of all devices annually. For 
facilities with 26 to 50 devices, we are proposing measurement of all 
devices in a two-year period. The proposed interval period increases 
with every 25 devices, until reaching a maximum cycle time of 5 years 
for facilities with 101 or more natural gas pneumatic devices that are 
vented directly to the atmosphere. The 25-device increment was selected 
because we estimated that this would be the typical number of devices 
that could be measured following the proposed methods in an 8-hour 
period.
    Under Calculation Method 2, we are proposing that each pneumatic 
device vent measurement, except for isolation valve actuators, would be 
conducted for a minimum of 15 minutes; measurements for pneumatic 
isolation valve actuators would be conducted for a minimum of 5 
minutes. We are proposing a reduced monitoring duration for isolation 
valve actuators specifically because these devices actuate very 
infrequently, and the monitoring is targeted to confirm the valve 
actuators are not malfunctioning (i.e., emitting when not actuating) 
rather than to develop an average emission rate considering some 
limited number of actuations. We are proposing that, if there is a 
measurable flow during the measurement period, the average flow rate 
measured during the measurement period would be used as the average 
flow rate for that device and multiplied by the total hours the device 
is in service (i.e., supplied with natural gas) to calculate annual 
emissions (by pneumatic device type). For continuous bleed devices, if 
there is no measurable flow rate (i.e., flow rate is below the method 
detection limit), we are proposing to require reporters to confirm the 
device is in service when measured and that the device type is 
correctly characterized. Once confirmed, we are proposing that the 
device must be retested (if designated as a high bleed device) or the 
manufacturer's steady state bleed rate must be used (if designated as a 
low bleed device) to estimate the device's emissions. For intermittent 
bleed devices, the lack of any emissions during a 5-minute or 15-minute 
period, as applicable, would indicate that the device did not actuate 
and that the device is seating correctly when not actuating. As such, 
we are proposing that engineering calculations would be made to 
estimate emissions per activation and that company records or 
engineering estimates would be used to assess the number of actuations 
per year to calculate the emissions from that device for the reporting 
year.
    Under Calculation Method 2, if vent measurements are made over 
several years, we are proposing that all measurements made within a 
multi-year measurement would be used to calculate a facility-specific 
emission factor by device type (continuous high bleed, continuous low 
bleed, and intermittent bleed). The emissions measurements for the 
pneumatic device vents measured during the reporting year would be used 
directly for those devices. We are proposing that reporters would use 
the facility-specific emission factor developed from the cycle of 
measurements times the number of devices (by type) at the facility that 
were not measured during the reporting year to calculate the emissions 
from the

[[Page 50312]]

pneumatic devices that were not measured during the reporting year.
    Reporters using proposed Calculation Method 2 would report for each 
well-pad, gathering and boosting site, or facility, as applicable, the 
total number of natural gas pneumatic devices by type, the number of 
years in the measurement cycle, the number of devices by measured in 
the reporting year, the value of the emissions factor for the reporting 
year as calculated using equation W-1A and the devices upon which the 
emission factor is based, the average time the devices were in service 
(i.e., supplied with natural gas) during the calendar year, and the GHG 
emissions for each type of natural gas pneumatic device.
    We are proposing calculation and reporting requirements for 
Calculation Method 2 for pneumatic pumps in proposed 40 CFR 
98.233(c)(2) and proposed 40 CFR 98.236(c)(4), respectively, that are 
similar to the proposed Calculation Method 2 requirements for pneumatic 
devices, with differences described as follows. First, only facilities 
in the Onshore Petroleum and Natural Gas Production and in the Onshore 
Petroleum and Natural Gas Gathering and Boosting industry segments are 
currently required to report emissions from pneumatic pumps and based 
on the analysis performed as described in section III.C.1 of this 
preamble and documented in the subpart W TSD, we are not proposing to 
add this source type for any other industry segment. Therefore, 
proposed Calculation Method 2 for pneumatic pumps only includes the 
provisions for a 5-year cycle and does not include the measurement 
cycles for other industry segments. The 5-year cycle is being proposed 
for natural gas driven pneumatic pumps for the same reason that it is 
being proposed for pneumatic devices (i.e., a few facilities have a 
high number of pumps, and the time needed to measure all of the pumps 
in a single year would be excessive). To minimize the burden while 
still collecting sufficient data to calculate sufficiently accurate 
emissions, we are proposing an approach similar to the current approach 
that Natural Gas Distribution facilities may use to conduct equipment 
leak surveys. Second, the proposal specifies that reporters would 
measure for a minimum of 5 minutes while liquid is continuously being 
pumped. Five minutes is currently specified for other emission 
measurements in the rule (e.g., leak rates from transmission storage 
tank vents in existing 40 CFR 98.233(k)(2), which are condensate 
storage tank vents in this proposal). Typically, emissions from pumps 
are expected to be greater than leak rates from transmission storage 
tank leaks. Thus, it is expected that a sufficient volume of sample 
would be collected in 5 minutes of pump operation to be measurable with 
sufficient accuracy. Third, we are proposing that the emissions would 
be calculated as the product of the measured natural gas flow rate and 
the number of hours the pneumatic pump was pumping. Under proposed 
Calculation Method 2 for pneumatic pumps, proposed reporting data 
elements in 40 CFR 98.236(c)(4) per well-pad or gathering and boosting 
site would include the number of years in the measurement cycle; an 
indication of whether emissions were measured or calculated; the 
primary measurement method (when emissions were measured); the value of 
the calculated emissions factor, the total number of pumps measured and 
used in calculating the emission factor, the number of pumps that 
vented to atmosphere, and the estimated average number of hours per 
year that the vented pumps were pumping liquid (when the emissions were 
calculated); the total measured CO2 and CH4 
emissions; and the total calculated CO2 and CH4 
emissions.
    We request comment on whether the option of up to a 5-year cycle is 
appropriate for all facilities in the onshore production and gathering 
and boosting industry segments. If a shorter time frame would be 
appropriate, we request comment on how long the maximum cycle should be 
and why that length of time would be adequate. We also request comment 
on the proposed sampling period of 5 minutes. If a longer test period 
would be needed or a shorter time period would be sufficient to collect 
representative emissions data, we request comment on what time period 
would be appropriate and the reasons why that test time would be 
appropriate. Finally, we request comment on suggestions for other 
approaches to emissions measurement that might be more effective and 
better achieve the goal of obtaining accurate vented emissions data 
from natural gas driven pneumatic pumps.
2. Intermittent Bleed Pneumatic Device Surveys
    As part of our review to characterize pneumatic device emissions, 
we found a significant difference in the emissions from intermittent 
bleed pneumatic devices that appeared to be functioning as intended 
(short, small releases during device actuation) and those that appeared 
to be malfunctioning (continuously emitting or exhibiting large or 
prolonged releases upon actuation). For natural gas intermittent bleed 
pneumatic devices, it is possible to identify malfunctioning devices 
through routine monitoring using OGI or other technologies. As noted in 
the introduction to section II of this preamble, the EPA recently 
proposed NSPS OOOOb and EG OOOOc for oil and natural gas sources. Under 
the proposed standards in NSPS OOOOb and the proposed presumptive 
standards in EG OOOOc (which would inform the state plans or, if 
necessary, the Federal plan in 40 CFR part 62), nearly all covered 
pneumatic devices (continuous bleed and intermittent vent) would be 
required to have a CH4 (and, for NSPS OOOOb only, VOC) 
emission rate of zero. The only proposed exception would be for 
pneumatic devices in Alaska at locations where on-site power is not 
available, in which case owners and operators would be required to use 
low bleed pneumatic devices in place of high bleed pneumatic devices 
(unless a high bleed device is needed for a functional need such as 
safety), and to verify that any intermittent bleed pneumatic devices 
operate such that they do not vent when idle by monitoring these 
devices during the fugitive emissions survey.
    We envision relatively few intermittent bleed pneumatic devices 
that vent GHG to the atmosphere under the proposed zero-emission 
standard and presumptive standard for these pneumatic devices, 
compliance with which would require the use of technology to achieve 
the zero-emission standard. As noted in the previous paragraph, we 
proposed in NSPS OOOOb and EG OOOOc to require periodic monitoring of 
those few intermittent bleed pneumatic devices in Alaska. In addition, 
as noted in section II of this preamble, the proposed amendments that 
would apply to sources subject to the NSPS OOOOb and approved state 
plans or applicable Federal plan in 40 CFR part 62 would not become 
effective for individual reporters unless and until their emission 
sources become subject to and are required to comply with either the 
final NSPS OOOOb or an approved state plan or applicable Federal plan 
in 40 CFR part 62. Prior to that time, a reporter may elect to conduct 
inspections or surveys of their intermittent bleed pneumatic devices. 
Therefore, the EPA is proposing amendments to subpart W to provide an 
alternative methodology to calculate emissions from intermittent bleed 
pneumatic devices based on the results of inspections or surveys, 
consistent with section II.B of this

[[Page 50313]]

preamble. Specifically, we are proposing to provide in 40 CFR 
98.233(a)(3) an alternative calculation methodology for facilities that 
monitor for malfunctioning intermittent bleed pneumatic devices 
analogous to a ``leaker factor'' approach used for equipment leaks. We 
included this ``leaker factor'' approach in the 2022 Proposed Rule; 
however, we are proposing revisions to the ``leaker factors'' terms 
included in the calculation approach using peer reviewed study data. We 
are proposing to refer to this monitoring/leaker factor approach as 
Calculation Method 3 for pneumatic devices.
    If Calculation Method 3 is elected, we are proposing that all 
intermittent bleed pneumatic devices that vent to the atmosphere at the 
well-pad, gathering and boosting site, or facility, as applicable, 
would be required to be monitored according to the leak detection 
methods in 40 CFR 98.234(a)(1) through (3), but with a monitoring 
duration of at least 2 minutes or until a malfunction is identified. 
Based on our review of the measurement studies that identified 
malfunctioning intermittent bleed devices, we found that most 
malfunctioning devices could be identified using a 2-minute monitoring 
duration, but malfunctioning devices could not be identified 
effectively using a typical ``leak survey'' monitoring duration, which 
is on the order of a few seconds. However, if a pneumatic device is 
observed to be malfunctioning in the first minute, there is no need to 
continue to monitor that device. Therefore, we are proposing that a 
minimum monitoring duration of 2 minutes or until a malfunction is 
identified be used for the purpose of identifying malfunctioning 
intermittent bleed pneumatic controllers.
    Under Calculation Method 3, we are proposing that all intermittent 
bleed pneumatic devices that are vented directly to the atmosphere 
present at the facility (except those for which natural gas supply is 
measured according to Calculation Method 1) would have to be monitored 
to identify malfunctioning devices at regular intervals, with a 
complete cycle of measurements being completed in no more than 5 years 
for facilities in the Onshore Petroleum and Natural Gas Production and 
in the Onshore Petroleum and Natural Gas Gathering and Boosting 
industry segments. Additionally, we are proposing that when monitoring 
is conducted at a particular well-pad or gathering and boosting site, 
all pneumatic devices at that well-pad or gathering and boosting site 
must be monitored in the same year. This would help enhance the 
representativeness of the measurement data. For facilities in the 
Onshore Natural Gas Processing, Onshore Natural Gas Transmission 
Compression, Underground Natural Gas Storage, and Natural Gas 
Distribution industry segments, we are proposing the monitoring 
interval to be dependent on the number of intermittent bleed pneumatic 
devices at the facility. For facilities with 100 or fewer natural gas 
intermittent bleed pneumatic devices, we are proposing monitoring of 
all devices annually. For facilities with 101 to 200 devices, we are 
proposing measurement of all devices in a 2-year period. The proposed 
interval period increases with every 100 devices, until reaching a 
maximum cycle time of 5 years for facilities with 401 or more natural 
gas pneumatic devices vented directly to the atmosphere. The 100-device 
increment was selected because we estimated that this would be the 
typical number of devices that could be monitored following the 
proposed methods in an 8-hour period. For all industry segments, we are 
proposing that, if you elect to monitor your pneumatic devices over 
multiple years, you must monitor approximately the same number of 
devices each year.
    Under Calculation Method 3, if a ``leak'' is observed from the 
intermittent bleed pneumatic device for more than 5 seconds during a 
device actuation, then the device is considered to be 
``malfunctioning'' and the malfunctioning device emission factor 
(similar to a leaker emission factor) would be applied to that device. 
Emissions from intermittent bleed pneumatic devices that were not 
observed to be malfunctioning would be calculated based on the default 
emission factor for ``properly functioning'' intermittent bleed 
pneumatic devices. We are proposing in the definition of the variable 
``Tz'' in proposed equation W-1C that the time that a device 
is assumed to be malfunctioning would be determined following the same 
procedures as the determination of the duration of equipment leaks 
identified during a leak survey conducted under 40 CFR 98.233(q) (see 
the variable ``Tp,z'' in equation W-30 for equipment leaks). 
For example, if only one survey of intermittent bleed natural gas 
pneumatic devices is conducted during the reporting year, then any 
device found to be malfunctioning during the survey would be required 
to be assumed to be malfunctioning for the entire year.
    If a complete survey of intermittent bleed pneumatic devices is 
completed over multiple years, we are proposing equation W-1D be used 
to calculate the emissions. As proposed, this equation uses the ratio 
of the number of intermittent bleed devices identified to be 
malfunctioning during the current reporting year to the total number of 
intermittent bleed devices monitored during the reporting year to 
estimate the number of malfunctioning and properly functioning 
intermittent bleed devices for the intermittent bleed devices that were 
not monitored during the reporting year.
    Under Calculation Method 3, we are proposing that emissions from 
continuous bleed pneumatic controllers (other than those for which the 
natural gas supply flow is measured as specified in Calculation Method 
1) would be determined either by annually measuring the emissions from 
the pneumatic device vent following the methods provided in Calculation 
Method 2 or by using applicable default population emission factors for 
continuous high bleed and continuous low bleed pneumatic devices.
    Reporters using proposed Calculation Method 3 would report for each 
the well-pad, gathering and boosting site, or facility, as applicable, 
the total number of natural gas pneumatic devices by type, the method 
used to estimate emissions from continuous bleed natural gas pneumatic 
devices, the frequency of monitoring for intermittent devices, the 
number of years in a monitoring cycle, the number of devices at the 
facility, the number monitored in the reporting year, the number found 
to be malfunctioning, the average time the malfunctioning devices were 
assumed to be malfunctioning under proposed 40 CFR 98.236(b)(5), the 
average time that devices that were monitored but were not detected as 
malfunctioning year were in service (i.e., supplied with natural gas) 
during the calendar year, and the GHG emissions for each type of 
natural gas pneumatic device.
    For more information regarding this proposed alternative 
calculation methodology for natural gas intermittent bleed pneumatic 
devices, see the subpart W TSD, available in the docket for this 
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
3. Revisions to Emission Factors
    As noted in section III.E of this preamble, subpart W currently 
requires calculation of GHG emissions from natural gas pneumatic device 
venting using default population emission factors multiplied by the 
number of devices and the average time those devices are ``in-service'' 
(i.e., supplied with natural gas). Correspondingly, the current default 
population factors for natural gas pneumatic devices were

[[Page 50314]]

developed by taking both periods of actuation and periods without 
actuation into account. Subpart W provides two sets of pneumatic device 
emission factors, one for devices in the Onshore Petroleum and Natural 
Gas Production and Onshore Petroleum and Natural Gas Gathering and 
Boosting industry segments and one for the Onshore Natural Gas 
Transmission Compression and Underground Natural Gas Storage industry 
segments. Each set of emission factors consists of emission factors for 
three different types of natural gas pneumatic devices: continuous low 
bleed devices, continuous high bleed devices, and intermittent bleed 
devices.\65\
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    \65\ The development of the current emission factors for natural 
gas pneumatic devices is described in Greenhouse Gas Emissions 
Reporting from the Petroleum And Natural Gas Industry: Background 
Technical Support Document, U.S. EPA, 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 become aware of several studies on emissions from 
natural gas pneumatic device vents since subpart W was first 
promulgated. For example, in April 2015, the EPA reviewed three 
recently published studies on emissions from pneumatic devices (also 
referred to as ``pneumatic controllers'' within the studies as well as 
in NSPS OOOOa, proposed NSPS OOOOb, and proposed EG OOOOc) at onshore 
production facilities and evaluated those studies for use in the U.S. 
GHG Inventory.\66\ As part of this proposed rulemaking, we have 
reviewed these and other available studies to evaluate the potential 
for revisions to the natural gas pneumatic device emission factors in 
subpart W. As part of our review, we found there are significantly more 
data available now by which to characterize pneumatic device emissions. 
Therefore, consistent with section II.B of this preamble, we are 
proposing to amend the emission factors for all industry segments for 
which emissions from natural gas pneumatic device vents must be 
calculated.
---------------------------------------------------------------------------

    \66\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and 
Sinks: Potential Revisions to Pneumatic Controller Emissions 
Estimate (Production Segment). April 2015. Available at https://www.epa.gov/sites/production/files/2015-12/documents/ng-petro-inv-improvement-pneumatic-controllers-4-10-2015.pdf.
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    Under Calculation Method 3 for pneumatic devices, default 
population emission factors can be used for continuous bleed devices. 
Therefore, for continuous low bleed pneumatic devices, we are proposing 
an emission factor of 6.8 standard cubic feet per hour per device (scf/
hr/device) based on the available measurement data, which considers 
devices that may be malfunctioning (i.e., having higher steady state 
bleed rates than specified by the manufacturer) for all applicable 
industry segments in proposed Table W-1. For continuous high bleed 
pneumatic devices, we are proposing different population emission 
factors depending on the applicable industry segment. For facilities in 
the Onshore Petroleum and Natural Gas Production and in the Onshore 
Petroleum and Natural Gas Gathering and Boosting industry segments, we 
are proposing an emission factor of 21 scf/hr/device for continuous 
high bleed devices in existing Table W-1A (proposed Table W-1) based on 
study data for these industry segments. For facilities in the Onshore 
Natural Gas Processing, Onshore Natural Gas Transmission Compression, 
Underground Natural Gas Storage, and Natural Gas Distribution industry 
segments, we are proposing an emission factor of 30 scf/hr/device for 
continuous high bleed devices in proposed Table W-1 based on study data 
from transmission compression stations. These proposed continuous bleed 
emission factors consider emissions from pneumatic devices based on 
measurements while the devices are in service, not just actuating.
    Because none of the three proposed calculation methods described in 
section III.E.1 and 2 of this preamble would allow the use of the 
current default population emission factor methodology for intermittent 
bleed pneumatic devices, we are proposing to remove the population 
emission factors for intermittent bleed pneumatic devices from existing 
Tables W-1A, W-3B, and W-4B and not include them in proposed Table W-1. 
The EPA requests comment on whether the EPA should instead retain the 
use of default population emission factors as an alternative 
calculation methodology (as Calculation Method 4) for sites, i.e. 
include in the final rule an option for sites to not conduct 
measurements or monitor intermittent bleed devices. If the population 
emission factor calculation method is retained, the EPA requests 
comment on the appropriate intermittent bleed pneumatic device emission 
factors to include in the final rule. Based on our review of the 
recently published pneumatic device study data, we would consider 
revising the intermittent bleed pneumatic device emission factor for 
facilities in the Onshore Petroleum and Natural Gas Production and in 
the Onshore Petroleum and Natural Gas Gathering and Boosting industry 
segments to 8.8 scf/hr/device. This emission factor considers emissions 
from pneumatic devices based on measurements while the devices are in 
service, not just actuating, and may include emissions from devices 
that were malfunctioning during the time of the measurement. We have 
limited new data specific to intermittent bleed pneumatic devices for 
other industry segments. We would consider retaining the intermittent 
bleed pneumatic device emission factor of 2.3 scf/hr/device for 
facilities in other applicable industry segments; however, this 
emission factor is based on engineering calculations and would likely 
underestimate emissions from devices that are malfunctioning (e.g., 
bleeding continuously or bleeding more than expected during an 
actuation). The EPA requests comment and supporting data regarding 
potential revisions to the intermittent bleed pneumatic device 
population emission factors, if the use of population emission factors 
as a calculation methodology is retained.
    For more information regarding this review and development of the 
proposed emission factors, see the subpart W TSD, available in the 
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    Finally, we note that we are not proposing to revise or remove the 
default population emission factor in existing Table W-1A (proposed 
Table W-1) for natural gas driven pneumatic pumps. Reporters that do 
not have or elect to install a flow meter on the natural gas supply 
line dedicated to any one or more natural gas driven pneumatic pumps 
and that do not elect to measure the volumetric flow rate of emissions 
from all the natural gas driven pneumatic pumps vented directly to the 
atmosphere at a well-pad or gathering and boosting site would be 
required to continue using the current default population emission 
factor for pneumatic pumps vented directly to the atmosphere, as 
proposed Calculation Method 3. The existing emission factor is based on 
the average stroke volumes and frequencies for a range of typical 
pumps.\67\ In contrast to some other equipment for which emission 
factors are currently used to calculate emissions (e.g., intermittent 
bleed pneumatic devices), the emissions per unit of operating time for 
a given pump are not expected to vary significantly due to malfunctions 
as the pump ages. As such, we expect the natural gas

[[Page 50315]]

driven pneumatic pump emission factor to provide an acceptably accurate 
estimate of the average hourly emissions from natural gas driven 
pneumatic pumps. For this reason, we are proposing to retain the 
emission factor calculation method for this source type.
---------------------------------------------------------------------------

    \67\ Methane Emissions from the Natural Gas Industry, Volume 13: 
Chemical Injection Pumps, Final Report. GRI-94/0257.30 and EPA-600/
R-96-080m. 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.
---------------------------------------------------------------------------

    In the 2022 Proposed Rule we proposed clarifying the definition of 
the time parameter in equation W-2 of the current rule. The current 
definition is the ``average estimated number of hours in the operating 
year that the pumps were operational.'' We proposed changing the word 
``operational'' to ``in service (i.e., supplied with natural gas).'' 
This change was proposed to be consistent with the proposed change to 
the time term in equation W-1 for pneumatic devices. This change was 
proposed for the pneumatic device equation because the specified 
emission factors were developed based on emission measurement tests 
conducted over periods when the devices were actuating as well as 
periods when they were not actuating (i.e., theoretical steady-state 
continuous bleeding, or for intermittent devices, when they 
theoretically were not emitting). However, after further review, we 
determined that the current emission factor for pneumatic pumps was 
developed based on observations of pump operation at several production 
facilities (e.g., stroke rates and frequency of pump use) and pump 
manufacturer data (e.g., gas consumption per volume of chemical pumped, 
plunger diameter, and stroke length) for a variety of chemical 
injection pumps.\68\ This means the emission factor represents 
emissions when pumps are actuating, or, in other words, when they are 
actively pumping liquid. Thus, we are now proposing to clarify the 
definition of the term ``T'' in current equation W-2 (equation W-2B in 
proposed 40 CFR 98.233(c)) by replacing the word ``operational'' with 
``pumping liquid.'' We request comment on the potential for natural gas 
to leak through a pump to the atmosphere when the pump is not actively 
pumping liquid and the mechanism for such leakage.
---------------------------------------------------------------------------

    \68\ Methane Emissions from the Natural Gas Industry, Volume 13: 
Chemical Injection Pumps, Final Report. GRI-94/0257.30 and EPA-600/
R-96-080m. 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.
---------------------------------------------------------------------------

4. Hours of Operation of Natural Gas Pneumatic Devices
    In correspondence with the EPA via e-GGRT, some reporters have 
indicated that they are interpreting the term ``operational'' in the 
definition of variable ``Tt'' in equation W-1 in 40 CFR 
98.233(a) and the term ``operating'' in the reporting requirements in 
40 CFR 98.236(b)(2) differently than the EPA intended. Both the current 
emission factors and the proposed calculation methodologies described 
in sections III.E.1 through III.E.3 of this preamble for natural gas 
pneumatic devices were developed by taking both periods of actuation 
and periods without actuation into account; \69\ in other words, the 
emission factors are population emission factors considering all times 
when the device was connected to natural gas supply line. To calculate 
emissions accurately using the existing population emission factor, 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). Similarly, based on the calculation methodology for the site-
specific population emission factor in Calculation Method 2 or for the 
leaker emission factor approach proposed in Calculation Method 3, 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) must be used in the calculation, Therefore, 
consistent with section II.D of this preamble, we are proposing to 
revise the definition of variable ``Tt'' 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)(4), and (b)(5)(i)(C)(2) to use 
the term ``in service (i.e., supplied with natural gas)'' rather than 
``operational'' or ``operating,'' to clarify the original and current 
intended meaning of that variable and term. We are also proposing to 
use this ``in service'' language for the time variables in the newly 
proposed equations W-1C and W-1D for the leaker factor approach for 
intermittent bleed pneumatic devices under Calculation Method 3.
---------------------------------------------------------------------------

    \69\ As noted previously, the development of the current 
emission factors for natural gas pneumatic devices is described in 
Greenhouse Gas Emissions Reporting from the Petroleum And Natural 
Gas Industry: Background Technical Support Document, U.S. EPA, 
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.
---------------------------------------------------------------------------

5. Natural Gas Pneumatic Devices and Natural Gas Driven Pneumatic Pumps 
Routed to Control
    We understand that emissions from some natural gas pneumatic 
devices and/or natural gas driven pneumatic pumps are routed to control 
(i.e., a flare, combustion unit, or vapor recovery system). The 
population emission factor is based on natural gas vented directly to 
the atmosphere from these pneumatic devices/pumps and does not 
accurately reflect emissions from controlled pneumatic devices/pumps. 
Therefore, consistent with section II.B of this preamble, we are 
proposing to revise 40 CFR 98.233(a) and (c) to clarify requirements 
for calculating emissions from natural gas pneumatic devices and 
natural gas driven pneumatic pumps, respectively, that are vented 
directly to the atmosphere versus pneumatic devices/pumps that are 
routed to control, consistent with the intent of the current rule. We 
are proposing revisions to 40 CFR 98.233(a) and (c) to clarify that the 
existing population emission factor calculation methodology is intended 
to apply only to pneumatic devices/pumps vented directly to the 
atmosphere. The proposed new calculation methodologies described in 
sections III.E.1 and 2 of this preamble also specify that they apply 
only to pneumatic devices/pumps vented directly to the atmosphere.
    We are proposing that flared emissions from natural gas pneumatic 
devices or pumps are not required to be calculated and reported 
separately from other flared emissions. We are proposing to specify 
that instead emission streams from natural gas pneumatic devices or 
pumps that are routed to flares are required to be included in the 
calculation of total emissions from the flare according to the 
procedures in 40 CFR 98.233(n) and reported as part of the total flare 
stack emissions according to the procedures in 40 CFR 98.236(n), in the 
same manner as emission streams from other source types that are routed 
to the flare. Similarly, we are proposing that emissions from natural 
gas pneumatic devices or pumps that are routed to a combustion unit are 
required to be combined with other streams of the same fuel type and 
used to calculate total emissions from the combustion unit as specified 
in 40 CFR 98.233(z) and reported as part of the total emissions from 
the combustion unit as specified in 40 CFR 98.236(z). We are also 
proposing reporters would not calculate or report emissions from 
natural gas pneumatic devices or pumps if the emissions are routed to 
vapor

[[Page 50316]]

recovery and are not subsequently routed to a combustion device (e.g., 
are routed back to process or sales).
    We are also proposing to require in proposed 40 CFR 98.236(b)(2) 
and 98.236(c)(2) reporting of the total number of continuous low bleed, 
continuous high bleed, and intermittent bleed natural gas pneumatic 
devices and the total number of natural gas driven pneumatic pumps at 
the site (regardless of vent disposition), the number of these devices/
pumps that are vented to the atmosphere for at least a portion of the 
year, and the number of these devices/pumps that are routed to control 
for at least a portion of the year (which includes natural gas 
pneumatic devices/pumps routed to a flare, combustion unit, or vapor 
recovery system). The total count of pneumatic devices or pumps is a 
proposed reporting element because the total count may not always be 
equal to the sum of the other two counts. For example, a reporter that 
switches from atmospheric venting to routing to control during a year 
for a particular pneumatic device or pump would include that pneumatic 
device or pump in both the count of devices or pumps that vent directly 
to atmosphere and in the count of devices or pumps that are routed to 
flares. However, that pneumatic device or pump would only be counted 
once towards the total number of pneumatic devices or pumps, allowing 
us to discern the number of devices or pumps that exclusively vent or 
exclusively route to control. The number of pneumatic devices or pumps 
vented directly to the atmosphere would be used in the verification of 
annual reports to the GHGRP. The total count of pneumatic devices or 
pumps at the facility and the number of pneumatic devices or pumps that 
are routed to a flare, combustion, or vapor recovery would provide the 
EPA with information to better characterize emissions from this source, 
including how many pneumatic devices or pumps are controlled across the 
industry and how the use of controls for pneumatic pumps changes across 
multiple years.

F. Acid Gas Removal Unit Vents

1. Reporting of Methane Emissions From Acid Gas Removal Units
    Reporters currently report only CO2 emissions from AGR 
vents using one of the four calculation methodologies provided in 40 
CFR 98.233(d). In the 2010 subpart W TSD, the EPA explained that 
``CH4 emissions from AGR vents are insignificant, 0.06 
percent of the total volume of CO2 and CH4 
emissions,'' leading to the decision at that time not to require 
reporting of CH4 emissions from AGR vents.\70\ However, as 
described in more detail later in this section, both the number and 
size of the AGRs reported to the GHGRP in recent years are greater than 
the values used in that initial assessment, so current nationwide 
CH4 emissions are likely greater than estimated in the 2010 
subpart W TSD.
---------------------------------------------------------------------------

    \70\ Greenhouse Gas Emissions Reporting from the Petroleum And 
Natural Gas Industry: Background Technical Support Document, U.S. 
EPA, 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.
---------------------------------------------------------------------------

    To determine the potential sources to be evaluated for inclusion in 
the original subpart W, the EPA used the emissions for the year 2006 as 
published in the 2008 U.S. GHG Inventory.\71\ As documented in the 2010 
subpart W TSD, the EPA estimated that AGR vents emitted 643 MMscf of 
CH4 that year, which corresponds generally to the 12,380 mt 
CH4 from AGR vents shown in Table A-114 of the 2008 U.S. GHG 
Inventory. The inputs for that estimate include the emission factor for 
AGR vents from Volume 14: Glycol Dehydrators of the 1996 GRI/EPA study 
(available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234), and an estimate of about 290 AGRs at processing plants, 
scaled from the 1992 estimate of 371 AGRs presented in the GRI/EPA 
study. However, the emission factor in the 1996 GRI/EPA study is based 
on an AGR throughput of about 35 MMscf per day, while the average feed 
rate of the AGRs reported at onshore natural gas processing plants in 
RY2021 was around 78 MMscf per day and the average feed rate of all 
reported AGRs in RY2021 was around 59 MMscf per day. In addition, there 
were 391 AGRs reported at onshore natural gas processing plants and 579 
total AGRs reported in RY2021. In other words, the total quantity of 
natural gas treated in AGRs in RY2021 at onshore natural gas processing 
plants was about three times the total amount of natural gas estimated 
to be treated by the 2008 U.S. GHG Inventory. Therefore, the 
CH4 emissions from AGR vents are likely to be significantly 
greater than estimated in the 2010 subpart W TSD, and as such, the EPA 
is proposing to amend 40 CFR 98.233(d) and 98.236(d) to require 
calculation and reporting of those emissions. The proposed inclusion of 
reporting for emissions of CH4 from AGR vents would improve 
the coverage of total CH4 emissions reported to subpart W, 
consistent with section II.A of this preamble. For more information on 
the estimation of potential CH4 emissions from AGR vents, 
see the subpart W TSD, available in the docket for this rulemaking, 
Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    \71\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and 
Sinks 1990-2006. April 2008. Available at https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2006 and in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

    There are four calculation methods currently provided in 40 CFR 
98.233(d) for calculating CO2 emissions from AGR vents. 
Calculation Method 1 is to use a continuous emissions monitoring system 
(CEMS) if one is installed (40 CFR 98.233(d)(1)), and Calculation 
Method 2 requires the use of a vent flow meter if there is one 
installed that is not part of a CEMS and use either a continuous gas 
analyzer or quarterly gas samples for composition (40 CFR 
98.233(d)(2)). If neither a CEMS nor a vent flow meter is installed, 
reporters currently may use Calculation Method 3, engineering equations 
(40 CFR 98.233(d)(3)), or Calculation Method 4, modeling simulation via 
software (40 CFR 98.233(d)(4)).
    As part of this proposal, the EPA evaluated the existing 
calculation methods for the purpose of proposing to require 
CH4 emissions from AGR vents, and based on that assessment, 
Calculation Methods 2, 3, and 4, are generally appropriate to use for 
CH4. Calculation Method 1 is not considered an option for 
CH4 because the EPA is not currently aware of continuous 
CH4 monitors that meet the EPA's criteria for CEMS.\72\ 
Therefore, the EPA is proposing to specify that reporters must use 
Calculation Method 2 to calculate CH4 emissions if they have 
a vent flow meter installed (including the flow meter of a 
CO2 CEMS) and is proposing to revise the subscripts of the 
variables in equation W-3 slightly to specify that reporters should 
calculate both CO2 and CH4. If there is no vent 
flow meter, the EPA is proposing that reporters would choose between 
Calculation Method 3 or Calculation Method 4. For Calculation Method 4, 
the EPA is proposing to add the CH4 content of the feed 
natural gas and the outlet natural gas as parameters that must be used 
to characterize emissions. This specification is analogous to the 
existing requirement to use acid gas content of the feed natural gas 
and the acid gas content of outlet natural gas to characterize 
CO2 emissions. For Calculation Method 3, the EPA is 
proposing to revise the existing equations W-4A and W-4B and to add

[[Page 50317]]

a new equation W-4C. With the addition of CH4 as a component 
for these equations, reporters would need to have information on four 
parameters rather than the three they currently need to know. For more 
information on the derivation of these proposed equations, see the 
subpart W TSD, available in the docket for this rulemaking, Docket Id. 
No. EPA-HQ-OAR-2023-0234. We request comment on whether these are the 
appropriate methods for calculating CH4 from AGR vents, 
including whether there are continuous CH4 monitors that 
meet the EPA's criteria for CEMS.
---------------------------------------------------------------------------

    \72\ See https://www.epa.gov/emc/emc-continuous-emission-monitoring-systems for more information on CEMS.
---------------------------------------------------------------------------

    Although we used the 1996 GRI/EPA emission factor to assess the 
potential magnitude of CH4 emissions from AGR vents, both in 
the 2010 subpart W TSD and for an initial assessment of whether to 
include additional reporting requirements in this proposal, we are not 
proposing use of that emission factor as a method for calculating 
emissions under subpart W. That emission factor is based on modeling of 
an average system from many years ago, and as discussed earlier in this 
section, the model AGR is much smaller than the AGRs reported to 
subpart W more recently. The emission factor is per AGR, so it does not 
take into account the feed rate of the AGR, the concentration of 
CO2 entering the unit, or the level of treatment (i.e., 
concentration of CO2 exiting the unit).
    The EPA is also proposing to add relevant reporting elements for 
CH4 from each AGR to 40 CFR 98.236(d). The additional data 
elements include annual CH4 emissions vented directly to the 
atmosphere; annual average volumetric fraction of CH4 in the 
vent gas if using Calculation Method 2; additional inputs for 
Calculation Method 3, depending on the equation used (i.e., as 
applicable, the annual average volumetric fraction of CH4 in 
the natural gas flowing out of the AGR, annual average volumetric 
fraction of CH4 content in natural gas flowing into the AGR, 
annual average volumetric fraction of CO2 in the vent gas 
exiting the AGR and annual average volumetric fraction of 
CH4 in the vent gas exiting the AGR); and the CH4 
content of the feed natural gas and outlet natural gas if using 
Calculation Method 4.
    Finally, we note that under the current provisions of subpart W, 
reporters with AGRs routed to flares are required to report the 
CO2 emissions from the AGR that pass through the flare as 
AGR vent emissions, and the emissions that result from combustion of 
any CH4 in the AGR vent stream are reported as flare stack 
emissions. In the 2022 Proposed Rule, we proposed to provide more 
clarity regarding how to determine the flow rate and composition of the 
gas routed to a flare if Calculation Method 3 or 4 were used to 
calculate CO2 emissions. Because we are proposing to require 
reporting of CH4 emissions from AGR vents, there would be no 
reason for subpart W to include special provisions for AGR vents routed 
to flares that are different from the provisions for all other emission 
source types routed to flares. Instead, the EPA is proposing that AGR 
vents routed to a flare would follow the same calculation requirements 
as other emission source types and would begin reporting flared AGR 
emissions (CO2, CH4, and N2O) separately from 
vented AGR emissions (CO2 and CH4). See section 
III.N of this preamble for more information on the proposed flaring 
calculation and reporting provisions. In a similar amendment, we are 
proposing to specify that AGR vents routed to an engine would calculate 
CO2, CH4, and N2O emissions using the provisions 
of 98.233(z) or subpart C, whichever is applicable to that industry 
segment. We are also proposing that AGRs routed to a flare or engine 
for the entire year would report the information in proposed 40 CFR 
98.236(d)(1) except for the calculation method, the indication of 
whether any CO2 emissions were recovered and transferred 
offsite, and the CO2 and CH4 emissions from the 
unit. If the AGR routed to a flare or an engine only for part of the 
year, the other information in proposed 40 CFR 98.236(d)(1) would be 
required to be reported for the part of the year in which emissions 
were vented directly to the atmosphere.
2. Calculation Method 4
    Reporters with AGRs that elect to calculate emissions using 
Calculation Method 4 are currently required to calculate emissions 
using any standard simulation software package that uses the Peng-
Robinson equation of state and speciates CO2 emissions. 
According to existing 40 CFR 98.233(c)(4), the information that must be 
used to characterize emissions include natural gas feed temperature, 
pressure, flow rate, and acid gas content; outlet natural gas acid gas 
content and temperature; unit operating hours; and solvent temperature, 
pressure, circulation rate, and weight. These parameters currently must 
be determined for typical operating conditions over the calendar year 
by engineering estimate and process knowledge based on best available 
data. Consistent with section II.B of this preamble, we are proposing 
that the input parameters related to the natural gas feed that are used 
for the simulation software must be obtained by measurement. Those 
parameters include natural gas feed temperature, pressure, flow rate, 
acid gas content, CH4 content, and, for nitrogen removal 
units, nitrogen content. We are proposing that reporters would collect 
measurements reflective of representative operating conditions over the 
time period covered by the simulation. We are not proposing to change 
the requirement that the other parameters must be determined for 
operating conditions based on engineering estimate and process 
knowledge.
    We are also proposing that the parameters that must be used to 
characterize emissions should reflect operating conditions over the 
time period covered by the simulation rather than just over the 
calendar year. Under this proposed change, reporters could continue to 
run the simulation once per year with parameters that are determined to 
be representative of operating conditions over the entire year. 
Alternatively, reporters would be allowed to conduct periodic 
simulation runs to cover portions of the calendar year, as long as the 
entire calendar year is covered. The reporter would then sum the 
results at the end of the year to determine annual emissions. In that 
case, the parameters for each simulation run would be determined for 
the operating conditions over each corresponding portion of the 
calendar year. Finally, we are proposing to clarify that the 
information reported under 40 CFR 98.236(d)(2)(ii) should be provided 
on an annual basis, either as an average across the year, or a total 
for the year (in the case of operating hours for the unit).
    We are also proposing an additional change to the reported data for 
reporters with AGRs that elect to calculate emissions using Calculation 
Method 4. One of the required inputs to report is the solvent weight, 
in pounds per gallon (under existing 40 CFR 98.236(d)(2)(iii)(L)). A 
variety of different solvents may be used in an AGR (e.g., chemical 
solvents such as monoethanolamine (MEA) and methyl diethanolamine 
(MDEA), physical solvents such as SelexolTM and 
Rectisol[supreg]), and the solubility of CO2 varies across 
the different types of solvent. Requiring reporters to provide solvent 
characteristics provides information about the type of solvent used so 
the emissions calculated by the modeling run could be verified. 
However, the ``solvent weight'' is the only data element related to the 
identification of the solvent that is currently collected, and the 
values reported across all reporters have been inconsistent over the 
last few years, indicating that this data element is

[[Page 50318]]

likely not clear to reporters (e.g., some reporters appear to be 
providing the density of the solvent and others appear to be providing 
the amine concentration in weight percent). In addition, the densities 
of common amine-based solvents are fairly close in value, so even among 
reporters that are providing values within the expected range of 
solvent densities, we have found it difficult to use this data element 
to identify the solvent type. Finally, the current requirement to 
report solvent weight does not specify how this value should be 
determined, but given the precise values being reported, it appears 
that reporters are either measuring the solvent or reporting a specific 
value provided by the vendor.
    Therefore, we are proposing to replace the existing requirement to 
report solvent weight with a requirement (proposed 40 CFR 
98.236(d)(2)(iii)(N)) to report the solvent type and, for amine-based 
solvents, the general composition. Reporters would choose the solvent 
type option from a pre-defined list that most closely matches the 
solvent type and, for amine-based solvents, the general composition, 
used in their AGR. The standardized response options would include the 
following: ``SelexolTM,'' ``Rectisol[supreg],'' 
``PurisolTM,'' ``Fluor SolventSM,'' 
``BenfieldTM,'' ``20 wt% MEA,'' ``30 wt% MEA,'' ``40 wt% 
MDEA,'' ``50 wt% MDEA,'' and ``Other (specify).'' We are proposing to 
use commercially available trade names in this list rather than 
chemical compositions, as the trade names are more commonly used among 
AGR operators and therefore more readily available. This proposed 
amendment to collect standardized information about the solvent is 
expected to result in more useful data that would improve verification 
of reported data and better characterize AGR vent emissions, consistent 
with section II.C of this preamble. It would also improve the quality 
of the data reported compared to the apparently inconsistent 
application of the current requirements. In addition, the solvent type 
and composition rarely change from one year to the next, so once the 
data element is reported the first time, most reporters would be able 
to copy the response from the previous year's reporting form each year. 
Therefore, the proposal to require reporters to select a solvent type 
and composition from these standardized responses is also expected to 
improve verification and the consistency of reported data compared to 
the current requirement, consistent with section II.C of this preamble. 
In the event that reporters use more than one type of solvent in their 
AGR during the year, the proposed reporting requirement specifies that 
reporters would select the option that corresponds to the solvent used 
for the majority of the year.
3. Reporting of Flow Rates
    We are proposing several amendments to improve the quality and 
verification of AGR flow rate information, consistent with sections 
II.C of this preamble. Reporters are currently required to report the 
total feed rate entering the AGR in units of million cubic feet per 
year (existing 40 CFR 98.236(d)(1)(iii), proposed 40 CFR 
98.236(d)(1)(iv)). The existing rule does not specify million standard 
cubic feet per year or million actual cubic feet per year, so reporters 
may provide this feed rate in either of those units of measure. 
However, there is not currently a requirement for reporters to provide 
the actual temperature and pressure for the total feed rate if it is 
reported in million actual cubic feet, so it is difficult for the EPA 
to tell which are the correct units of measure. Reporters also provide 
flow rates that correspond with the calculation method chosen, and the 
subpart W reporting form currently requests the temperature and 
pressure corresponding to those flow rates, but they cannot necessarily 
be used to clarify the units of measure for the total feed rate. For 
example, for Calculation Method 1 or 2, reporters provide the annual 
volume of gas vented from the AGR in cubic feet (existing 40 CFR 
98.236(d)(2)(i)(B), proposed 40 CFR 98.236(d)(2)(i)(C)), but the 
temperature and pressure of this vent gas does not correlate directly 
to the temperature and pressure for the AGR feed rate. In addition, 
while the reporting form requests the temperature and pressure 
corresponding to various flow rates, those data elements are not 
specifically included in 40 CFR 98.236(d), so there appears to be some 
inconsistency between the flow rates reported and the temperature and 
pressure reported. For example, in some cases, the flow rate appears to 
be reported in standard cubic feet but the temperature and pressure 
appear to represent actual conditions; in these cases, the temperature 
and pressure may have been the values used to convert the flow rate 
from actual conditions to the reported standard conditions, but it is 
not clear. As a result, the EPA has found it difficult to verify the 
AGR flow rates in some cases.
    Therefore, we are first proposing to require that the total annual 
feed rate that is required to be reported for all AGRs regardless of 
the how the emissions are calculated (existing 40 CFR 
98.236(d)(1)(iii), proposed 40 CFR 98.236(d)(1)(iv)) would be reported 
at standard conditions (i.e., in units of MMscf per year). The 
revisions would make the units of measure for this total annual feed 
rate more consistent with the natural gas throughputs reported for each 
industry segment in existing 40 CFR 98.236(aa) and would standardize 
the units of measure for this total annual feed rate across all AGRs. 
Stakeholders have previously indicated that standard industry practice 
for either calculating or measuring the flow of gas into or out of an 
AGR would be in standard conditions.\73\ Based on the data reported 
from RY2015 to RY2021, the EPA estimates that at least 80 percent of 
the AGR total annual feed rates were reported in MMscf per year (for 
the remaining 20 percent of the AGRs, the EPA either was able to 
determine that the AGR feed rate was reported in million actual cubic 
feet per year, or it is unclear whether the feed rate was reported in 
actual or standard conditions). Therefore, this proposed revision is 
not expected to result in changes for the majority of the reporters but 
would improve the quality of the overall data.
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    \73\ E.g., see U.S. EPA. Response to Public Comments on 
Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems, November 2014, 
Comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt Number 73.
---------------------------------------------------------------------------

    Second, we are proposing to specifically require the temperature 
and pressure that correspond to the flow rates reported for Calculation 
Methods 1, 2, or 3 (reporters using Calculation Method 4 are already 
required to report the temperature and pressure of the acid gas feed, 
under existing 40 CFR 98.236(d)(2)(iii)(B) and (C)). Depending on the 
calculation method selected, reporters are required to provide the vent 
gas flow rate, flow rate of natural gas into the AGR, and/or the flow 
rate of natural gas out of the AGR. The calculation methodologies in 
existing 40 CFR 98.233(d)(1) through (3) and the reporting requirements 
in existing 40 CFR 98.236(d)(2)(i) and (ii) accommodate use of flow 
rates in either actual or standard conditions to calculate emissions. 
The proposed additions, at proposed 40 CFR 98.236(d)(2)(i)(D) and (E) 
and (d)(2)(ii)(I), (J), (L), and (M), specify that reported temperature 
and pressure should be the actual temperature and pressure if the flow 
rate is reported in actual conditions, or standard temperature and 
pressure if the flow rate is reported in standard conditions. These 
proposed additions would provide the EPA with the ability to verify the 
emissions calculations more

[[Page 50319]]

efficiently and would provide a more consistent data set overall.

G. Dehydrator Vents

    Dehydrators are used to remove water from produced natural gas 
prior to transferring the natural gas into a pipeline or to a gas 
processing facility. Subpart W requires reporting of GHG emissions from 
dehydrator vents at onshore petroleum and natural gas production, 
onshore petroleum and natural gas gathering and boosting, and natural 
gas processing facilities. Emissions are determined using one of the 
calculation methodologies for glycol dehydrators provided in existing 
40 CFR 98.233(e) based on the unit's annual average daily natural gas 
throughput. For glycol dehydrator units with an annual average daily 
natural gas throughput less than 0.4 MMscf per day, reporters currently 
use population emission factors and equation W-5 to calculate 
volumetric CO2 and CH4 emissions per existing 40 
CFR 98.233(e)(2) (Calculation Method 2). For glycol dehydrator units 
with an annual average daily natural gas throughput greater than or 
equal to 0.4 MMscf per day, reporters must follow the provisions under 
existing 40 CFR 98.233(e)(1), which require modeling GHG emissions 
using a software program (e.g., AspenTech HYSYS[supreg] \74\ or GRI-
GLYCalcTM \75\) (Calculation Method 1). Facilities with 
desiccant dehydrators calculate volumetric CO2 and 
CH4 emissions using equation W-6 and the provisions of 
existing 40 CFR 98.233(e)(3) (Calculation Method 3). In the 2022 
Proposed Rule, the EPA proposed to remove the emissions calculation and 
reporting requirements for desiccant dehydrators per 40 CFR 
98.233(e)(3) and 40 CFR 98.236(e)(3). However, to avoid potential gaps 
in emissions data and improve the accuracy of the data collected in the 
GHGRP (consistent with section II.A of this preamble), the EPA is not 
proposing the removal of desiccant dehydrator requirements in this 
proposal.
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    \74\ AspenTech HYSYS[supreg] software available from AspenTech 
website (https://www.aspentech.com/).
    \75\ GRI-GLYCalcTM software available from Gas 
Technology Institute website (https://sales.gastechnology.org/).
---------------------------------------------------------------------------

1. Selection of Appropriate Calculation Methodologies for Glycol 
Dehydrators
    As noted in section III.G of this preamble, for dehydrators that 
have an annual average of daily natural gas throughput that is less 
than 0.4 MMscf per day, reporters currently use population emission 
factors and equation W-5 to calculate volumetric CO2 and 
CH4 emissions per Calculation Method 2 (40 CFR 98.233(e)(2)) 
and report emissions per 40 CFR 98.236(e)(2). Reporters with glycol 
dehydrators that have an annual average of daily natural gas throughput 
that is greater than or equal to 0.4 MMscf per day are currently 
required to model their dehydrator emissions per Calculation Method 1 
(40 CFR 98.233(e)(1)). Through requests submitted to the GHGRP Help 
Desk and correspondence with the EPA via e-GGRT, reporters have 
indicated the desire to use Calculation Method 1 for determining 
emissions from dehydrators that have a throughput that is less than 0.4 
MMscf per day, as they stated that the population emission factors 
provided in 40 CFR 98.233(e)(2) are not always representative of their 
dehydrators' actual emissions. Process simulations and models require 
unit-specific inputs, so it is reasonable to expect that they would 
result in more accurate emissions estimates for dehydrators that have 
differing operating characteristics than those used to develop the 
Calculation Method 2 emission factors. Therefore, we are proposing to 
revise the calculation requirements of 40 CFR 98.233(e) to allow 
reporters the ability to use Calculation Method 1 or Calculation Method 
2 when determining emissions from dehydrators that have an annual 
average of daily natural gas throughput that is less than 0.4 MMscf per 
day. We are also proposing to specify that if a facility is required to 
or elects to perform emissions modeling of a glycol dehydrator 
consistent with the methodology outlined in 40 CFR 98.233(e)(1), they 
must use the results of the model for estimating emissions under 40 CFR 
98.233(e). It is the EPA's intention with this proposal that if 
reporters conduct modeling for environmental compliance or reporting 
purposes, including but not limited to compliance with Federal or state 
regulations, air permit requirements, annual inventory reporting, or 
internal review, they would use those results for reporting under 
subpart W. The EPA is also proposing revisions to 40 CFR 98.236(e) to 
specify the applicable reporting requirements based on the selected 
calculation method rather than the throughput of the dehydrator. This 
amendment is expected to improve the quality of the data collected, 
consistent with section II.B of this preamble.
2. Controlled Dehydrators
    In correspondence with the EPA via e-GGRT, some reporters have 
asked the EPA for guidance regarding calculating emissions from 
dehydrators that are routed to different control devices throughout the 
reporting year (e.g., dehydrators that are routed to vapor recovery and 
subsequently vented to atmosphere or routed to a flare when the vapor 
recovery device is not operating). Given the proposed amendments to the 
calculation methodology and reporting of flare stack emissions 
(discussed in section III.N of this preamble), we are proposing to 
revise the methodologies for calculating emissions from dehydrator 
vents controlled by a vapor recovery system, flare, or regenerator 
firebox/fire tubes currently provided in 40 CFR 98.233(e)(5) and (6), 
respectively. The new language in proposed 40 CFR 98.233(e)(4) provides 
a methodology for calculating emissions vented directly to the 
atmosphere during periods of time when emissions are not routed to the 
vapor recovery system, flare, or regenerator firebox/fire tubes. For 
flared dehydrator emissions, the proposed 40 CFR 98.233(e) provisions 
would direct reporters to the proposed methodologies in 40 CFR 
98.233(n). As a regenerator firebox/fire tubes does not meet the 
definition of a flare per 40 CFR 98.238, we are proposing methodologies 
for calculating combusted emissions from a regenerator firebox/fire 
tubes in 40 CFR 98.233(e)(5) using the combustion source equations W-
39A, W-39B, and W-40 of 40 CFR 98.233(z)(3). We are also proposing new 
reporting requirements for dehydrator units with emissions routed to a 
firebox/fire tubes in proposed 40 CFR 98.236(e)(1)(xvi) and (xvii), 
(e)(2)(v), and (e)(3)(vii) that are consistent with the reporting 
requirements for combustion sources in 40 CFR 98.236(z)(2). By 
proposing these amendments, the EPA seeks to enhance the overall 
quality of the data collected under the GHGRP, consistent with sections 
II.B and II.D of this preamble.
    The EPA is also proposing revisions to two terms consistent with 
the proposed amendments for reporting for glycol dehydrators with an 
annual average daily natural gas throughput greater than or equal to 
0.4 MMscf per day. The EPA is proposing to amend the definition of 
``dehydrator vent emissions'' in 40 CFR 98.6 to confirm that dehydrator 
emissions reporting should include emissions from both the dehydrator 
still vent, and if applicable, the dehydrator flash vent. We are also 
proposing to remove the term ``reboiler'' from the definition, as the 
term ``regenerator'' refers to the same piece of equipment. Finally, we 
are proposing to expand the dehydrator control types referenced in the 
definition to include regenerator fireboxes/fire tubes and vapor 
recovery systems. Additionally,

[[Page 50320]]

the EPA is proposing to amend the definition of ``vapor recovery 
system'' in 40 CFR 98.6 to clarify that routing emissions from a 
dehydrator regenerator still vent or flash tank separator vent to the 
regenerator firebox/fire tubes does not qualify as vapor recovery for 
purposes of 40 CFR 98.233. The EPA has noted significant variability in 
the dehydrator emissions values reported over the past several years, 
with values ranging from extremely high to almost negligible emissions, 
which indicates that there are likely inconsistencies in how these 
terms are being interpreted among subpart W reporters. In proposing 
these edits, the EPA expects to improve the quality of the emissions 
data reported and confirm the original intent of these terms.
3. Calculation Method 1 for Glycol Dehydrators
    Reporters with glycol dehydrator units that calculate emissions 
using Calculation Method 1 are currently required to determine 
emissions using any standard simulation software package that uses the 
Peng-Robinson equation of state to calculate the equilibrium 
coefficient; speciates CH4 and CO2 emissions from 
dehydrators; and has provisions to include regenerator control devices, 
a separator flash tank, stripping gas and a gas injection pump or gas 
assist pump. According to current 40 CFR 98.233(e)(1), the information 
that must be used to characterize emissions include natural gas feed 
flow rate and water content; outlet natural gas water content; 
absorbent circulation pump type, circulation rate, and absorbent type; 
use of stripping gas, use of flash tank separator (and disposition of 
recovered gas), hours operated, wet natural gas temperature, pressure, 
and composition. These parameters currently must be determined for 
typical operating conditions over the calendar year by engineering 
estimate and process knowledge based on best available data. Consistent 
with section II.B of this preamble, we are proposing that the input 
parameters related to the natural gas feed that are used for the 
simulation software must be obtained by measurement. Those parameters 
include feed natural gas flow rate, feed natural gas water content, wet 
natural gas temperature and pressure at the absorber inlet, and wet 
natural gas composition. We are proposing that reporters would collect 
measurements reflective of representative operating conditions over the 
time period covered by the simulation. We are not proposing to change 
the requirement that the other parameters must be determined for 
operating conditions based on engineering estimate and process 
knowledge.
    We are also proposing that the parameters that must be used to 
characterize emissions should reflect operating conditions over the 
time period covered by the simulation rather than just over the 
calendar year. Under this proposed change, reporters could continue to 
run the simulation once per year with parameters that are determined to 
be representative of operating conditions over the entire year. 
Alternatively, reporters would be allowed to conduct periodic 
simulation runs to cover portions of the calendar year, as long as the 
entire calendar year is covered. The reporter would then sum the 
results at the end of the year to determine annual emissions. In that 
case, the parameters for each simulation run would be determined for 
the operating conditions over each corresponding portion of the 
calendar year. Finally, we are proposing to clarify that the 
information reported under 40 CFR 98.236(e)(1) should be provided on an 
annual basis, either as an average across the year, or a total for the 
year (in the case of operating hours for the unit).
    Subpart W currently lists two example software options, AspenTech 
HYSYS[supreg] and GRI-GLYCalcTM (GLYCalc), that meet the 
software requirements in 40 CFR 98.233(e)(1). Reporters are not limited 
to only using these two example software options. However, the EPA 
recently approved the use of ProMax \76\ software simulations for 
compliance with 40 CFR part 63, subpart HH, National Emission Standards 
for Hazardous Air Pollutants from Oil and Gas Production Facilities 
(hereafter referred to as ``NESHAP HH'').\77\ In the approval letter, 
the EPA concluded that the ProMax model results are typically 
equivalent or more conservative when compared to the results from the 
GLYCalc model and the total capture condensation method used by the EPA 
in its research. After considering this issue, we expect that ProMax 
meets the specifications of existing 40 CFR 98.233(e)(1) and, 
therefore, we are proposing to add ProMax as an example software 
program for calculating dehydrator emissions in 40 CFR 98.233(e)(1) for 
clarity for reporters. Consistent with the EPA's approval of ProMax for 
NESHAP HH compliance, the EPA is proposing that if reporters elect to 
use ProMax, they would be required to use version 5.0 or above.
---------------------------------------------------------------------------

    \76\ BRE Promax[supreg] software available from BRE website 
(https://www.bre.com/).
    \77\ Letter from Steffan Johnson, Group Leader, Measurement 
Technology Group, U.S. EPA Office of Air Quality Planning and 
Standards, to Josh Ravichandran, Bryan Research & Engineering, LLC, 
Re: Response to request for broad source category-wide approval for 
use of Bryan Research & Engineering's process simulation software, 
ProMax[supreg] (ProMax) in lieu of the GRI-GLYCalcTM 
software (GLYCalc) for modeling glycol dehydration unit emissions in 
demonstrating compliance with 40 CFR part 63, subpart HH, National 
Emission Standards for Hazardous Air Pollutants from Oil and Gas 
Production Facilities (Subpart HH). March 31, 2022. Available at 
https://www.epa.gov/system/files/documents/2022-03/ravichandran-bre-promax-alt-final_147_signed.pdf and in the docket for this 
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    As stated above, the EPA indicated in the referenced NESHAP HH 
ProMax approval that ProMax emissions results may be more conservative 
than emissions calculated using GLYCalc. In order to assess potential 
emissions changes between reporting years, the EPA is also proposing 
add a new provision under 40 CFR 98.236(e)(1)(xviii) to request 
reporting of the modeling software used to calculate emissions for each 
dehydrator unit using Calculation Method 1. We expect these proposed 
amendments would improve the quality of the data collected, consistent 
with section II.B of this preamble.
4. Calculation Method 1 Reporting
    The EPA has reviewed the subpart W glycol dehydrator data and 
reporting requirements in existing 40 CFR 98.236(e) and has made a 
preliminary determination that additional information would help to 
more accurately characterize emissions from glycol dehydrators using 
Calculation Method 1. The EPA is proposing under 40 CFR 98.236(e) to 
require separate reporting of emissions for a modeled glycol 
dehydrator's still vent and flash tank vent. These vents often use 
different control techniques, so requiring the emissions and applicable 
controls from these vents to be reported separately would ensure that 
emissions are more accurately characterized. The proposed data elements 
are included in the output files from the modeling software used for 
glycol dehydrators and therefore, this provision is not expected to be 
difficult for reporters to implement. We expect these proposed 
amendments would improve the quality of the data collected, consistent 
with section II.C of this preamble.\78\
---------------------------------------------------------------------------

    \78\ In the 2022 Proposed Rule, the EPA proposed to add several 
new reporting requirements for Calculation Method 1 glycol 
dehydrators under 40 CFR 98.236(e)(1) in an effort to find a 
potential correlation between dehydrator emissions and operating 
parameters. However, after consideration of comments received on the 
2022 Proposed Rule, we have decided not to propose these additional 
elements in this proposal.

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[[Page 50321]]

    In the 2022 Proposed Rule, the EPA proposed to collect additional 
information on Calculation Method 1 glycol dehydrators under 40 CFR 
98.236(e)(1) in an effort to derive a correlation between vent flow 
rate, absorbent circulation rate, and glycol pump type. Comments on the 
2022 Proposed Rule indicated that this additional information request 
would be unnecessarily burdensome to reporters. Therefore, we are not 
proposing the reporting of additional data elements for this purpose in 
this proposal.
5. Calculation Method 2 for Glycol Dehydrators
    As noted in section III.F.3 of this preamble, for glycol 
dehydrators with an annual average daily natural gas throughput less 
than 0.4 MMscf per day, reporters currently use population emission 
factors and equation W-5 to calculate volumetric CO2 and 
CH4 emissions per existing 40 CFR 98.233(e)(2) and report 
emissions per existing 40 CFR 98.236(e)(2). Under these current 
requirements, the count of glycol dehydrators with annual average daily 
natural gas throughput less than 0.4 MMscf per day could include 
dehydrators with annual average daily natural gas throughput of 0 MMscf 
per day (i.e., glycol dehydrators that were not operated during the 
reporting year). As a result, some annual reports include a nonzero 
count of dehydrators per existing 40 CFR 98.236(e)(2)(i) without any 
corresponding CO2 and CH4 emissions. In these 
cases, it is not clear if the reporter did not report emissions because 
emissions are not expected, the emissions data were inadvertently 
omitted, or the nonzero count represents the total count of all 
dehydrators with annual average daily natural gas throughput less than 
0.4 MMscf per day, including those that were not in use.
    Therefore, the EPA is proposing to clarify in 40 CFR 98.233(e)(2) 
that the dehydrators for which emissions are calculated should be those 
with annual average daily natural gas throughput greater than 0 MMscf 
per day and less than 0.4 MMscf per day (i.e., the count should not 
include dehydrators that did not operate during the year). Similarly, 
the EPA is proposing to clarify in 40 CFR 98.236(e)(2) introductory 
text that the count of dehydrators in existing 40 CFR 98.236(e)(2)(i) 
(proposed 40 CFR 98.236(e)(2)(ii)) should also be those with annual 
average daily natural gas throughput greater than 0 MMscf per day and 
less than 0.4 MMscf per day. These proposed amendments are expected to 
improve implementation and verification of reported data, consistent 
with section III.C of this preamble.
    Additionally, the EPA is proposing edits to the existing reporting 
requirements in current 40 CFR 98.236(e)(2). Specifically, we are 
proposing to revise the data collected under current 40 CFR 
98.236(e)(2)(iii) (proposed 40 CFR 98.236(e)(2)(iv)) to emphasize the 
original intent of the rule. Currently, the requirement is to report 
whether any Calculation Method 2 dehydrator emissions are routed to a 
control device other than a vapor recovery system or a flare or 
regenerator firebox/fire tubes (and if so, the type of control 
device(s) and count of units routing to each control). We are proposing 
to specifically state that the reporting of ``other'' control devices 
should only include control devices that reduce CO2 and/or 
CH4 emissions. This proposed revision would allow the EPA to 
verify the expected reductions in vented CO2 and/or 
CH4 emissions due to the use of the control device. This 
proposed amendment is expected to improve implementation and 
verification of reported data, consistent with section III.C of this 
preamble.
6. Desiccant Dehydrators
    Subpart W requires reporting of desiccant dehydrators as a 
subcategory of dehydrator vents. The data required to be reported for 
desiccant dehydrators is consistent with the information that is 
reported for Calculation Method 2 for small glycol dehydrators: the 
total number of desiccant dehydrator units, whether any emissions from 
Calculation Method 3 units were routed to a vapor recovery system, 
flare, or other control (and if so, the count of units utilizing each 
of those controls), and the vented and/or combusted emissions from 
desiccant dehydrators. In June 2022, the EPA proposed to remove the 
reporting of desiccant dehydrators; however, as described in section 
II.B of this preamble, CAA section 136(h) directs the EPA to ensure 
that reporting under subpart W reflects total CH4 emissions, 
and we are no longer proposing to remove this source. Instead, to 
better implement and verify the desiccant dehydrator data reported 
under subpart W (consistent with section II.C of this preamble), the 
EPA is proposing several updates to the current desiccant dehydrator 
reporting requirements of 40 CFR 98.236(e)(3).
    Specifically, we are proposing to remove the cross-references from 
40 CFR 98.236(e)(3) to 40 CFR 98.236(e)(2)(i) through (iv) and instead 
include all of the applicable reporting requirements from current 40 
CFR 98.236(e)(2)(i) through (iv) for Calculation Method 2 glycol 
dehydrators as reporting requirements for Calculation Method 3 
desiccant dehydrators under 40 CFR 98.236(e)(3). Currently, the 
language in 40 CFR 98.236(e)(3)(i) simply states that the same 
information that is included under 40 CFR 98.236(e)(2)(i) through (iv) 
should be reported for dehydrators that use desiccant. While we 
acknowledge that the current language has been correctly interpreted by 
reporters as-is, replicating the requirements under 40 CFR 98.236(e)(3) 
would make the rule easier to follow and allow the EPA to further 
clarify the required reporting data elements for desiccant dehydrators. 
Additionally, the EPA is proposing to specify that only desiccant 
dehydrators that were opened during the reporting year should be 
included in the total number of desiccant dehydrators at the facility 
under proposed 40 CFR 98.236(e)(3)(ii). This revision would align the 
reported count of desiccant dehydrators with the applicability of 
Calculation Method 3 methodology, which requires facilities to 
calculate emissions from the amount of gas vented from vessels when 
they are depressurized and opened for the desiccant refilling process. 
Also, we are proposing to require reporting of the total volume of all 
opened desiccant dehydrator vessels and the total number of desiccant 
dehydrator openings in the calendar year as new data elements under 
proposed 40 CFR 98.236(e)(3)(iii) and (iv), respectively. These data 
elements are inputs into equation W-6 and should, therefore, be readily 
available to facilities. With the change to reported number of 
desiccant dehydrators under proposed 40 CFR 98.233(e)(3)(ii) and the 
proposed addition of the two new data elements for vessel volume and 
number of vessel openings, the EPA would be able to more effectively 
verify the reported desiccant dehydrator emissions from each facility.
    The EPA is also proposing to revise the definitions of 
``dehydrator'' and ``desiccant'' in 40 CFR 98.6 to conform with the 
inclusion of desiccant dehydrators in subpart W. Currently, the 
definition of ``dehydrator'' indicates that desiccant is an example of 
a liquid absorbent. Since desiccants are solid materials, we are 
proposing to remove desiccant from the list of example liquid 
absorbents and instead define dehydrators as devices that use either a 
liquid absorbent or a desiccant to remove water vapor from a natural 
gas stream. The current definition of ``dehydrator'' also indicates 
that the device is used to absorb water vapor.

[[Page 50322]]

However, since some desiccants work by adsorbing water, we are 
proposing to replace the word ``absorb'' with ``remove.'' The 
definition of ``desiccant'' indicates that desiccants ``include 
activated alumina, pelletized calcium chloride, lithium chloride and 
granular silica gel material.'' We are proposing to add ``molecular 
sieves'' to the list of example desiccant because they are a common 
type of desiccant. Since the list of example desiccants is not meant to 
be exhaustive or all-inclusive, we are also proposing to replace the 
word ``including'' with ``including, but not limited to.'' With these 
changes, the proposed definition would clarify that desiccants 
``include, but are not limited to, molecular sieves, activated alumina, 
pelletized calcium chloride, lithium chloride and granular silica gel 
material.'' We expect these proposed amendments would improve the 
overall quality and completeness of the emissions data collected by the 
GHGRP, consistent with section II.A of this preamble.
    Consistent with the proposed revisions to the definition of 
``desiccant'' under 40 CFR 98.6, the EPA is proposing to add two 
additional data elements to the desiccant dehydrator reporting 
requirements in 40 CFR 98.236(e)(3). We are proposing to require 
reporting of the count of opened desiccant dehydrators that used 
deliquescing desiccant (e.g., calcium chloride or lithium chloride) and 
the count of opened desiccant dehydrators that used regenerative 
desiccant (e.g., molecular sieves, activated alumina, or silica gel) 
present at the facility (proposed 40 CFR 98.236(e)(3)(ii)(B) and (C), 
respectively). As regenerative desiccant dehydrators are not opened as 
often as deliquescing desiccant dehydrators, the EPA would use this new 
data to verify large swings in desiccant dehydrator emissions year-to-
year and to gain a better understanding of the distribution of 
emissions between the two types of desiccant dehydrators. These 
proposed amendments would improve verification of reported data and 
ensure accurate reporting of emissions, consistent with section II.C of 
this preamble.

H. Liquids Unloading

1. Selection of Calculation Method
    Subpart W currently requires reporting of emissions from well 
venting for liquids unloading. Facilities currently calculate emissions 
using measured flow rates under Calculation Method 1 (40 CFR 
98.233(f)(1)) or engineering equations under Calculation Method 2 for 
unloadings without plunger lifts (40 CFR 98.233(f)(2)) and Calculation 
Method 3 for unloadings with plunger lifts (40 CFR 98.233(f)(3)). As 
noted in the preamble to the NSPS OOOOb supplemental proposal, 
facilities can face operational and safety issues managing liquids 
unloading with the EPA noting in the preamble that there could be 
situations where ``it is technically infeasible or not safe to perform 
well liquids with zero emissions unloadings'' (87 FR 74781, December 6, 
2022). The EPA believes these safety and operational issues can 
possibly extend to taking measurements at wells with liquids unloading. 
Therefore, the EPA is proposing to continue providing reporters the 
option to use Calculation Methods 2 and 3 to calculate emissions from 
liquids unloading. Both equations rely on well-specific data, including 
well depth, tubing or casing diameter, and the flow line rate of gas, 
to calculate well-level emissions. However, consistent with section 
II.B of this preamble, the EPA is proposing that reporters with liquids 
unloadings must calculate emissions from unloadings for each well at 
least once every 3 consecutive calendar years or more frequently using 
Calculation Method 1 to ensure that the engineering equations 
accurately and consistently represent the quantity of emissions from 
unloading events.
    To implement this change, the EPA is proposing to amend the 
introductory text in 40 CFR 98.233(f) to add the requirement that 
reporters must use Calculation Method 1 to calculate emissions from 
well venting for liquids unloading every 3 consecutive calendar years 
or more frequently. Calculation Method 1 currently requires reporters 
to install a recording flow meter on the vent line used to vent gas 
from the well to a separator or atmospheric tank and measure the flow 
rate of the unloading events. The reporter must measure flow rates at 
one or more wells in each sub-basin combination (sub-basin/plunger lift 
indicator/automated/manual indicator) where wells are subject to 
liquids unloading events. The average measured flow rate in standard 
cubic feet per hour is then applied to each well with unloadings in the 
same sub-basin combination for the time in hours during the year the 
well is unloaded. To support implementation of this requirement, the 
EPA is proposing to add 40 CFR 98.236(f)(2)(xi)(D) and 
98.236(f)(2)(xii)(D) to require reporters to report the most recent 
calendar year Calculation Method 1 was used to calculate emissions from 
unloadings for the same sub-basin combination.
2. Reporting for Calculation Methods 2 and 3
    Under the current reporting requirements of 40 CFR 98.236(f), 
facilities must report whether plunger lifts were used when using 
Calculation Method 1 and must report the data elements used in 
equations W-7A and W-7B. For Calculation Methods 2 and 3, however, 
reporters currently only report a subset of the data elements used to 
calculate emissions in equations W-8 and W-9. Specifically, for 
Calculation Methods 2 and 3, reporters must provide a plunger lift 
indicator (i.e., whether plunger lifts were used), total number of 
wells with well venting for liquids unloading, the total number of 
unloading events, and the casing diameter (Calculation Method 2) or the 
tubing diameter (Calculation Method 3).
    In a 2019 study, Zaimes et al.\79\ evaluated various liquid 
unloading scenarios, and the results indicated that differentiating 
emissions only on the basis of type of unloading (plunger or non-
plunger lift) may not accurately assess emissions from this source. In 
particular, Zaimes et al. noted that type of unloading should be 
further differentiated for plunger lift unloadings between automated 
and manual unloadings, suggesting further granularity is necessary to 
properly characterize emissions. In particular, there could be 
significant differences in the number and duration of unloadings and, 
hence, differences in emissions between manual and automated plunger 
lift unloadings and liquids unloading emissions. A manual unloading 
occurs when field personnel attend to the well at the well-pad, for 
example, to manually plunge a well at the site using a rig or other 
method, to open a valve to direct flow to an atmospheric tank to clear 
the well, or to manually shut-in the well to allow pressure to build in 
the well-bore. Manual unloadings may be performed on a routine schedule 
or on ``as needed'' basis. An automated unloading is performed without 
manual interference. Examples of an automated unloading include a 
timing and/or pressure device used to optimize intermittent shut-in of 
the well before liquids choke off gas flow or to open and close valves, 
continually operating equipment that does not require presence of an 
operator such as rod pumping units, automated and unmanned plunger 
lifts, or other

[[Page 50323]]

unloading activities that do not entail a physical presence at the 
well-pad.
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    \79\ Zaimes, G.G. et al. ``Characterizing Regional Methane 
Emissions from Natural Gas Liquid Unloading.'' Environ. Sci. 
Technol. 2019, 53, 4619-4629. Available in the docket for this 
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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    The Zaimes et al. study did not evaluate manual and automated non-
plunger lift unloadings separately, but further differentiating non-
plunger lift unloadings between manual and automated unloadings in 
subpart W could also improve data quality. Correspondence with 
reporters via e-GGRT since subpart W reporting for the onshore 
production segment began in 2011 indicates potentially meaningful 
differences in the number of unloadings and emissions for manual versus 
automated non-plunger lift unloadings. When the EPA finalized the 
calculation methods and reporting requirements for well venting for 
liquids unloading, the reporting requirements did not differentiate 
between manual and automated non-plunger lift unloadings. However, 
reporters have clearly affirmed the use of automated non-plunger lift 
unloadings in response to multiple inquiries the EPA has made as part 
of the annual report verification process.
    In addition, there are several data elements used to calculate 
emissions from liquids unloading in equations W-8 and W-9 for 
Calculation Methods 2 and 3 that are not currently required to be 
provided. Specifically, reporters do not report well depth (Calculation 
Method 2) or tubing depth (Calculation Method 3), the average flow-line 
rate of gas, the hours that wells are left open to the atmosphere 
during unloading events, and the shut-in, surface or casing pressure 
(Calculation Method 2) or the flow-line pressure (Calculation Method 
3). Requiring reporting of these data elements would improve 
verification of annual reports to the GHGRP and would allow the EPA and 
the public to replicate calculations and more confidently confirm 
reported calculated emissions than is currently possible.
    The EPA is, therefore, proposing to revise the reporting 
requirements in 40 CFR 98.236(f)(1) and (2) to require reporters to 
include the following data elements, consistent with section II.C of 
this preamble. In 40 CFR 98.236(f)(1), for Calculation Method 1, the 
EPA is proposing that reporters would identify the type of unloading as 
an automated or manual unloading in addition to identifying whether the 
unloading is a plunger lift or non-plunger lift unloading. We are also 
proposing in 40 CFR 98.236(f)(1) that reporters would report emissions 
by unloading type combination (with or without plunger lifts, automated 
or manual unloading). In addition, for each individual Calculation 
Method 1 well that was tested during the year, we are proposing that 
reporters would specify the type of unloading as automated or manual 
unloading under 40 CFR 98.236(f)(1)(xi)(F) or 40 CFR 
98.236(f)(1)(xii)(F), as applicable.
    For non-plunger lift unloadings that use Calculation Method 2 in 40 
CFR 98.233(f)(2), the EPA is proposing in 40 CFR 98.236(f)(2) that 
reporters would identify the type of non-plunger lift unloading as 
automated or manual non-plunger lift unloading and that reporters would 
report emissions and activity data separately for each unloading type 
combination. In addition, for each well with non-plunger lift 
unloadings, the EPA is proposing to revise and add requirements in 
existing 40 CFR 98.236(f)(2)(ix) (proposed 40 CFR 98.236(f)(2)(xi) in 
this proposed rule) to report the well depth for each well 
(WDp) and the shut-in pressure, casing pressure or surface 
pressure for each well, (SPp). Reporters would continue to 
report the internal casing diameter (CDp) as is currently 
required for non-plunger lift unloadings.
    For plunger lift unloadings that use Calculation Method 3 in 40 CFR 
98.233(f)(3), the EPA is proposing in 40 CFR 98.236(f)(2) that 
reporters would identify the type of plunger lift unloading as 
automated or manual plunger lift unloading and that reporters would 
report emissions and activity data separately for each unloading type 
combination. In addition, for all each well with plunger lift 
unloadings, the EPA is proposing to revise and add requirements in 
existing 40 CFR 98.236(f)(2)(x) (proposed 40 CFR 98.236(f)(2)(xii) in 
this proposed rule) to report the tubing depth (WDp) and the 
flow-line pressure for each well in the sub-basin (SPp). 
Reporters would continue to report the internal tubing diameter 
(TDp) as is currently required for plunger lift unloadings.
    Finally, for each well with unloadings that uses Calculation Method 
2 or 3, the EPA is proposing to add new requirements, as proposed 40 
CFR 98.236(f)(2)(ix) and (x), to report the flow-line rate of gas 
(SFRp) and the cumulative number of hours that the well is 
left open to the atmosphere during unloading events (HRp,q), 
respectively.
    To encourage accurate classification of manual and automated 
unloadings for all calculation methods, the EPA is proposing to add new 
terms in 40 CFR 98.238 for ``Manual liquids unloading'' and ``Automated 
liquids unloading.'' The terms are proposed to be defined consistent 
with the descriptions provided earlier in this section of this 
preamble.
3. Other Clarifying Amendments
    The EPA is proposing an additional amendment to add clarity for 
reporters with liquids unloadings. The EPA is proposing to specify in 
the introductory text for 40 CFR 98.233(f) that calculation of 
emissions from unloading events is required only when the well is 
unloaded to the atmosphere or to a control device. The EPA is proposing 
this change because these unloadings are the events that result in 
emissions of GHG to the atmosphere. The proposed change, consistent 
with sections II.C and II.D of this preamble, is intended to provide 
clarity to reporters while also ensuring that the EPA continues to 
receive accurate and relevant data.

I. Gas Well Completions and Workovers With Hydraulic Fracturing

    Reporters currently may use equation W-10A or W-10B to calculate 
emissions from gas well completions and workovers with hydraulic 
fracturing. Equation W-10A is used to calculate emissions from wells 
using inputs obtained from a representative sample of wells within a 
sub-basin and the ratio of the gas flowback rate to the production flow 
rate, and equation W-10B is used to calculate emissions using inputs 
obtained from all wells within a sub-basin and the flow rate and flow 
volume of the gas vented or flared. In addition, reporters must use 
Calculation Method 1 or Calculation Method 2 in existing 40 CFR 
98.233(g)(1) for calculating inputs to equations W-12A and W-12B if 
using equation W-10A. Calculation Method 1 relies on direct measurement 
of gas flow rate during flowback to develop calculation inputs whereas 
Calculation Method 2 uses an engineering equation to produce a 
calculated flowback. Specifically, Calculation Method 2 uses the 
measured gas pressure differential across the well choke to estimate 
gas flow rate for natural gas well completions and workovers with 
hydraulic fracturing. It is, therefore, often referred to as the 
``Choke Flow'' equation. The Choke Flow equation is only available for 
hydraulically fractured natural gas well completions and workovers. It 
cannot be used for hydraulically fractured oil well completions and 
workovers.
    The majority of onshore production facilities with hydraulically 
fractured completions and workovers use equation W-10B to calculate 
emissions. In RY2021, 118 onshore production facilities reported 2418 
hydraulically fractured gas well completions or workovers. Only 15 of 
those facilities used equation W-10A for emissions calculations for 385 
gas well

[[Page 50324]]

completions or workovers. It is unknown what percentage of those 
facilities use Calculation Method 2, as the calculation methodology is 
not currently reported.
    Consistent with section II.B of this preamble, the EPA is proposing 
to retain equations W-10A and W-10B, but is proposing to remove the 
option in 40 CFR 98.233(g)(1) for reporters to use Calculation Method 
2, the Choke Flow equation, when using equation W-10A. The EPA believes 
that measurement of back flow rates is standard practice in the onshore 
production segment, whether through measurement of every well 
completion or workover or through measurement of a representative well 
or workover. Moreover, this is supported by the large number of 
reporters using equation W-10B compared with equation W-10A. The EPA 
believes this proposal would improve reporting of emissions from 
hydraulically fractured gas well completions and workovers while 
impacting very few reporters due to the small number of reporters using 
equation W-10A. The EPA understands that some reporters may be 
concerned that there could be situations where direct measurement is 
not possible for technical, operational or safety reasons; however, 
subpart W provides requirements for use of missing data procedures as 
specified in 40 CFR 98.235. The EPA is requesting comment on whether we 
should retain Calculation Method 2 for gas well completions and 
workovers with hydraulic fracturing. However, if the EPA retains 
Calculation Method 2 following consideration of public comment on this 
proposed rulemaking, the EPA expects we would also amend the reporting 
requirements in the final rulemaking to improve data quality and 
transparency. Specifically, if Calculation Method 2 is retained, the 
EPA expects we would add a new reporting requirement in 40 CFR 
98.236(g) for reporters that use equation W-10A to indicate whether the 
backflow rate for the representative well was determined using 
Calculation Method 1 or Calculation Method 2.

J. Blowdown Vent Stacks

1. Reporting Equipment Categories for Pipelines
    Subpart W currently requires reporting of blowdowns either using 
flow meter measurements (40 CFR 98.233(i)(3)) or using unique physical 
volume calculations by equipment or event types (40 CFR 98.233(i)(2)). 
Stakeholders have indicated through correspondence with the EPA via e-
GGRT and the GHGRP Help Desk that the descriptions of the ``facility 
piping'' and ``pipeline venting'' categories in 40 CFR 98.233(i)(2) as 
it is currently written reference ``distribution'' pipelines but 
compressor stations are generally not associated with distribution 
pipelines. Therefore, the EPA is proposing to revise the descriptions 
of the facility piping and pipeline venting categories in 40 CFR 
98.233(i)(2) to reflect the EPA's intent regarding which equipment or 
event type category is appropriate for each blowdown, consistent with 
section II.D of this preamble. Our intent is that the ``facility 
piping'' equipment category is limited to unique physical volumes of 
piping (i.e., piping between isolation valves) that are located 
entirely within the facility boundary. In contrast, the intent for the 
``pipeline venting'' equipment category is that a portion of the unique 
physical volume of pipeline is located outside the facility boundary 
and the remainder, including the blowdown vent stack, is located within 
the facility boundary. The proposed revisions to the equipment type 
descriptions would clarify these distinctions. Additionally, we are 
proposing to remove the reference to ``distribution'' pipelines in the 
description of these two categories because we did not intend to limit 
the pipeline venting category to unique physical volumes that include 
such pipelines. We agree with the industry stakeholders who have 
indicated that facilities subject to the blowdown vent stack reporting 
requirements typically are connected to other pipelines such as 
gathering pipelines or transmission pipelines, and on-site blowdowns 
from sections of these pipelines should be reported. Finally, we note 
that for the ``facility piping'' equipment category and the ``pipeline 
venting'' equipment category, the existing phrase ``located within a 
facility boundary'' in the descriptions of those categories generally 
refers to being part of the facility as defined by the existing 
provisions of subpart A or subpart W, as applicable, and we are not 
proposing to change that portion of those descriptions. In other words, 
blowdowns from unique physical volumes of gathering pipeline that are 
entirely considered to be part of the ``facility with respect to 
onshore petroleum and natural gas gathering and boosting'' as defined 
in 40 CFR 98.238 would be assigned to the ``facility piping'' equipment 
category. The ``pipeline venting'' equipment category would only apply 
if the unique physical volume includes some sections of gathering 
pipelines that are not part of the ``facility with respect to onshore 
petroleum and natural gas gathering and boosting'' as defined in 40 CFR 
98.238.
2. Blowdown Equipment Types
    As noted in section III.J.1 of this preamble, subpart W currently 
requires reporting of blowdowns either using flow meter measurements 
(40 CFR 98.233(i)(3)) or using unique physical volume calculations by 
equipment or event types (40 CFR 98.233(i)(2)). When the Onshore 
Natural Gas Transmission Pipeline industry segment was added to subpart 
W in 2015, after considering public comments that indicated that the 
existing equipment or event types were not appropriate for the new 
segment, the EPA developed new equipment or event types that apply only 
for the Onshore Natural Gas Transmission Pipeline industry segment (80 
FR 64275, October 22, 2015). The new equipment or event types were 
added to the introductory paragraph of 40 CFR 98.233(i)(2), where the 
existing equipment or event types were already located, resulting in a 
complex introductory paragraph. These changes also resulted in 
identical third and last sentences in 40 CFR 98.233(i)(2) that 
currently read as follows: ``If a blowdown event resulted in emissions 
from multiple equipment types and the emissions cannot be apportioned 
to the different equipment types, then categorize the blowdown event as 
the equipment type that represented the largest portion of the 
emissions for the blowdown event.''
    The EPA is proposing, consistent with section II.D of this 
preamble, to move the listings of event types and the apportioning 
provisions to a new 40 CFR 98.233(i)(2)(iv) so that the introductory 
paragraph in 40 CFR 98.233(i)(2) would be more concise and provide 
clearer information regarding which requirements are applicable for 
each blowdown. Proposed 40 CFR 98.233(i)(2)(iv) includes separate 
paragraphs for each set of equipment and event type categories and 
would also provide clearer information regarding the applicable 
requirements for each industry segment.
3. Blowdown Temperature and Pressure
    In the 2015 amendments to subpart W (80 FR 64262, October 22, 
2015), the EPA added the Onshore Petroleum and Natural Gas Gathering 
and Boosting industry segment and the Onshore Natural Gas Transmission 
Pipeline industry segment and specified that both industry segments are 
required to report emissions from blowdown vents. Stakeholders 
representing the Onshore Petroleum and Natural Gas Gathering and 
Boosting industry segment provided

[[Page 50325]]

comments on the proposed rule stating that the proposed definition of 
facility would make equipment geographically dispersed, and blowdowns 
may occur without personnel on-site or nearby, which would make it 
difficult to collect the information needed to calculate emissions from 
each blowdown (80 FR 64271, October 22, 2015). After considering those 
comments, the EPA also specified in the final amendments to equation W-
14A that for emergency blowdowns at onshore petroleum and natural gas 
gathering and boosting facilities, engineering estimates based on best 
available information may be used to determine the actual temperature 
and actual pressure.
    Since that time, the EPA has received questions through the GHGRP 
Help Desk indicating that facilities in the Onshore Natural Gas 
Transmission Pipeline industry segment also have unmanned blowdown 
vents. Given that a ``facility with respect to the onshore natural gas 
transmission pipeline segment'' is the total mileage of natural gas 
transmission pipelines owned and operated by an onshore natural gas 
transmission pipeline owner or operator, all of the blowdown vents at 
that facility would be outside the fenceline of a transmission 
compression station and would be geographically dispersed. The EPA 
considers it reasonable to assume that those blowdown vents may also be 
unmanned during an emergency blowdown, and thus it can similarly be 
difficult to collect the information needed to calculate emissions from 
each blowdown. Therefore, we are proposing to extend the provisions in 
equation W-14A of 40 CFR 98.233(i)(2)(i) that allow use of engineering 
estimates based on best available information to determine the 
temperature and pressure of an emergency blowdown to the Onshore 
Natural Gas Transmission Pipeline segment, which would align the 
requirements for the two geographically dispersed industry segments 
currently required to report blowdown vent stack emissions (Onshore 
Natural Gas Transmission Pipeline and Onshore Petroleum and Natural Gas 
Gathering and Boosting) and increase clarity of reporting requirements 
for Onshore Natural Gas Transmission Pipeline reporters, consistent 
with section II.D of this preamble. As described in section III.C.1 of 
this preamble, we are also proposing to allow use of engineering 
estimates to determine the temperature and pressure for emergency 
blowdowns in equation W-14A for the geographically dispersed industry 
segments that we are proposing would begin reporting emissions from 
blowdown vent stacks (Onshore Petroleum and Natural Gas Production and 
Natural Gas Distribution).
    In addition, similar provisions to allow use of engineering 
estimates based on best available information to determine the 
temperature and pressure of an emergency blowdown were not added to 
equation W-14B of 40 CFR 98.233(i)(2)(i) in 2015 (80 FR 64262, October 
22, 2015). We have reviewed this equation and have determined that this 
omission was inadvertent. Therefore, we are proposing to add provisions 
to equation W-14B of 40 CFR 98.233(i)(2)(i) to allow use of engineering 
estimates to determine the temperature and pressure of an emergency 
blowdown for both the geographically dispersed industry segments that 
currently report blowdown vent stack emissions (Onshore Natural Gas 
Transmission Pipeline and Onshore Petroleum and Natural Gas Gathering 
and Boosting) as well as the geographically dispersed industry segments 
that we are proposing would be required to begin reporting blowdown 
vent stack emissions as described in section III.C.1 of this preamble 
(Onshore Petroleum and Natural Gas Production and Natural Gas 
Distribution), consistent with equation W-14A.

K. Atmospheric Storage Tanks

    Facilities in the Onshore Petroleum and Natural Gas Production and 
Onshore Petroleum and Natural Gas Gathering and Boosting industry 
segments are currently required to report CO2 and 
CH4 emissions (and N2O emissions when flared) 
from atmospheric pressure fixed roof storage tanks receiving 
hydrocarbon liquids (hereafter referred to as ``atmospheric storage 
tanks'').\80\ Reporters with gas-liquid separators or onshore petroleum 
and natural gas gathering and boosting non-separator equipment (e.g., 
stabilizers, slug catchers) with annual average daily throughput of oil 
greater than or equal to 10 barrels per day are required to calculate 
annual CH4 and CO2 using Calculation Method 1 or 
2 as described in existing 40 CFR 98.233(j)(1) and (2), respectively. 
For wells flowing directly to atmospheric storage tanks without passing 
through a separator with throughput greater than or equal to 10 barrels 
per day, facilities must calculate annual CH4 and 
CO2 emissions using Calculation Method 2. For hydrocarbon 
liquids flowing to gas-liquid separators or non-separator equipment or 
directly to atmospheric storage tanks with throughput less than 10 
barrels per day, reporters must currently use Calculation Method 3 as 
specified in existing 40 CFR 98.233(j)(3) to calculate annual 
CO2 and CH4 emissions.
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    \80\ As described in section III.C.3 of this preamble, the EPA 
is proposing to revise the source type in 40 CFR 98.233(j) from the 
current name of ``onshore production and onshore petroleum and 
natural gas gathering and boosting storage tanks'' to ``hydrocarbon 
liquids and produced water storage tanks'' to reflect the proposal 
to require reporting of storage tank emissions from additional 
industry segments as well as to reflect the proposed addition of 
reporting for produced water storage tanks. When used to describe 
proposed amendments in this section, the general term ``atmospheric 
storage tanks'' applies to the group of hydrocarbon liquids and 
produced water storage tanks that would be reporting emissions if 
these proposed amendments are finalized.
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1. Open Thief Hatches
    The purpose of a thief hatch on an atmospheric storage tank is 
generally to allow access to the contents of the tank for sampling, 
gauging, and determining liquid levels. The thief hatch also works 
along with the vent valve to maintain safe tank operating pressures. 
The EPA previously evaluated emissions from atmospheric storage tanks 
as part of the 2016 amendments to subpart W (81 FR 86500, November 30, 
2016) and determined that the subpart W calculation methodology in 40 
CFR 98.233(j) already includes emissions from thief hatches or other 
openings on atmospheric storage tanks in the Onshore Petroleum and 
Natural Gas Production and Onshore Petroleum and Natural Gas Gathering 
and Boosting industry segments. The subpart W calculation methodologies 
for controlled atmospheric storage tanks include procedures for 
determining emissions from storage tanks with a vapor recovery system 
(existing 40 CFR 98.233(j)(4)) and storage tanks with a flare (existing 
40 CFR 98.233(j)(5)). The procedure for determining emissions from a 
tank with a vapor recovery system instructs reporters to adjust the 
storage tank emissions downward by the magnitude of emissions recovered 
using a vapor recovery system as determined by engineering estimate 
based on best available data (existing 40 CFR 98.233(j)(4)(i)). The 
procedure for determining emissions from an atmospheric storage tank 
with a flare references 40 CFR 98.233(n), which currently instructs 
reporters to use engineering calculations based on process knowledge, 
company records, and best available data to determine the flow to the 
flare if the flare does not have a continuous flow measurement device. 
If a reporter sees emissions from a thief hatch or other opening on a 
controlled atmospheric storage tank during an equipment leak survey

[[Page 50326]]

conducted using OGI, the reporter should consider that information as 
part of the ``best available data'' used to calculate emissions from 
that storage tank.
    However, it appears that reporters may not be accurately accounting 
for emissions from open thief hatches on atmospheric storage tanks, as 
many reporters claim 100 percent capture efficiency from vapor recovery 
systems and flares. In order to emphasize the original intent of the 
rule and ensure the accuracy of reported data, the EPA is proposing 
several clarifying edits to 40 CFR 98.233(j)(4) and (5) (which, as 
described in section III.K.3 of this preamble, would be combined in 
proposed 40 CFR 98.233(j)(4)), consistent with sections II.B and II.C 
of this preamble. We are proposing to specifically state that emissions 
during times of reduced capture efficiency are required to be evaluated 
to determine if adjustments are needed to the calculated recovered mass 
from vapor recovery units or total emissions vented to atmosphere from 
tanks. Reduced capture efficiency may occur during periods when the 
control device is not operating or is bypassed when the control device 
is operating, such as open thief hatches. The emissions that are not 
captured by a vapor recovery system or sent to a flare must be 
considered when calculating emissions from atmospheric storage tanks 
vented directly to the atmosphere using Calculation Methods 1, 2, or 3.
    Further, we are proposing to provide a calculation methodology for 
determining reduced capture efficiencies when a control device is in 
use but a thief hatch is not properly seated or closed. We are 
proposing to revise existing 40 CFR 98.233(j) to require facilities to 
assume that no emissions are captured by the control device (0 percent 
capture efficiency) when the thief hatch on a tank is open or not 
properly seated. As described above, emissions during this time would 
be reported as vented directly to the atmosphere as determined using 
Calculation Methods 1, 2, or 3. Additionally, in order to accurately 
quantify the time period that emissions are vented to atmosphere from 
an open or not properly seated thief hatch, consistent with section 
II.B of this preamble, the EPA is proposing in 40 CFR 98.233(j)(7) to 
require either the use of a thief hatch sensor, if present and 
operating, or if a thief hatch sensor is not present and operating, 
visual inspection of the tank to monitor the thief hatch. We are 
proposing that if a thief hatch sensor is present and operating on the 
tank, sensor data must be used to inform the periods of time that a 
thief hatch is open or not properly seated. The thief hatch sensor must 
be capable of transmitting and logging data whenever a thief hatch is 
open or not properly seated and when the thief hatch is subsequently 
closed. Visual inspections would be required once per calendar year, at 
a minimum, if a thief hatch sensor is not present and operating. If the 
thief hatch is required to be monitored as a fugitive emissions 
component to comply with NSPS OOOOb or the applicable EPA-approved 
state plan or the applicable Federal plan in 40 CFR part 62, we are 
proposing that visual inspections must be conducted at least as 
frequent as the required visual, audible, or olfactory fugitive 
emissions components surveys described in NSPS OOOOb or the applicable 
EPA-approved state plan or the applicable Federal plan in 40 CFR part 
62, or annually (whichever is more frequent). Similar to the provisions 
of 40 CFR 98.233(q), if one visual inspection is conducted in the 
calendar year and an open or not properly seated thief hatch is 
identified, the reporter would be required to assume that the thief 
hatch had been open for the entire calendar year. If multiple visual 
inspections are conducted in the calendar year and an open or not 
properly seated thief hatch is identified, the reporter would be 
required to assume that the thief hatch had been open since the 
preceding visual inspection (or the beginning of the year if the 
inspection was the first performed in a calendar year) through the date 
of the visual inspection (or the end of the year if the inspection was 
the last performed in a calendar year). As discussed in the TSD for the 
2016 amendments to subpart W, we determined that this methodology 
provides an accurate quantification of emissions and it is consistent 
with the timeframe required for subpart W annual reports.\81\ However, 
we are requesting comment on expanding the start date of the open thief 
hatch prior to the beginning of the reporting year. In this scenario, 
if the reporter can identify the start date and it spans reporting 
years, then that reporter would have to report the vented tank 
emissions from an open thief hatch that occurred in each reporting year 
and, if necessary, revise reports for the previous reporting year. The 
EPA is also seeking comment on alternative methodologies for 
quantifying the time that a thief hatch is left open or not properly 
seated in lieu of a required visual inspection.
---------------------------------------------------------------------------

    \81\ Greenhouse Gas Reporting Rule: Technical Support for Leak 
Detection Methodology Revisions and Confidentiality Determinations 
for Petroleum and Natural Gas Systems. November 1, 2016. Docket Id. 
No. EPA-HQ-OAR-2015-0764-0066; also available in the docket for this 
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    The EPA is also proposing revisions to the atmospheric storage tank 
reporting requirements in 40 CFR 98.236(j) with regard to open thief 
hatches. Specifically, the EPA is proposing to require reporting of the 
number of controlled atmospheric storage tanks with open or not 
properly seated thief hatches within the reporting year, as well as the 
total volume of gas vented through the open or not properly seated 
thief hatches, for all calculation methods. With these new reporting 
elements, the EPA seeks to quantify the impact of open thief hatches on 
atmospheric storage tanks and enhance the overall quality of the data 
collected under the GHGRP, consistent with section II.C of this 
preamble.
    Stakeholders have voiced concerns through the GHGRP Help Desk 
regarding the potential for double counting of tank thief hatch 
emissions under 40 CFR 98.236(j), (q) and (r). The EPA has previously 
confirmed that there is no potential for double counting thief hatches 
in the methodologies provided in 40 CFR 98.233(q) and 40 CFR 98.233(r), 
and we have also confirmed that there is no potential for double 
counting thief hatches based on the proposed revisions to 40 CFR 
98.236(j), (q) and (r). When determining leaks by population count per 
40 CFR 98.233(r), the EPA is proposing updated major equipment emission 
factors in existing Table W-1A (proposed Table W-1) that were developed 
using Rutherford et al. (2021). Population emission factors are 
presented by major equipment, which includes tanks--leaks; however, the 
major equipment indicating venting emissions (e.g., tanks--
unintentional vents) were not included. For equipment leak surveys per 
40 CFR 98.233(q), existing Table W-1E (proposed Table W-2) references 
40 CFR 98.232(c)(21) and (j)(10) for onshore petroleum and natural gas 
production and onshore petroleum and natural gas gathering and 
boosting, respectively. These provisions, which describe the list of 
components to be surveyed for equipment leaks, specifically state that 
thief hatches or other openings on a storage vessel should not be 
considered an ``other component.'' As such, we confirm that the 
proposed thief hatch emissions reporting requirements in 40 CFR 
98.236(j) would not overlap with the equipment leak emission reporting 
requirements in 40 CFR 98.236(q) and (r). Also, we confirm that the 
proposed thief hatch emissions reporting requirements would not overlap 
with

[[Page 50327]]

emissions reporting in 40 CFR 98.236(y). As stated in section III.B of 
this preamble, only thief hatch emissions that exceed the emissions 
estimated under 40 CFR 98.233(j) by 250 mtCO2e or more, or 
100 kg/hr of CH4 or more, would be included in the 
calculation and reporting requirements for ``other large release 
events.''
    The EPA is aware that there are circumstances other than open or 
not properly seated thief hatches in which the capture efficiency of 
the control device(s) for atmospheric storage tanks is reduced. These 
circumstances include, but are not limited to, when the control device 
is bypassed due to an open pressure relief device or when the 
atmospheric storage tank covers and closed vent systems have openings 
that allow emissions to vent directly to atmosphere. We are proposing 
in 40 CFR 98.233(j)(4)(i)(D) to require facilities to account for time 
periods of reduced capture efficiency from causes other than open or 
not properly seated thief hatches when determining total emissions 
vented directly to atmosphere based on best available data. However, we 
are requesting comment on methodologies other than best available data 
for identifying and quantifying time periods of reduced capture 
efficiency in these situations. For example, the EPA is requesting 
comment on the prevalence of pressure monitoring systems on atmospheric 
storage tanks, how pressure monitoring systems can be used to identify 
and determine the duration of periods of reduced capture efficiency due 
to open pressure relief devices, and the cost of those pressure 
monitoring systems.
2. Malfunctioning Dump Valves
    For Onshore Petroleum and Natural Gas Production and Onshore 
Petroleum and Natural Gas Gathering and Boosting facilities with 
atmospheric storage tank emissions calculated using Calculation Method 
1 (40 CFR 98.233(j)(1)) or Calculation Method 2 (40 CFR 98.233(j)(2)), 
reporters must also follow the procedures in current 40 CFR 
98.233(j)(6) (proposed 40 CFR 98.233(j)(5)) and use equation W-16 to 
calculate emissions from occurrences of gas-liquid separator dump 
valves not closing properly. Equation W-16 estimates the annual 
volumetric GHG emissions at standard conditions from each storage tank 
resulting from the malfunctioning dump valve on the gas-liquid 
separator using a correction factor, the total time the dump valve did 
not close properly in the calendar year, and the hourly storage tank 
emissions. Per the definition of the variable ``En'' in 
equation W-16, the input hourly storage tank emissions should be those 
calculated using Calculation Methods 1 or 2 and should be adjusted 
downward by the magnitude of emissions recovered using a vapor recovery 
system, if applicable. The EPA is proposing to revise the equation 
variables (particularly the subscripts) in equation W-16 to clarify the 
intent of this equation. We are proposing to revise the variable 
``En'' to ``Es,i'' to further clarify that these 
are the volumetric atmospheric storage tank emissions determined using 
the procedures in 40 CFR 98.233(j)(1), (2), and (4). We are also 
proposing to replace the ``n'' and ``o'' subscripts in the other 
variables with a ``dv'' subscript to indicate that these are the 
emissions from periods when the gas-liquid separator dump valves were 
not closed properly and that the emissions from these periods should be 
added to the emissions determined using the procedures in 40 CFR 
98.233(j)(1), (2), and (4).
    One of the inputs to equation W-16 is the total time the dump valve 
did not close properly in the calendar year (Tn). Currently, 
Tn may be estimated based on maintenance, operations, or 
routine separator inspections that indicate the period of time when the 
valve was malfunctioning in open or partially open position. In order 
to improve the quality of the open dump valve emissions data collected, 
consistent with section II.C of this preamble, the EPA is proposing to 
formalize the requirement to perform routine visual inspections of 
separator dump valves to determine if the valve is stuck in an open 
position, thus allowing gas carry-through to the controlled tank(s).
    The EPA is proposing to revise the current provisions in 40 CFR 
98.233(j)(6) (which is proposed 40 CFR 98.233(j)(5)) to require visual 
inspection of the gas-liquid separator and determine if the liquid dump 
valve is stuck in an open or partially open position. Incorporating 
this proposed monitoring requirement would result in a more realistic 
time estimate being used in equation W-16 and thus, more accurate 
emissions reporting, consistent with section II.B of this preamble. 
Visual inspections would be required once per calendar year, at a 
minimum. Similar to the provisions of 40 CFR 98.233(q) and the proposed 
section 40 CFR 98.233(j)(7), if one visual inspection is conducted in 
the calendar year and a stuck dump valve is identified, the reporter 
would be required to assume that the dump valve had been stuck open for 
the entire calendar year. If multiple visual inspections are conducted 
in the calendar year and a stuck dump valve is identified, the reporter 
would be required to assume that the dump valve had been stuck open 
since the preceding visual inspection (or the beginning of the year if 
the inspection was the first performed in a calendar year) through the 
date of the visual inspection (or the end of the year if the inspection 
was the last performed in a calendar year). As discussed in the TSD for 
the 2016 amendments to subpart W, we determined that this methodology 
provides an accurate quantification of emissions and it is consistent 
with the timeframe required for subpart W annual reports.\82\ We are 
requesting comment on expanding the start date of the open thief hatch 
prior to the beginning of the reporting year. In this scenario, if the 
reporter can identify the start date and it spans reporting years, then 
that reporter would have to report the vented tank emissions from an 
open thief hatch that occurred in each reporting year and, if 
necessary, revise reports for the previous reporting year.
---------------------------------------------------------------------------

    \82\ Greenhouse Gas Reporting Rule: Technical Support for Leak 
Detection Methodology Revisions and Confidentiality Determinations 
for Petroleum and Natural Gas Systems. November 1, 2016. Docket Id. 
No. EPA-HQ-OAR-2015-0764-0066; also available in the docket for this 
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

3. Applicability and Selection of Appropriate Calculation Methodologies 
for Atmospheric Storage Tanks
    When determining the applicability of the different calculation 
methodologies described in existing 40 CFR 98.233(j), reporters must 
calculate their annual average daily throughput to determine whether 
flow of hydrocarbon liquids through the gas-liquid separator, well, or 
non-separator equipment is greater than or equal to 10 barrels per day. 
Through the GHGRP Help Desk and correspondence with the EPA via e-GGRT, 
it appears that reporters may be misinterpreting how hydrocarbon liquid 
throughputs from gas-liquid separators should be determined. 
Specifically, reporters appear to have differing conclusions regarding 
whether the throughput determination should be based on flow into or 
out of the separator and whether days when the separator was not 
operating should be included when calculating the annual average. 
Therefore, we are proposing revisions to the introductory text of 40 
CFR 98.233(j) to emphasize the original intent of how the hydrocarbon 
liquid throughputs should be determined. Specifically, we are proposing 
to add language that clearly states that the annual average daily 
throughput of hydrocarbon liquids should be based on

[[Page 50328]]

flow out of the separator, well, or non-separator equipment determined 
over the actual days of operation. This amendment is expected to 
clarify the rule, consistent with II.D of this preamble and improve the 
quality of the data collected, consistent with section II.C of this 
preamble.
    For hydrocarbon liquids flowing to gas-liquid separators or non-
separator equipment or directly to atmospheric storage tanks with 
throughput greater than 0 barrels per day and less than 10 barrels per 
day, reporters currently use population emission factors and equation 
W-15 to calculate volumetric CO2 and CH4 
emissions per Calculation Method 3 (40 CFR 98.233(j)(3)) and report 
emissions per 40 CFR 98.236(j)(2). However, facilities with hydrocarbon 
liquids flowing to gas-liquid separators or non-separator equipment or 
directly to atmospheric storage tanks with throughput greater than or 
equal to 10 barrels per day are given the option to either model their 
tanks per Calculation Method 1 (40 CFR 98.233(j)(1)) or use a mass 
balance approach per Calculation Method 2 (40 CFR 98.233(j)(2)). 
Through the GHGRP Help Desk and correspondence with the EPA via e-GGRT, 
reporters have expressed the desire to use Calculation Methods 1 or 2 
for reporting emissions from storage tanks currently required to use 
Calculation Method 3, as they stated that the population emission 
factors provided in 40 CFR 98.233(j)(3) are not always representative 
of their tanks' actual emissions. Calculation Methods 1 and 2 require 
unit-specific inputs, so it is reasonable to expect that they would 
result in more accurate emissions estimates for atmospheric storage 
tanks that have differing operating characteristics than those used to 
develop the Calculation Method 3 emission factors. Therefore, the EPA 
is proposing to amend the requirements in 40 CFR 98.233(j) to specify 
reporters may use Calculation Method 1, Calculation Method 2, or 
Calculation Method 3 when determining emissions from hydrocarbon 
liquids flowing to wells, gas-liquid separators, or non-separator 
equipment with throughput greater than 0 barrels per day and less than 
10 barrels per day. We are also proposing to specify in 40 CFR 
98.233(j) that if a reporter is required or elects to perform emissions 
modeling of an atmospheric storage tank consistent with the methodology 
outlined in 40 CFR 98.233(j)(1), they must use the results of the model 
for estimating emissions under 40 CFR 98.233(j). It is the EPA's 
intention with this proposal that if reporters conduct modeling for 
environmental compliance or reporting purposes, including but not 
limited to compliance with Federal or state regulations, air permit 
requirements, annual inventory reporting, or internal review, they 
would use those results for reporting under subpart W. Consistent 
revisions are also proposed for the reporting requirements in 40 CFR 
98.236(j). These amendments are expected to improve the quality of the 
data collected and provide flexibility to reporters, consistent with 
section II.D of this preamble.
    The current requirements in 40 CFR 98.233(j) require calculation of 
emissions from atmospheric pressure fixed roof storage tanks. As 
discussed in section III.C of this preamble, the EPA evaluated the 
sources included in present-day inventories of the oil and gas industry 
in comparison with sources covered in subpart W and is proposing to 
include additional sources in subpart W as a result of this evaluation. 
Based on a similar evaluation, we are proposing to remove the ``fixed 
roof'' language when referring to atmospheric pressure storage tanks 
subject to 40 CFR 98.233(j). This would expand the reporting of tank 
emissions to include floating roof tanks, which are a source included 
in the 2022 U.S. GHG Inventory for the petroleum industry. We are also 
proposing revisions to existing 40 CFR 98.236(j)(1)(x) and existing 40 
CFR 98.236(j)(2)(i) to require separate reporting of the total count of 
fixed roof and floating roof tanks at the facility. To provide 
additional clarity for this proposed amendment, we are also proposing 
to revise all instances of ``storage tanks,'' ``atmospheric tanks,'' 
and ``tanks'' in 40 CFR 98.233(j) and 40 CFR 98.236(j) to instead use 
the term ``atmospheric pressure storage tanks.'' We are proposing to 
define an atmospheric pressure storage tank as ``a vessel (excluding 
sumps) operating at atmospheric pressure that is designed to contain an 
accumulation of crude oil, condensate, intermediate hydrocarbon 
liquids, or produced water and that is constructed entirely of non-
earthen materials (e.g., wood, concrete, steel, plastic) that provide 
structural support. Atmospheric pressure storage tanks include both 
fixed roof tanks and floating roof tanks. Floating roof tanks include 
tanks with either an internal floating roof or an external floating 
roof.'' We expect these proposed amendments would improve the overall 
quality and completeness of the emissions data collected by the GHGRP, 
consistent with section II.A of this preamble.
4. Controlled Atmospheric Storage Tanks
    In correspondence with the EPA via e-GGRT, some reporters have 
asked the EPA for guidance regarding calculating emissions from 
atmospheric storage tanks that are routed to different control devices 
throughout the reporting year (e.g., tanks that are routed to vapor 
recovery and subsequently vented to atmosphere or routed to a flare 
when the vapor recovery device is not operating). Given the proposed 
amendments to the calculation methodology and reporting of flare stack 
emissions (discussed in section III.N of this preamble), we are 
proposing to revise the methodologies for calculating emissions from 
tanks controlled by a vapor recovery system or a flare currently 
provided in 40 CFR 98.233(j)(4) and (5), respectively. The new language 
in proposed 40 CFR 98.233(j)(4)(i) provides a methodology for 
calculating emissions vented to atmosphere during periods of reduced 
capture efficiency of the vapor recovery system or flare (e.g., when a 
thief hatch is open or not properly seated). The provisions of proposed 
40 CFR 98.233(j)(4)(ii) would require facilities to use engineering 
estimates based on best available data to calculate recovered mass from 
vapor recovery systems, and also clarifies that reporters must take 
into account periods with reduced capture efficiency of the vapor 
recovery system (e.g., when a thief hatch is open or not properly 
seated or when the vapor recovery system is down for maintenance) when 
calculating mass recovered. For flared atmospheric storage tank 
emissions, the proposed 40 CFR 98.233(j) provisions would direct 
reporters to the proposed methodologies in 40 CFR 98.233(n). By 
proposing these amendments, the EPA seeks to enhance the overall 
quality of the data collected under the GHGRP, consistent with section 
II.D of this preamble.
5. Calculation Methods 1 and 2 for Atmospheric Storage Tanks
    Reporters with atmospheric storage tanks that calculate emissions 
using Calculation Method 1 are currently required to determine 
emissions using any standard simulation software package that uses the 
Peng-Robinson equation of state, models flashing emissions, and 
speciates CH4 and CO2 emissions from the 
atmospheric storage tank. According to current 40 CFR 98.233(j)(1), the 
information that must be used to characterize emissions include 
separator or non-separator equipment temperature and pressure, sales or 
stabilized hydrocarbon liquids API gravity, sales or stabilized

[[Page 50329]]

hydrocarbon liquids production rate, ambient air temperature and 
pressure, and separator or non-separator equipment hydrocarbon liquids 
composition and Reid vapor pressure. These parameters currently must be 
determined for typical operating conditions over the calendar year by 
engineering estimate and process knowledge based on best available 
data. Consistent with section II.B of this preamble, we are proposing 
that the input parameters related to the hydrocarbon liquid stream that 
are used for the simulation software must be obtained by 
measurement.\83\ Those parameters include separator or non-separator 
equipment temperature and pressure, sales or stabilized hydrocarbon 
liquids API gravity, sales or stabilized hydrocarbon liquids production 
rate, and separator or non-separator equipment hydrocarbon liquids 
composition and Reid vapor pressure. We are proposing that reporters 
would collect measurements reflective of representative operating 
conditions over the time period covered by the simulation. We are not 
proposing to change the requirement that the other parameters must be 
determined for operating conditions based on engineering estimate and 
process knowledge.
---------------------------------------------------------------------------

    \83\ As described in section III.C.3 of this preamble, the EPA 
is also proposing to expand the applicability of 40 CFR 98.233(j)(1) 
to include produced water tanks.
---------------------------------------------------------------------------

    We are also proposing that the parameters that must be used to 
characterize emissions should reflect operating conditions over the 
time period covered by the simulation rather than just over the 
calendar year. Under this proposed change, reporters could continue to 
run the simulation once per year with parameters that are determined to 
be representative of operating conditions over the entire year. 
Alternatively, reporters would be allowed to conduct periodic 
simulation runs to cover portions of the calendar year, as long as the 
entire calendar year is covered. The reporter would then sum the 
results at the end of the year to determine annual emissions. In that 
case, the parameters for each simulation run would be determined for 
the operating conditions over each corresponding portion of the 
calendar year.
    For reporters with atmospheric storage tanks that calculate 
emissions using Calculation Method 2, all CH4 and 
CO2 in solution are assumed to be emitted from hydrocarbon 
liquids. For flow to storage tanks after passing through a separator, 
the CH4 and CO2 in solution is determined by 
taking a sample of separator hydrocarbon liquids at separator pressure 
and temperature. However, for flow to atmospheric storage tanks direct 
from wells and flow to atmospheric storage tanks direct from non-
separator equipment, facilities may only use either the latest 
compositional analysis already available at the facility or default 
liquid and gas compositions from modeling software programs to 
determine the CH4 and CO2 in solution; there is 
currently no requirement to take a representative sample during the 
calendar year. Consistent with these proposed amendments for 
atmospheric tanks with emissions calculated using Calculation Method 1, 
the EPA is proposing that the composition of the liquids flowing to all 
tanks with emissions calculated using Calculation Method 2 must be 
obtained by measurement, regardless of the source from which the 
liquids are supplied. We are proposing to remove the provisions of 40 
CFR 98.233(j)(2)(ii) and (iii) that allowed for representative 
compositions to be used for tanks receiving liquids directly from wells 
or non-separator equipment. These amendments are expected to improve 
the accuracy of the data collected under the GHGRP, consistent with 
section II.B of this preamble.
    Similar to the provision for dehydrators in 40 CFR 98.233(e)(1), 
subpart W currently provides two example software options, AspenTech 
HYSYS[supreg] or API 4697 E&P Tank, that meet the software requirements 
in 40 CFR 98.233(j)(1). Under the existing requirements, reporters are 
not limited using to these two software options when complying with 40 
CFR 98.233(j)(1). However, many reporters have been using BRE's ProMax 
software to model their tank emissions. In RY2021, based on responses 
to 40 CFR 98.236(j)(1)(ii) (name of the software package used if using 
Calculation Method 1), 59 percent of facilities reporting emissions 
from Calculation Method 1 atmospheric storage tanks used ProMax as 
their modeling software, compared to 30 percent using API 4697 E&P Tank 
and 6 percent using AspenTech HYSYS[supreg]. Given the significant 
majority of reporters using ProMax, and considering our proposed 
addition and supporting rationale of ProMax to the list of example 
software options in 40 CFR 98.233(e)(1), we are proposing to add ProMax 
as an example software program for calculating atmospheric tank 
emissions per 40 CFR 98.233(j)(1). Consistent with the EPA's proposed 
revisions to 40 CFR 98.233(e)(1), the EPA is proposing to require 
ProMax version 5.0 or above. We expect these proposed amendments would 
improve the quality of the data collected, consistent with section II.C 
of this preamble.
    Additionally, we are aware that several process simulation software 
options have the ability to model emissions from atmospheric storage 
tanks that are receiving hydrocarbon liquids directly from wells. As 
such, the EPA is proposing to amend 40 CFR 98.233(j) such that 
facilities with wells flowing directly to atmospheric storage tanks 
without passing through a separator may use either Calculation Method 
1, Calculation Method 2, or, for wells, gas-liquid separators, or non-
separator equipment with annual average daily throughput less than 10 
barrels per day, Calculation Method 3. We are also proposing conforming 
edits within 40 CFR 98.233(j)(1) and (2) and 40 CFR 98.236(j)(1) to 
refer to parameters and requirements for wells flowing directly to 
atmospheric storage tanks. These proposed amendments are expected to 
improve the accuracy of reported emissions, consistent with section 
II.B of this preamble.
    Stakeholders have indicated through correspondence with the EPA via 
e-GGRT and the GHGRP Help Desk that flash emissions from atmospheric 
storage tanks are often determined through laboratory measurement of 
separator liquid gas to oil ratio (GOR). This emission calculation 
methodology involves taking a pressurized sample of crude or condensate 
from an upstream vessel (separator or non-separator equipment) and 
flashing the sample in a laboratory. To do this, part of the sample is 
brought to sampling temperature and pressure conditions, while another 
portion of the sample is brought to storage tank temperature and 
pressure conditions. The amount of gas released per volume of oil 
generated is measured to estimate the GOR. The chemical composition of 
the flash gas is then analyzed and the CH4 and 
CO2 concentrations are determined. The GHG emissions can be 
estimated by multiplying the GOR by the crude oil or condensate 
throughput, and then applying the CH4 and/or CO2 
composition to the total gas rate to estimate the CH4 and/or 
CO2 emissions from the atmospheric storage tank. The EPA has 
determined that this methodology does not meet the requirements of 
Calculation Method 1 (as the emissions are not calculated using a 
modeling software) or Calculation Method 2 (as the emissions are not 
calculated assuming that all the CH4 and CO2 in 
solution at separator temperature and pressure is emitted).

[[Page 50330]]

However, upon review of storage tank emissions calculation guidance 
from states such as Louisiana \84\ and Texas,\85\ it appears that 
companies may be performing this testing to meet state-level 
requirements. Additionally, this methodology is included in the 2021 
API Compendium as an option for determining atmospheric storage tank 
emissions.
---------------------------------------------------------------------------

    \84\ Louisiana Department Of Environmental Quality. ``Flash Gas 
Calculation Methods.'' https://www.deq.louisiana.gov/page/flash-gas-calculation-methods.
    \85\ Texas Commission on Environmental Quality Air Permits 
Division. May 2012. Calculating Volatile Organic Compounds (VOC) 
Flash Emissions from Crude Oil and Condensate Tanks at Oil and Gas 
Production Sites. Air Permit Reference Guide APDG 5942. Available at 
https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/guidance_flashemission.pdf and in the docket for 
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    Therefore, we are seeking comment on adding laboratory measurement 
of the GOR from a pressurized liquid sample as a new emission 
calculation methodology for atmospheric storage tanks under 40 CFR 
98.233(j). If this methodology were to be added to 40 CFR 98.233(j), we 
anticipate providing an equation that would multiply the measured GOR 
by the annual throughput of the hydrocarbon liquid stream to the 
atmospheric storage tank (in barrels per year) to obtain the annual 
volumetric flash gas emissions. The CO2 and CH4 
emissions from the atmospheric storage tank would then be calculated 
using CO2 and CH4 flash gas concentrations 
determined from the laboratory analysis. Facilities utilizing this 
methodology would report all data elements required under 40 CFR 
98.236(j)(1), consistent with the reporting for Calculation Methods 1 
and 2. We would also require additional data elements associated 
specifically with this new calculation method, such as the annual 
average GOR and total days of operation of the atmospheric storage 
tank(s) at the facility, well-pad, or gathering and boosting site. We 
specifically request comment on the accuracy of this methodology for 
calculating GHG emissions (with emphasis on comparison with Calculation 
Method 1 modeling), as well as how extensive its use may be in the oil 
and gas industry.
6. Calculation Methods 1 and 2 Reporting
    For facilities reporting atmospheric storage tank emissions 
calculated using Calculation Method 1 or Calculation Method 2, 40 CFR 
98.236(j)(1) currently requires reporting of counts of the total number 
of atmospheric storage tanks within the sub-basin or county (40 CFR 
98.236(j)(1)(x)), the number of atmospheric storage tanks that are 
controlled by a vapor recovery system (40 CFR 98.236(j)(1)(xii)(A)), 
the number of atmospheric storage tanks that are controlled by a flare 
(40 CFR 98.236(j)(1)(xiv)(A)), and the number of atmospheric storage 
tanks that are not controlled by either a vapor recovery system or a 
flare (40 CFR 98.236(j)(1)(xiii)(A)).\86\ Given the proposed amendments 
to require reporting of CO2, CH4, and 
N2O emissions from atmospheric storage tanks controlled by a 
flare under 40 CFR 98.236(n) (discussed in section III.N of this 
preamble), the EPA is proposing to reorganize the reporting 
requirements in 40 CFR 98.236(j)(1) to collect each of these tank 
counts under 40 CFR 98.236(j)(1)(x)(A) through (F).\87\ The EPA is also 
proposing to move the reporting of CO2 and CH4 
vented emissions and recovered mass to paragraph 40 CFR 
98.236(j)(1)(xi) through (xiv). With this reorganization of the 
emissions reporting requirements for atmospheric storage tanks, the EPA 
expects to improve verification of atmospheric storage tank emissions, 
consistent with section II.C of this preamble.
---------------------------------------------------------------------------

    \86\ In the 2022 Proposed Rule, the EPA proposed updates to the 
tank count reporting requirements in current 40 CFR 98.236(j)(1). 
These revisions are not included in this proposal, as the current 
tank count reporting requirements better align with the proposed 
flare stack revisions discussed in section III.N of this preamble.
    \87\ 87 As discussed in section III.K.3 of this preamble, the 
EPA is expanding this source to include both fixed roof and floating 
roof atmospheric storage tanks. The total count of tanks within the 
facility is proposed to be further divided into the count of fixed 
roof atmospheric storage tanks and the count of floating roof 
atmospheric storage tanks. Also, as discussed in section III.K.1 of 
this preamble, the EPA is also proposing to collect the count of 
controlled atmospheric storage tanks with open or not properly 
seated thief hatches.
---------------------------------------------------------------------------

    Additionally, the EPA is proposing to remove the requirement to 
report an estimate of the number of atmospheric storage tanks that are 
not on well-pads and that are receiving the facility's oil (existing 40 
CFR 98.236(j)(1)(xi)), consistent with section II.C of this preamble. 
This reporting requirement is currently, and under the proposed rule 
would still be, redundant because all Onshore Petroleum and Natural Gas 
Production facilities reporting atmospheric storage tank emissions 
calculated using Calculation Method 1 or Calculation Method 2 must also 
report the total number of atmospheric storage tanks in the sub-basin 
per existing 40 CFR 98.236(j)(1)(x) (proposed to be revised to the 
total number of atmospheric storage tanks at the well-pad).
    Under 40 CFR 98.236(j)(1)(vii) and (viii), reporters with 
atmospheric storage tank emissions calculated using Calculation Method 
1 or Calculation Method 2 are currently required to provide the minimum 
and maximum concentrations (mole fractions) of CO2 and 
CH4 in the tank flash gas. Reporting of emissions and 
activity data for atmospheric storage tanks is aggregated at the sub-
basin or county level under the current regulations, and the minimum 
and maximum flash gas concentrations were expected to provide the EPA 
with a broad characterization of the often-significant number of tanks 
reported for each sub-basin or county. However, through correspondence 
with reporters via e-GGRT, the EPA has found that the minimum and 
maximum flash gas concentrations do not accurately represent the 
majority of atmospheric storage tanks within the reported sub-basins 
and counties. Thus, the EPA is proposing to revise these two reporting 
requirements to request the flow-weighted average concentration (mole 
fraction) of CO2 and CH4 in the flash gas, rather 
than the minimum and maximum values. These values would be calculated 
as the sum of all products of the concentration of CO2 or 
CH4 in the flash gas for each storage tank times the total 
quantity of flash gas for that storage tank, divided by the sum of all 
flash gas emissions from storage tanks. The concentration of 
CO2 or CH4 in the flash gas and the throughput 
for each storage tank would be determined using the methodologies in 
Calculation Method 1 or Calculation Method 2. Consistent with section 
II.C of this preamble, the EPA expects that these revisions would 
improve both the representative nature of the data collected and the 
process of verifying annual reported atmospheric storage tanks 
emissions data under the GHGRP.
7. Calculation Method 3 for Atmospheric Storage Tanks
    For hydrocarbon liquids flowing to storage tanks from gas-liquid 
separators or non-separator equipment or directly to atmospheric 
storage tanks with throughput less than 10 barrels per day, reporters 
currently use population emission factors and equation W-15 to 
calculate volumetric CO2 and CH4 emissions per 40 
CFR 98.233(j)(3) and report emissions per 40 CFR 98.236(j)(2). Under 
these current requirements, the count of separators, wells, or non-
separator equipment with annual average daily throughput less than 10 
barrels per day could include separators, wells, or non-separator

[[Page 50331]]

equipment with annual average daily hydrocarbon liquids throughput of 0 
barrels (i.e., separators, wells, or non-separator equipment that were 
not operated during the reporting year). As a result, some annual 
reports include a nonzero count of wells with and without separators 
per existing 40 CFR 98.236(j)(2)(i)(E) and (F) (which, as described in 
section III.K.7 of this preamble, would be combined in proposed 40 CFR 
98.236(j)(2)(ii)(E) and are proposed to be revised to the total number 
of separators, wells, or non-separator equipment to better match 
``Count'' from equation W-15) without any corresponding CO2 
and CH4 emissions. In these cases, it is not clear if the 
reporter did not report emissions because emissions are not expected, 
the emissions data were inadvertently omitted, or the nonzero count of 
all wells and separators includes those that had no throughput.
    Therefore, the EPA is proposing to clarify in 40 CFR 98.233(j)(3) 
that the separators, wells, or non-separator equipment for which 
emissions are calculated should be those with annual average daily 
hydrocarbon liquids throughput greater than 0 barrels per day and less 
than 10 barrels per day (i.e., the count should not include separators, 
wells, or non-separator equipment that had no throughput during the 
year). Similarly, we are proposing to clarify that the count of 
separators, wells, or non-separator equipment to report under proposed 
40 CFR 98.236(j)(2)(ii)(E) should also be those with annual average 
daily hydrocarbon liquids throughput greater than 0 barrels per day and 
less than 10 barrels per day. These amendments are expected to improve 
the quality of the data collected, consistent with section II.C of this 
preamble.
8. Calculation Method 3 Reporting
    The provisions in existing 40 CFR 98.236(j)(2)(ii) and (iii) 
currently require facilities to separately report Calculation Method 3 
emissions from atmospheric storage tanks that did not control emissions 
with flares and those that controlled emissions with flares, 
respectively. As discussed in section III.N of this preamble, the EPA 
is proposing new reporting requirements for atmospheric storage tanks 
controlled by flares. The proposed revisions would require all flared 
emissions from atmospheric storage tanks with emissions calculated 
using Calculation Method 3 to be reported under 40 CFR 98.236(n). 
Therefore, the EPA is proposing to require reporting of all Calculation 
Method 3 emissions that are vented directly to atmosphere under 40 CFR 
98.233(j)(2)(ii).\88\ We are proposing to no longer require separate 
reporting of Calculation Method 3 emissions from atmospheric storage 
tanks that did not control emissions with flares and those that 
controlled emissions with flares. This proposed reporting structure 
would be similar to the emissions reporting structure for Calculation 
Methods 1 and 2 atmospheric storage tanks. Further discussion on the 
reasoning behind these proposed revisions is provided in section III.N 
of this preamble. In the 2022 Proposed Rule, we proposed to revise the 
reporting structure to specify that the reporting requirements in the 
current 40 CFR 98.236(j)(2)(iii) only apply to tanks whose emissions 
were calculated using Calculation Method 3 that used flares to control 
emissions from at least half the annual hydrocarbon liquids received. 
As this proposed amendment would not be consistent with the revisions 
to the flare stack reporting requirements discussed in section III.N of 
this preamble, the EPA is not including these revisions in this 
proposal.
---------------------------------------------------------------------------

    \88\ As described in section III.C.3 of this preamble, the EPA 
is proposing new reporting requirements in 40 CFR 98.233(j)(2)(iii) 
for produced water tanks.
---------------------------------------------------------------------------

    For hydrocarbon liquids flowing to gas-liquid separators or non-
separator equipment or directly to atmospheric storage tanks with 
throughput less than 10 barrels per day, reporters currently follow the 
Calculation Method 3 methodology specified in 40 CFR 98.233(j)(3) and 
equation W-15 (proposed equation W-15A). Equation W-15 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 40 CFR 98.236(j)(2)(i)(E) through (F) require reporters to delineate 
the count used in equation W-15 into the number of wells with gas-
liquid separators in the basin and those without gas-liquid separators. 
After reviewing these reporting requirements, the EPA has made a 
preliminary determination that they are not consistent with the 
language used in the definition of the ``Count'' variable in equation 
W-15, nor are they inclusive of all equipment to be included in the 
count. Therefore, the EPA is proposing to revise existing 40 CFR 
98.236(j)(2)(i)(E) and (F), in combined proposed 40 CFR 
98.236(j)(2)(ii)(E), to completely align the reporting requirement with 
the total ``Count'' input variable in equation W-15. We are also 
proposing to collect this information at the well-pad, gathering and 
boosting site, or facility level. The EPA proposes to amend the 
language in proposed 40 CFR 98.236(j)(2)(ii)(E) to request the total 
number of separators, wells, or non-separator equipment used to 
calculate Calculation Method 3 storage tank emissions. The current 
language in existing 40 CFR 98.236(j)(2)(i)(E) requests the number of 
wells with gas-liquid separators in the basin, which is only a subset 
of the equipment included in the ``Count'' variable. Further, the EPA 
is proposing to remove the reporting requirement in existing 40 CFR 
98.236(j)(2)(i)(F) that requires reporting of the number of wells 
without gas-liquid separators in the basin. These changes would ensure 
the consistency of the requirements for all facilities reporting 
atmospheric storage tanks emissions using Calculation Method 3 and 
provide activity data that better correlates with the calculated 
Calculation Method 3 atmospheric tank emissions. Consistent with 
section II.C of this preamble, reporters would no longer be required to 
determine two separate counts that may not align with the inputs used 
in equation W-15.

L. Flared Transmission Storage Tank Vent Emissions

    Reporters in the transmission compression industry segment 
currently are required to report flared emissions specific to their 
transmission storage tanks under 40 CFR 98.236(k), separately from 
other flare stack emissions. In the years RY2015 through RY2020, 
between one and six facilities per year reported having a transmission 
tank vent stack routed to a flare, and each of these facilities 
reported no dump valve leakage from the tanks that were routed to 
flares. As a result, the reported flared emissions from transmission 
storage tank vent stacks in each of the last 6 years have been 0 mt of 
CO2, CH4, and N2O. Based on these 
results, the EPA has made a preliminary determination that including 
flared emissions from transmission storage tank vents in the group of 
``other flared sources'' instead of continuing to report source-
specific flared emissions from transmission tanks would not affect data 
quality or accuracy, nor would it significantly impact the EPA's 
knowledge of the industry sector, emissions or trends. Therefore, 
consistent with section II.C of this preamble, the EPA is proposing 
that transmission storage tanks (proposed to be renamed ``condensate 
storage tanks'' as described in section III.C.1 of this preamble) be 
classified as an ``other'' flared source such that any flared emissions 
from the tanks in the future would be reported only as part of the

[[Page 50332]]

total emissions from the flare. The proposed disaggregation of total 
flare emissions to individual source types as described in section 
III.N of this preamble would not apply to condensate storage tanks.
    To implement this change for condensate storage tanks that are 
connected to a flare, the EPA is proposing to remove the current 
requirements in 40 CFR 98.233(k)(5) that require reporters to monitor 
the tank vent stack annually for leaks and to quantify the leak rate if 
a leak is detected. Reporting requirements would remain essentially the 
same except that flared mass emissions would no longer be reported 
under 40 CFR 98.236(k)(3). Note that if we decide not to finalize the 
proposed changes described in this section after considering public 
comment, then we alternatively propose that we would finalize 
provisions applying the proposed flare emissions disaggregation 
requirements as described in section III.N of this preamble to flared 
emissions from condensate storage tank vent stacks, consistent with the 
proposed disaggregation of emissions for other source types. Under this 
alternative, condensate storage tanks would be added to the list of 
source types in proposed 40 CFR 98.233(n)(10) for which disaggregation 
would be required. We would also not finalize the proposal to remove 
the current requirements in 40 CFR 98.233(k)(5) to monitor and quantify 
leak rates because it would not be possible to tell how much of the 
total flare emissions should be disaggregated to condensate storage 
tanks if the scrubber dump valve leakage is not monitored. We request 
comment on the advantages and disadvantages of both approaches we are 
considering relative to the current requirements.

M. Associated Gas Venting and Flaring

1. Associated Gas Venting
    Associated gas venting or flaring is the venting or flaring of 
natural gas that originates at wellheads that also produce hydrocarbon 
liquids and occurs either in a discrete gaseous phase at the wellhead 
or is released from the liquid hydrocarbon phase by separation. Venting 
associated gas involves directly releasing associated gas into the 
atmosphere at the well-pad or tank battery. Flaring associated gas is a 
common, and usually preferred, alternative to venting for safety and 
environmental reasons. Subpart W currently requires reporters to 
calculate annual emissions from associated gas venting and flaring 
using equation W-18, which uses the GOR, volume of oil produced, and 
volume of associated gas sent to sales to calculate the volume of gas 
vented. Associated gas venting emissions are then calculated using the 
results of equation W-18 and the gas composition determined using 40 
CFR 98.233(u), and associated gas flaring emissions are calculated by 
applying the calculation method of flare stacks in 40 CFR 98.233(n) to 
the associated natural gas volume and gas composition determined for 
the associated gas stream routed to the flare.
    For associated gas venting emissions, we are proposing provisions 
in 40 CFR 98.233(m)(3) to specify that if the reporter measures the 
flow to a vent using a continuous flow measurement device the reporter 
must use the measured flow volumes to calculate the volume of gas 
vented rather than using equation W-18. This proposed amendment would 
add calculation methodologies based on measurements and improve the 
accuracy of the data collected, consistent with section II.B of this 
preamble. We are proposing corresponding reporting requirements for 
associated gas venting emissions in 40 CFR 98.236(m)(7), including 
requiring an indication of whether a continuous flow monitor or 
continuous composition analyzer was used. We are also proposing to 
require reporting of the flow-weighted mole fractions of CH4 
and CO2 and the total volume of associated gas vented from 
the well, in standard cubic feet for all wells whether using GOR or 
continuous flow measurement devices. Finally, we are proposing to 
specify that if the volumetric emissions from associated gas venting 
and flaring were determined using a continuous flow measurement device 
rather than equation W-18, then reporting of the inputs to equation W-
18, including the GOR, the volume of oil produced, and the volume of 
gas sent to sales for wells with associated gas venting or flaring, 
would not be required for that well. We request comment on whether we 
should continue to require reporting of these data elements even if 
they are not used as inputs to an emissions calculation. 40 CFR 
98.236(m)(7)(i) currently requires the reporter to provide the total 
number of wells and a list of well IDs in the sub-basin for wells that 
vented associated gas emissions. As noted in section III.D of this 
preamble, however, the EPA is proposing that reporters begin reporting 
information for this emission source by well rather than at the sub-
basin level. Therefore, we are proposing to remove this reporting 
requirement. The well ID would be reported for each vented well under 
proposed 40 CFR 98.236(m)(1) and the total number of wells reported at 
the sub-basin level is no longer necessary, because we are proposing to 
require reporting at the well level for associated gas venting rather 
than the sub-basin level.
    As discussed further in section III.N of this preamble, the EPA is 
proposing several amendments to the calculation and reporting 
requirements for flare stacks that would impact associated gas flaring 
emissions calculations in existing 40 CFR 98.233(m)(5) and reporting in 
existing 40 CFR 98.236(m)(8). As a result, the EPA is proposing to 
remove existing 40 CFR 98.233(m)(5) and instead direct reporters to 40 
CFR 98.233(n) to calculate emissions from associated gas flaring. The 
EPA is also proposing to remove 40 CFR 98.236(m)(8), as flared 
emissions would be reported under 40 CFR 98.236(n). In addition to 
flared emissions, 40 CFR 98.236(m)(8)(i) currently requires the 
reporter to provide a list of well IDs in the sub-basin for wells that 
flared associated gas emissions. As noted in section III.D of this 
preamble, however, the EPA is proposing that reporters begin reporting 
information for this emission source by well rather than at the sub-
basin level. Existing 40 CFR 98.236(m)(3) requires reporters to 
indicate whether any associated gas was flared. The EPA is not 
proposing to revise this requirement. Thus, reporters would still be 
required to indicate whether associated gas was flared but would report 
this information at the well level rather than the sub-basin level 
under the proposed rule. Retaining the requirement to provide a list of 
well IDs as required by current 40 CFR 98.236(m)(8)(i) would 
effectively duplicate the proposed requirement to indicate if 
associated gas is flared in 40 CFR 98.236(m)(3) for each well. 
Therefore, the EPA is proposing to remove existing 40 CFR 
98.236(m)(8)(i) in addition to all other requirements in 40 CFR 
98.236(m)(8).
2. Oil and Gas Volumes
    As noted previously in this section, subpart W currently requires 
reporters to calculate annual emissions from associated gas venting and 
flaring using equation W-18. Two of the inputs in the equation are the 
volume of oil produced and volume of associated gas sent to sales for 
each well in the sub-basin during time periods in which associated gas 
was vented or flared. However, based on the values initially reported 
in some annual GHGRP reports and correspondence with reporters via e-
GGRT, it appears that reporters, in a

[[Page 50333]]

limited number of cases, may have incorrectly interpreted the language 
of equation W-18 to require reporting of gas sent to sales summed 
across all sub-basins at the facility during time periods in which 
associated gas was vented or flared under existing 40 CFR 98.236(m)(6) 
rather than gas sent to sales in the sub-basin during these flaring and 
venting periods. Thus, the total sales volume reported for the 
associated gas source in these instances is the same as the total 
volume of gas sent to sales for the facility reported under existing 40 
CFR 98.236(aa)(1)(i)(B). If these reporters are accurately reporting 
the volume of gas sent to sales during flaring and venting associated 
gas events and using that volume in equation W-18, then the associated 
gas venting and flaring emissions are likely overstated, as it is 
unlikely that all wells are venting or flaring associated gas 100 
percent of the time. If the reporters are using accurate volumes of gas 
sent to sales during time periods in which associated gas was vented or 
flared for their emissions calculations but reporting total gas sent to 
sales, then the activity data reported do not match the emissions, 
leading to an inconsistent data set. Therefore, the EPA is proposing to 
add the word ``only'' to the definitions of the terms Vp,q 
and SGp,q in equation W-18 (40 CFR 98.233(m)(3)) and to the 
reporting requirements for those data elements in 40 CFR 98.236(m)(5) 
and (6).These proposed amendments would lead to improved accuracy of 
reported emissions, consistent with sections II.C and II.D of this 
preamble.
    The EPA is further proposing to clarify the definition of the 
variable SGp,q in equation W-18 to account for associated gas used at 
the facility. Currently, the term is defined as ``Volume of associated 
gas sent to sales, for well p in sub-basin q, in standard cubic feet of 
gas in the calendar year during time periods in which associated gas 
was vented or flared.'' That volume is subtracted from the total volume 
of associated gas produced to provide a net volume of gas sent to a 
vent or flare at each well. However, an operator may use the produced 
gas at the well-pad, further reducing the volume of gas sent to sales. 
For example, produced gas is often used as fuel for internal combustion 
engines or for separators. For this reason, the EPA is proposing to 
amend the definition of SGp,q in equation W-18 to include 
these additional uses. Specifically, we propose to revise the variable 
name to SGp (i.e., we propose to remove the ``q'' subscript) 
to indicate that the emissions would no longer be summed and reported 
by sub-basin (as described in more detail in section III.D of this 
proposal). We propose to define SGp as the volume of 
associated gas sent to sales or volume of associated gas used for other 
purposes at the facility site, including powering engines, separators, 
safety systems and/or combustion equipment and not flared or vented, 
for well p, in standard cubic feet of gas in the calendar year only 
during time periods in which associated gas was vented or flared. 
Incorporating these proposed changes would add clarity to equation W-
18, consistent with section II.D of this preamble, resulting in more 
accurate reporting of actual volumes of associated gas sent to a vent 
or flare and thus more accurate emissions reporting, consistent with 
section II.C of this preamble. Consistent with these changes, the EPA 
is also proposing to amend reporting requirements in 40 CFR 
98.236(m)(6) to clarify that SGp,q includes associated gas 
that is used on-site at the facility but not sent to a flare or vent.

N. Flare Stack Emissions

    Flare stacks are an emission source type subject to emissions 
reporting by facilities in seven of the ten industry segments in the 
Petroleum and Natural Gas Systems source category.\89\ Total 
CO2, CH4, and N2O emissions from each 
flare currently are required to be calculated using the methodology 
specified in 40 CFR 98.233(n). In addition to calculating total 
emissions from a flare, reporters currently must also separately 
calculate the flared emissions from several types of emission sources 
as specified in the requirements of 40 CFR 98.233 specific to that 
source type.\90\ The procedures in the source-specific paragraphs of 
the existing rule cross-reference the calculation procedures in 
existing 40 CFR 98.233(n), but they also specify that the volume and 
composition of the gas routed to the flare are required to be 
determined according to the procedures for estimating vented emissions 
from the specific source type. For example, existing 40 CFR 
98.233(e)(6) specifies that the volume and gas composition to use in 
calculating flared emissions from dehydrators must be determined 
according to the procedures for calculating vented emissions from 
dehydrators as specified in existing 40 CFR 98.233(e)(1) through (5). 
Since source-specific flared emissions often are a portion of the total 
emissions from a flare, existing 40 CFR 98.233(n)(9) specifies that the 
total CO2, CH4, and N2O for a 
particular flare must be adjusted downward by the amount of the source-
specific emissions that are calculated for the same flare; this ensures 
that emissions from a flare are not double counted (i.e., reported for 
both the flare stacks source type and another emission source type). 
The resulting CO2, CH4, and N2O 
emissions to report for that flare according to existing 40 CFR 
98.236(n)(9) through (11) should be only what is left after subtracting 
all of the source-specific flared emissions from the total emissions.
---------------------------------------------------------------------------

    \89\ Flare stacks are an emission source type currently subject 
to emissions reporting by facilities in the following industry 
segments: Onshore Petroleum and Natural Gas Production, Onshore 
Petroleum and Natural Gas Gathering and Boosting, Onshore Natural 
Gas Processing, Onshore Natural Gas Transmission Compression, 
Underground Natural Gas Storage, LNG Import and Export Equipment, 
and LNG Storage.
    \90\ Facilities currently separately calculate the flared 
emissions from the following types of emission sources (if required 
for the applicable industry segment, per 40 CFR 98.232): dehydrator 
vents (40 CFR 98.233(e)(6)), well venting during completions and 
workovers with hydraulic fracturing (40 CFR 98.233(g)(4)), gas well 
venting during completions and workovers without hydraulic 
fracturing (40 CFR 98.233(h)(2)), onshore production and onshore 
petroleum and natural gas gathering and boosting storage tanks (40 
CFR 98.233(j)(5)), transmission storage tanks (40 CFR 98.233(k)(5)), 
well testing venting and flaring (40 CFR 98.233(l)(6)), and 
associated gas venting and flaring (40 CFR 98.233(m)(5)).
---------------------------------------------------------------------------

    When a flare is dedicated to one or more source types that are all 
subject to source-specific flared emissions reporting, all of the mass 
emissions are currently reported under those source types, and zero 
mass emissions are reported for the flare stacks source types. However, 
even when the only streams routed to a flare are from source types that 
are subject to flared emissions reporting under those source types, the 
flare name or ID and all activity data related to the streams that are 
routed to the flare and the flare operating characteristics still must 
be reported under existing 40 CFR 98.236(n). These activity data 
include the volume of gas routed to the flare, average CO2 
and CH4 mole fractions in the flared gas, flare combustion 
efficiency, fraction of flared gas routed to the flare when it was 
unlit, and indicators of whether a continuous flow measurement device 
and a continuous gas analyzer were used on the gas stream routed to the 
flare. These flare ID and activity data reporting requirements are 
specified in existing 40 CFR 98.236(n)(1) through (8). In the rare 
cases that a CEMS is used on the outlet of a flare, then according to 
existing 40 CFR 98.236(n)(12), only the flare ID and the measured 
CO2 emissions must be reported.
    The EPA is proposing changes to the flared emissions calculation

[[Page 50334]]

methodologies, including the monitoring provisions, as well as the 
flare data reporting requirements for both the flared emissions from 
each source type and for each flare. The proposed changes would align 
the flared emissions calculation methodology and reporting with the 
requirements in CAA section 136(h) to report emissions that are based 
on empirical data and that accurately reflect the total CH4 
emissions from each facility, consistent with section II.B of this 
proposal. We are also proposing changes to clarify specific provisions.
1. Calculation Methodology for Total Emissions from a Flare
    The EPA is proposing several revisions to the flare emission 
calculation methods to improve the quality and accuracy of the 
calculated and reported data, consistent with section II.B of this 
proposal. First, we are proposing to revise the default combustion 
efficiency for flares. Currently, reporters may assume a default 
combustion efficiency of 98 percent, as provided in existing 40 CFR 
98.233(n)(3). However, researchers conducting remote sensing tests of 
emissions from flares have reported finding lower combustion 
efficiencies. For example, Plant et al. conducted extensive testing in 
the Eagle Ford, Bakken, and Permian basins and found average combustion 
efficiencies ranging from less than 92 percent in the Bakken basin to 
slightly more than 97 percent in the Permian basin.\91\ Consistent with 
the requirements of CAA section 136(h), we are proposing a tiered 
approach to setting the default combustion efficiency that would 
provide higher defaults when supported by data from the reporter 
implementing certain flare monitoring procedures, in proposed 40 CFR 
98.233(n)(4). Specifically, under Tier 1, a default combustion 
efficiency of 98 percent would be allowed where the reporter conducts 
flare monitoring consistent with the procedures specified in 40 CFR 
63.670 and 40 CFR 63.671 of the National Emission Standards for 
Hazardous Air Pollutants From Petroleum Refineries (40 CFR part 63, 
subpart CC) (hereafter referred to as ``NESHAP CC''). The standard in 
NESHAP CC is to either reduce emissions by 98 percent or comply with 
the specified flare requirements, as verified via monitoring. 
Therefore, under NESHAP CC, it is presumed that complying with the 
flare requirements achieve at least a 98 percent reduction in 
emissions. Under Tier 2, a default combustion efficiency of 95 percent 
would be allowed if the reporter is required to or elects to comply 
with the monitoring specified in proposed 40 CFR 60.5417b(d)(1)(viii) 
of NSPS OOOOb. The standard in NSPS OOOOb is 95 percent, and it is 
presumed that this standard is met when the specified monitoring is 
conducted and the corresponding activity data limits are met. The 
default combustion efficiency under Tier 3, which would apply if 
neither Tier 1 nor Tier 2 requirements are met, would be 92 percent. 
This value is based on the low end of the range of empirical results 
observed in testing over an extensive area in three of the most active 
basins in the United States (U.S.) in Plant et al. Our assessment is 
that this would be a reasonable combustion efficiency for subpart W 
sources that are not monitoring as specified under Tier 1 or Tier 2 
because the overall average in the empirical results likely included 
many facilities that would comply with those tiers and thus should be 
excluded from the calculation of the average for Tier 3 flares. We are 
proposing Tier 3 to provide a default combustion efficiency that would 
apply before the flare owner or operator has implemented the monitoring 
that would be required to comply with either the final NSPS OOOOb or an 
approved state plan or applicable Federal plan in 40 CFR part 62 and 
that would be consistent with CAA section 136(h).
---------------------------------------------------------------------------

    \91\ Plant, G., et al. 2022. ``Inefficient and unlit natural gas 
flares both emit large quantities of methane.'' Science, 377 (6614). 
https://doi.org/10.1126/science.abq0385. Available in the docket for 
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    We request comment on our proposed approach and values, including 
whether available data would support the selection of other default 
values for any of the tiers. In addition, we request comment on whether 
Tier 3 should be included in the final provisions and if so, whether 
the data support using a default combustion efficiency of 92 percent or 
another value. If commenters do not agree that Tier 3 is appropriate, 
we request that the commenters include what alternative approach should 
be specified for reporters to use for calculating the combustion 
efficiency that would be consistent with the requirements in CAA 
section 136(h) to accurately reflect total CH4 emissions and to base 
reporting on empirical data. Under an approach where only Tier 1 and 
Tier 2 were included, we expect that some period of time would be 
needed for flares not subject to NSPS OOOOb to implement the 
requirements, potentially the same period of time until the facility is 
subject to an approved state plan or applicable Federal plan in 40 CFR 
part 62. We request comment on this possible time frame and what 
procedures and combustion efficiency should be implemented in the 
interim.
    Second, for all flares, regardless of the tier discussed above, we 
are proposing to require at least continuous parameter monitoring to 
determine gas flow to the flare. Currently, under 40 CFR 98.233(n)(1), 
if a continuous flow measurement device is used on part or all of the 
gas routed to the flare, then the measured values must be used in the 
calculation of emissions from the flare. For the portion of gas not 
measured by a continuous flow measurement device, the reporter 
currently may estimate the flow using engineering calculations based on 
process knowledge, company records, and best available data. We are 
proposing a more defined empirical method for determining the gas flow 
to the flare, consistent with section II.B of this proposal. 
Specifically, the proposed revisions to 40 CFR 98.233(n)(1) specify 
that the flow rate determination must be based on direct measurement 
using a flow meter if one is present, or if a flow meter is not 
available, it must be based on indirect calculation of flow using 
continuous parameter monitoring, such as line pressure, burner nozzle 
dimensions, and appropriate engineering calculations. We are also 
proposing that the monitoring could be conducted on either the inlet 
gas to the flare or on each of the individual streams that are combined 
for routing to the flare.
    Third, for all flares, regardless of the tier discussed previously 
in this section, we are proposing in 40 CFR 98.233(n)(2) to require 
either continuous monitoring (proposed 40 CFR 98.233(n)(2)(i)) or 
visual inspection at least once per month (proposed 40 CFR 
98.233(n)(2)(ii)) for the presence of pilot flame or combustion flame. 
During periods when a continuous monitoring device is out of service, 
we are proposing that visual inspections be conducted at least once per 
week for the first four weeks of the outage or until a new or repaired 
continuous monitoring device is operational. If the outage is less than 
one week, then we are proposing that at least one visual inspection 
must be conducted during the time the continuous monitoring device is 
out of service. If an outage lasts more than four weeks, then we are 
proposing that the reporter may switch to conducting visual inspections 
at least once per month in accordance with proposed 40 CFR 
98.233(n)(2)(ii). Data from these measurements or inspections, combined 
with continuous flow data as described previously in this section, 
would be used to determine the

[[Page 50335]]

amount of gas routed to the flare when it was unlit. Currently, subpart 
W specifies that the fraction of gas sent to an unlit flare is to be 
determined by engineering estimate and process knowledge based on best 
available data and operating records (as provided in the definition of 
the variable ZU for existing equations W-19 and W-20 of 40 
CFR 98.233). Researchers conducting remote sensing testing of flares 
have identified higher percentages of unlit flares than the average 
fractions of gas routed to unlit flares reported under subpart W.\92\ 
Although the percentage of flares that are unlit may not equal the 
fraction of gas routed to unlit flares, the difference suggests there 
is a potential for the reported fractions of gas routed to unlit flares 
to be underestimated. Therefore, we are proposing a more defined 
empirical method of determining the fraction of gas sent to the flare 
when it is unlit, consistent with section II.B of this proposal. The 
proposed requirement for continuous monitoring or periodic visual 
inspection of the pilot flame or combustion flame would provide flare-
specific information on the specific times when the flare was unlit. 
The proposed continuous determination of the flow of gas to the flare, 
as described earlier in this section, would provide an accurate 
determination of the flow during the periods when the flare is unlit. 
Together, the information from both measurements would be used to 
calculate the total amount of gas routed to the flare when it is unlit. 
Dividing this amount by the total annual flow would give the fraction 
sent to the flare when it was unlit, which would be used in equations 
W-19 and W-20 to calculate the total annual CH4 and 
CO2 emissions, respectively, from the flare. If a flame is 
not present during a visual inspection, then the reporter must assume 
it was unlit since the previous inspection that confirmed the presence 
of a flame and that it remains unlit until the next inspection that 
confirms the presence of a flame. These assumptions are consistent with 
the existing requirements for estimating the time over which a leak 
occurs based on equipment leak inspections.
---------------------------------------------------------------------------

    \92\ See, e.g., Plant, G., et al. 2022. ``Inefficient and unlit 
natural gas flares both emit large quantities of methane.'' Science, 
377 (6614). https://doi.org/10.1126/science.abq0385. Available in 
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    Fourth, we are proposing changes to the determination of gas 
composition to make the results more accurate, consistent with section 
II.B of this proposal. Currently, under 40 CFR 98.233(n)(2), if a 
reporter is using a continuous gas composition analyzer on gas to the 
flare, then the measured data must be used in the calculation of 
emissions from the flare. However, if the reporter does not use a 
continuous gas composition analyzer, we have reassessed the current 
subpart W requirements that apply and think that they should be revised 
to improve clarity and thus better correspondingly result in calculated 
emissions that accurately reflect CH4 emissions at the 
facility. Specifically, existing 40 CFR 98.233(n)(2) requires 
determination of ``the appropriate gas compositions for each stream of 
hydrocarbons going to the flare . . .'' However, 40 CFR 98.233(u)(2)(i) 
for onshore petroleum and natural gas production facilities and onshore 
petroleum and natural gas gathering and boosting facilities requires 
the reporter to use an annual average gas composition based on the most 
recent available analysis of the facility. Although not explicitly 
stated, one interpretation is that the ``most recent available 
analysis'' should be for each stream of hydrocarbons routed to the 
flare. Another interpretation of 40 CFR 98.233(u)(2)(i) is that the 
composition of produced gas may be used for all streams routed to the 
flare. This interpretation is based on the first sentence in existing 
40 CFR 98.233(u)(2)(i) that states: ``If you have a continuous gas 
composition analyzer for produced natural gas, you must use an annual 
average of these values for determining the mole fraction.'' Given the 
ambiguity in the existing regulations, to date the EPA has not sent 
validation messages to have all facilities report using only one of the 
possible interpretations. Another concern with the current procedures 
for determining gas composition when not using a continuous gas 
composition analyzer is that there is no requirement to conduct 
additional sampling and analysis over time, and subpart W does not 
specify how compositions from multiple streams are to be weighted to 
generate the constituent mole fractions of the total combined stream 
into the flare that are to be used in equations W-19 and W-20. The 
current requirements for determining gas compositions for flared 
streams in other industry segments are clearer. However, one of the 
options for transmission compression, underground natural gas storage, 
LNG storage, LNG import/export facilities, and transmission pipeline 
industry segments is to use a default CH4 composition of 95 
percent, which may not accurately represent the composition of the gas 
flow routed to flares for some facilities. The proposed revisions to 
the flare stacks methodology would delete the cross-reference to 40 CFR 
98.233(u)(2) and specify the gas composition determination requirements 
within proposed 40 CFR 98.233(n)(3). The proposed options are to use a 
continuous gas composition analyzer or to take samples for 
compositional analysis at least once each quarter in which the flare 
operated. If a continuous gas analyzer is used, then the measured data 
would be required to be used to calculate flared emissions. Reporters 
would be allowed to determine the composition of either the inlet gas 
to the flare or on each of the streams that are routed to the flare. If 
periodic samples are collected, then the measured concentrations would 
be combined with flow data over the same time periods to calculate 
flow-weighted annual average concentrations.
    Fifth, for clarity, we are proposing to add requirements in 
existing 40 CFR 98.233(n)(5) to specify how flow and composition data 
would be used to calculate total emissions depending on different 
scenarios a reporter could use to determine the flow and gas 
composition. Proposed 40 CFR 98.233(n)(5)(i) specifies that if both 
flow and gas composition are determined for the inlet gas to the flare, 
then the inlet gas data would be used in a single application of 
equations W-19 and W-20 to calculate the total emissions from the 
flare. If the flow and gas composition are determined for each of the 
streams that are routed to the flare, then one proposed option in 
proposed 40 CFR 98.233(n)(5)(iii) would require the reporter to use 
each set of stream-specific flow and annual average concentration data 
in equations W-19 and W-20 to calculate stream-specific flared 
emissions for each stream, and then sum the results from each stream-
specific calculation to calculate the total emissions from the flare. 
Alternatively, in such circumstances proposed 40 CFR 98.233(n)(5)(iii) 
would also allow reporters to sum the flows from each source to 
calculate the total gas flow into the flare and use the source-specific 
flows and source-specific annual average concentrations to determine 
flow-weighted annual average concentrations of CO2 and 
hydrocarbon constituents in the combined gas stream into the flare. The 
calculated total gas flow and the calculated flow-weighted annual 
average concentrations would then be used in a single application of 
both equation W-19 and W-20 to calculate the total emissions from the 
flare. If flow is determined for all of the individual source streams 
while gas composition is determined for the

[[Page 50336]]

combined stream into the flare, then proposed 40 CFR 98.233(n)(5)(ii) 
would require the reporter to sum the individual source flows to 
calculate the total flow into the flare. This summed volume and the gas 
composition determined for the stream into the flare would be used in a 
single application of equations W-19 and W-20 to calculate the total 
emissions from the flare. Finally, in 40 CFR 98.233(n)(5)(iv) we are 
proposing that a reporter may not calculate flared emissions based on 
the determination of the total volume at the inlet to the flare and gas 
composition for each of the individual streams routed to the flare. The 
proposal would not allow this combination of volume and gas composition 
determinations because there is no way to calculate flow-weighted 
average compositions of either the inlet gas to the flare or the 
individual source streams.
    Sixth, we are proposing to delete the option to use a default 
higher heating value (HHV) in the calculation of N2O 
emissions and instead require all reporters to use either a flare-
specific HHV or individual flared gas stream-specific HHVs in the 
calculation. Currently, 40 CFR 98.233(n)(7) requires the use of 
equation W-40 to calculate N2O emissions from flares. This 
equation requires the flared gas volume, the HHV of the flared gas, and 
the use of a default emission factor. For field gas or process vent 
gas, the variable definition for the HHV provides that either a site-
specific or default value may be used; for other gas streams, a site-
specific HHV must be used. We are proposing in 40 CFR 98.233(n)(8) to 
require the use of a flare-specific HHV when composition of the inlet 
gas to the flare is measured or when flow-weighted concentrations of 
the inlet gas are calculated from measured flow and composition of each 
of the streams routed to the flare. Similarly, we are proposing that 
reporters would calculate N2O emissions using flared gas 
stream-specific HHVs when flow and composition are determined for each 
of the individual streams that are routed to the flare and emissions 
are calculated per stream and summed to calculate total emissions from 
the flare. We are proposing this change because we believe flare-
specific values more accurately represent the HHV of variable flared 
gas composition and would result in more accurate calculation of 
N2O emissions. Our assessment is that the methods for 
calculating CO2 and CH4 in 40 CFR 98.233(n) 
already require the use of flare-specific concentrations for the 
hydrocarbon constituents in the flared gas streams; therefore, we 
expect that a flare-specific HHV is known (or can be calculated using 
the compositional data) without incurring additional burden, while 
increasing the accuracy of the emissions estimate. We are also 
proposing to add a requirement in 40 CFR 98.236(n)(9) to report the 
HHV(s) used to calculate N2O emissions. This data element 
would improve verification of reported N2O emissions and 
minimize the amount of communication with reporters via e-GGRT. It also 
would be useful for characterizing the differences in flared gas 
streams among the various industry segments and basins, and it is 
expected to be useful in analyses such as updates to the U.S. GHG 
Inventory.
    Seventh, we are proposing changes to the emission calculation 
requirements for flares that use CEMS in order to address requirements 
in CAA section 136(h) as described in section II.B of this preamble. 
Currently, if a reporter operates and maintains a CEMS to monitor 
emissions from a flare, existing 40 CFR 98.233(n)(8) requires the 
reporter to calculate only CO2 emissions from the flare. 
This proposal would revise existing 40 CFR 98.233(n)(8) (proposed 40 
CFR 98.233(n)(9)) to require reporters to comply with all of the other 
emission calculation procedures in proposed 40 CFR 98.233(n), with one 
exception. The exception is that since CO2 emissions would 
be measured with the CEMS, calculation of CO2 emissions 
using equation W-20 would not be required. We expect that these 
proposed amendments would address a potential gap in CH4 
emissions reporting and improve the overall quality and completeness of 
the emissions data collected by the GHGRP, consistent with section II.A 
of this preamble.
    Eighth, we are proposing to replace the current source-specific 
methodologies for calculating flared emissions (e.g., existing 40 CFR 
98.233(e)(6) for dehydrators or existing 40 CFR 98.233(g)(4) for 
completions) with a requirement (proposed 40 CFR 98.233(n)(10)) that 
the reporter use engineering calculations and best available data to 
disaggregate the calculated total emissions per flare to the source 
types that routed gas to the flare. One issue with the current source-
specific flared emission calculation methodologies is that the equation 
inputs developed under these methodologies (e.g., flared volumes and 
compositions) often differ from the inputs used in the methodology to 
calculate the total emissions from the flare (as specified in existing 
40 CFR 98.233(n)). As a result, when using the existing methodologies, 
the sum of the flared emissions calculated for individual source types 
sometimes exceeds the total emissions calculated using the methodology 
for calculating total emissions from the flare. The proposed change 
would eliminate this issue because only the flare methodology would be 
used to calculate emissions from a flare, and only these values would 
be included in the published data set for the reporting year. Since 
estimates of the flared emissions from source types that route 
emissions to flares are still useful in other analyses (e.g., assessing 
impacts of emission control regulations on nationwide emission trends), 
the proposed methodology also would require reporters to estimate the 
portions of the total emissions from each flare that are attributable 
to each type of source that is currently subject to flared emissions 
reporting (e.g., completions, storage tanks, associated gas). The 
expected accuracy of the estimated quantities per source type may 
sometimes be lower than the expected accuracy of the total emissions 
from the flare since the source-specific estimates would be based on 
best available data, which may be of more variable quality. However, 
the expectation is that the sum of the estimated emissions over all 
source types will always equal the calculated (and reported) total 
emissions from the flare, and it is expected that the results will be 
of sufficient accuracy for their intended purpose.
    This proposed change would also address a common misperception 
among reporters regarding the flare activity data that is to be 
reported under existing 40 CFR 98.236(n). Many reporters have provided 
information through the GHGRP Help Desk and in correspondence with the 
EPA via e-GGRT indicating that they believe the adjustment requirement 
in existing 40 CFR 98.233(n)(9) applies to all flare data, not just the 
mass emissions (as intended). Thus, some reporters provide activity 
data information for a flare only if some of the mass emissions from 
the flare are due to combustion of gas from source types that are not 
subject to source-specific flared emissions reporting (i.e., 
miscellaneous flared sources). Although these reporters generally 
correctly report the mass emissions from the flare that are due to the 
miscellaneous flared sources, they incorrectly limit their activity 
data reporting to those same streams. The EPA has procedures in its 
verification process to identify such errors; if errors are identified, 
the EPA notifies the reporter, who can resolve the issue by correcting 
the data and resubmitting

[[Page 50337]]

their annual GHG report. Some reporters have also indicated that they 
dislike reporting activity data for a flare in one table in the 
reporting form (i.e., Table N.1) and reporting the emissions in a 
different table; they suggest that it would be clearer to report all 
flare activity data and emissions related to a particular emission 
source type together in one location.
    We also expect that the total emissions per flare calculated using 
the proposed methodology described above would be more accurate than 
the emissions calculated using the current source-specific 
methodologies. While similar changes to the methods for determining 
flow rate and composition of the gas routed to the flare could be 
proposed for each of the source-specific methodologies, we have 
tentatively determined that the additional accuracy in the source-
specific flared emissions relative to calculation of disaggregated 
total emissions based on best available data is not needed given the 
additional burden that would be imposed, as the total flared emissions 
are expected to be accurate; in other words, applying source-level 
methods for flares over the proposed method would not be expected to 
have an impact on the accuracy of the total emissions calculated. 
However, the proposed approach would still maintain calculation and 
reporting of flared emissions per source type because of that 
information's importance for use in assessing trends in control over 
time and in policy determinations under the CAA, and it would also be 
useful in U.S. GHG Inventory development.
    Finally, we are proposing to remove existing 40 CFR 98.233(n)(9) 
for consistency with the other proposed provisions in this subsection, 
as the requirement to correct flare emissions to avoid double counting 
would no longer be necessary because the disaggregated emissions would 
not be a separate source type.
2. Reporting Requirements for Flared Emissions
    The EPA is proposing several changes to the reporting requirements 
for flares. These changes are being proposed to align reporting in 40 
CFR 98.236(n) with the proposed revisions to the calculation methods 
specified in proposed 40 CFR 98.233(n), consistent with section II.B of 
this preamble, and to improve the verification process, obtain a better 
understanding of the design and operation of flares in each of the 
industry segment to help future policy determinations, and clarify 
ambiguous provisions.
    First, the EPA is proposing to replace the source-specific flared 
CH4, CO2, and N2O emissions reporting 
requirements currently in 40 CFR 98.236(e), (g), (h), (j), (l), (m), 
and (n) with a requirement to report source-specific CH4, 
CO2, and N2O emissions that have been 
disaggregated from the total flare emissions as described in section 
III.N.1 of this preamble. The disaggregated emissions per source type 
would be reported per flare under proposed 40 CFR 98.236(n)(19). We are 
proposing to remove the source-specific flared CH4, 
CO2, and N2O emissions reporting requirements 
currently in 40 CFR 98.236(k), but for the reasons discussed in section 
III.L of this preamble, we are not proposing to include condensate 
storage tanks in this list of source types for which emissions would be 
disaggregated in proposed 40 CFR 98.236(n)(19). We are also proposing 
to include AGR vents in the list of source types for which emissions 
would be disaggregated in proposed 40 CFR 98.236(n)(19), even though 
emissions from flaring are not currently reported separately for that 
source, due to the proposed addition of reporting of CH4 
emissions from that source type, as discussed further in section 
III.F.1 of this preamble. In addition to aligning the reporting with 
the proposed calculation methodology, reporting the disaggregated 
emissions per flare rather than per facility, sub-basin, or county 
(under the current provisions of subpart W), and rather than per well-
pad, gathering and boosting site, or facility (as is being proposed for 
vented emissions), would provide the EPA and other stakeholders with a 
better understanding of the impact of different emission source types 
on the performance of flares. We are proposing to retain some of the 
unit-specific activity data for source types that are flared as 
described throughout this preamble in the sections that describe 
amendments specific to those source types (e.g., section III.F.2 of 
this preamble for AGR vents, sections III.K.6 and III.K.8 of this 
preamble for atmospheric storage tanks, section III.M.1 for associated 
gas flaring).
    Second, the EPA is proposing to add a requirement for facilities in 
the Onshore Petroleum and Natural Gas Production industry segment, the 
Onshore Petroleum and Natural Gas Gathering and Boosting industry 
segment, and the Onshore Natural Gas Processing industry segment to 
report an estimate of the fraction of the gas burned in the flare that 
is obtained from other facilities specifically for flaring as opposed 
to being generated in on-site operations. A finding from the currently 
reported data is that a number of facilities in these industry segments 
report significant amounts of emissions from miscellaneous flared 
sources. It is not clear what sources are generating the large amount 
of gas that is routed to these flares. It is important to know what 
source types are generating the large amounts of flared gas because the 
same source type may not always be routing the gas to a flare. If the 
source type also is not currently subject to source-specific reporting 
of vented emissions, then a potentially large quantity of vented 
emissions might go unreported. It appears that one potential source of 
currently undefined sources of flared emissions is emissions from one 
facility that are routed to another facility specifically for flaring. 
To help the EPA understand what source types are generating the large 
amounts of flared gas, we are proposing in 40 CFR 98.236(n)(10) to 
require reporting by facilities in these three industry segments of an 
estimate of the fraction of the gas burned in the flare that is 
obtained from other facilities specifically for flaring as opposed to 
being generated in on-site operations. As an example, if an owner or 
operator has an onshore petroleum and natural gas production and an 
onshore petroleum and natural gas gathering and boosting facility in 
the same basin and routes associated gas from wells in the onshore 
petroleum and natural gas production facility to a flare that is 
defined as part of the onshore petroleum and natural gas gathering and 
boosting facility, then the flared emissions would be reported by the 
onshore petroleum and natural gas gathering and boosting facility as 
emissions from ``other flare stacks'' sources under the current rule 
(or from other flared sources under the proposed amendments). If the 
other gas streams routed to the flare are from sources at the onshore 
petroleum and natural gas gathering and boosting facility, then for 
this proposed reporting requirement, the onshore petroleum and natural 
gas gathering and boosting facility report would include an estimate of 
the fraction of the total gas burned in the flare that is associated 
gas from the onshore petroleum and natural gas production facility. We 
request comment on the types of sources (both onsite sources and 
offsite sources) that may be generating these large emissions and 
whether other reporting elements could be specified that would better 
achieve the EPA's objective of clearly characterizing the sources of 
flared emissions from facilities in the three industry segments 
identified above. For

[[Page 50338]]

example, we have considered adding a reporting element to identify for 
each flare the source type in the category of ``other flared sources'' 
under this proposal that routes the largest quantity of gas to the 
flare. We also request comment on whether there should be a minimum 
threshold for the amount of gas routed from a source in the ``other 
flared sources'' category before reporting the identity of the source 
type would be required and the basis for any such threshold.
    Third, we are proposing adjustments to several of the existing 
reporting elements to align with proposed changes to the calculation 
methodology. For example, existing 40 CFR 98.236(n)(4) requires 
reporting of the total volume of gas routed to the flare. As described 
in section III.N.1 of this preamble, we are proposing to add an option 
for reporters to monitor volume of each stream routed to the flare. To 
align with this monitoring approach, we are proposing in 40 CFR 
98.236(n)(11) to require reporting of the volumes for each of the 
individual streams if the reporter elects to monitor the flow rate of 
the individual streams rather than the total. Similarly, existing 40 
CFR 98.236(n)(7) and (8) require reporting of the CH4 and 
CO2 in the feed gas to the flare. To align with the proposed 
option that would allow determination of gas composition at all of the 
source stream levels as an alternative to determination of the 
composition at the flare inlet, as discussed in section III.N.1 of this 
preamble, proposed 40 CFR 98.236(n)(14) and (15) also would require 
reporting of the annual CH4 and CO2 mole 
fractions for each of the individual streams routed to the flare if the 
reporter elects to monitor composition of those streams. Existing 40 
CFR 98.236(n)(6) requires reporting of the flare combustion efficiency. 
To align with the proposed monitoring tiers, as discussed in section 
III.N.1 of this preamble, proposed 40 CFR 98.236(n)(13) would require 
reporting of the default combustion efficiency associated with 
applicable monitoring tier. In addition, if a reporter switches from 
one monitoring tier to another and calculates emissions for part of the 
year using the default combustion efficiency for one tier and 
calculates emissions for the rest of the year using the default 
combustion efficiency for a different tier, then proposed 40 CFR 
98.236(n)(13) would require reporting of a flow-weighted average 
combustion efficiency for that flare. We are proposing that flow-
weighted average combustion efficiencies be reported to one decimal 
place. These data also would help with verification of the reported 
emissions.
    Existing 40 CFR 98.236(n)(12) requires reporting of whether a CEMS 
was used to measure CO2 emissions from the flare. We are 
proposing to keep this reporting requirement (in proposed 40 CFR 
98.236(n)(20)), but to align with the proposed calculation procedures 
when using CEMS, as described in section III.N.1 of this preamble, we 
are also proposing to specify that the CO2 mole fraction of 
the gas sent to the flare should not be reported when using CEMS 
because equation W-20 is not used to calculate CO2 emissions 
when using a CEMS.
    We are proposing changes to the continuous flow and gas composition 
measurement indicator data elements to require reporting of specific 
measurement methodologies that were used instead of the current ``yes/
no'' indicators. Currently, existing 40 CFR 98.236(n)(2) requires 
reporting of whether the flare stack has a continuous flow measurement 
device and existing 40 CFR 98.236(n)(3) requires reporting of whether 
the flare stack has a continuous gas analyzer (these are yes/no 
indicators). The proposed 40 CFR 989.236(n)(7) would require reporters 
to indicate whether flow is determined using a continuous flow 
measurement device or whether they use a continuous parameter 
monitoring system with engineering calculations. Similarly, the 
proposed 40 CFR 98.236(n)(8) would require reporters to indicate 
whether gas composition is measured using a continuous gas analyzer or 
by taking periodic samples.
    We are also proposing to add a reporting element in proposed 40 CFR 
98.236(n)(13)(i) for facilities that report flares using a combustion 
efficiency of 95 percent to indicate whether the flare is subject to 
NSPS OOOOb or a State or Federal plan in part 62 implementing EG OOOOc 
or whether the reporter is electing to implement flare monitoring 
procedures that are specified in NSPS OOOOb or a State or Federal Plan 
in part 62 implementing EG OOOOc. This information would help the EPA 
verify the reported data.
    Finally, one objective of the current flare reporting requirements 
is to obtain information on the total number of flares and their 
operating characteristics. We are proposing to require a few new flare-
specific reporting elements to help us better understand the state of 
flaring in the industry and to improve data quality, such as an 
indication of the type of the flare (e.g., open ground-level flare, 
enclosed ground-level flare, open elevated flare, or enclosed elevated 
flare) in 40 CFR 98.236(n)(4) and the type of flare assist (e.g., 
unassisted, air-assisted (with indication of single-, dual-, or 
variable-speed fan), steam-assisted, or pressure-assisted) in proposed 
40 CFR 98.236(n)(5). These data would help the EPA assess the impact of 
design and operation on emissions and may be useful in analyses for 
potential future policy decisions related to flares under the CAA. To 
harmonize the proposed reporting requirements with the proposed 
requirement to either continuously monitor or periodically inspect for 
the presence of a pilot flame as discussed in section III.N.1 of this 
preamble, we are proposing in proposed 40 CFR 98.236(n)(6) that 
reporters indicate for each flare whether they continuously monitor for 
the presence of a pilot flame, conduct periodic visual inspections, or 
both. If periodic visual inspections are conducted, we are proposing to 
require reporting of the count of inspections conducted during the year 
and an indication of whether the flare has a continuous pilot or auto 
igniter. For a pilot flame that is monitored continuously, we are 
proposing to require reporting of the number of times the continuous 
monitoring device was out of service or otherwise inoperable for a 
period of more than one week.
3. Definition of Flare Stack Emissions
    In response to a verification message in e-GGRT, one reporter noted 
that the existing definition of the term ``flare stack emissions'' in 
40 CFR 98.238 does not include CO2 that is in streams routed 
to the flare. The term is currently defined to mean ``CO2 
and N2O from partial combustion of hydrocarbon gas sent to a 
flare plus CH4 emissions resulting from the incomplete 
combustion of hydrocarbon gas in flares.'' Based on this definition, 
the reporter concluded that CO2 in streams routed to the 
flare are not to be reported as flare stack emissions. The current 
definition, which was added to the 2010 Final Rule after consideration 
of comments on the 2010 re-proposal, does not clearly convey the EPA's 
intent that the CO2 that enters a flare should be reported 
as flare stack emissions. This intent is evident from the fact that 
equation W-20 includes a term for the inlet gas volume times the 
CO2 mole fraction in the inlet gas. Additionally, in a 
response to a comment on the 2010 re-proposal, the EPA clearly stated 
that the total quantity of CO2, including both combusted 
CO2 (i.e., CO2 created in the flare) and 
uncombusted CO2 (i.e., CO2 that entered and 
simply passed through the flare), is to be calculated. Another

[[Page 50339]]

issue with the current definition is that it implies N2O 
emissions only result from partial combustion of hydrocarbons in the 
gas routed to the flare. This is likely the primary mechanism for 
generating N2O emissions when combusting fuels that include 
nitrogen-containing compounds. However, natural gas and field gas have 
negligible amounts of fuel-bound nitrogen. For combustion of these 
fuels, it appears the N2O is generated primarily from 
converting thermal nitrogen oxides (NOX) under certain 
operating conditions in the flare. Consistent with section II.D of this 
preamble, in order to eliminate the unintended inconsistency between 
the definition and the intent that CO2 in gas routed to the 
flare is to be reported as emissions from the flare, to clarify the 
requirement to calculate and report total CO2 that leaves 
the flare, and to clarify the source of flared N2O 
emissions, we are proposing to revise the definition of the term 
``flare stack emissions'' in 40 CFR 98.238 to mean CO2 in 
gas routed to a flare, CO2 from partial combustion of 
hydrocarbons in gas routed to a flare, CH4 resulting from 
the incomplete combustion of hydrocarbons in gas routed to a flare, and 
N2O resulting from operation of a flare.

O. Compressors

    Compressors are used across the petroleum and natural gas industry 
to raise the pressure of and convey natural gas or CO2. The 
two main types of compressors used in the industry are centrifugal 
compressors and reciprocating compressors. Subpart W currently requires 
Onshore Petroleum and Natural Gas Production and Onshore Petroleum and 
Natural Gas Gathering and Boosting facilities to calculate compressor 
emissions using population emission factors per existing 40 CFR 
98.233(o)(10) and (p)(10). Population emission factors are multiplied 
by the count of equipment, in this case compressors of a certain type, 
to calculate emissions. For the Onshore Natural Gas Processing, Onshore 
Natural Gas Transmission Compression, Underground Natural Gas Storage, 
LNG Storage, and LNG Import and Export Equipment industry segments, 
subpart W requires facilities to annually measure the emissions from 
the compressor sources applicable to the mode the compressor is in at 
the time of the measurement; facilities also have the option to 
continuously measure emissions from a compressor source per existing 40 
CFR 98.233(o)(2) through (5) and (p)(2) through (5). The annual 
measurements are called ``as found'' measurements because the 
compressors are to be measured in the mode in which they are found when 
the measurements are made. The ``as found'' measurements are required 
for each centrifugal and reciprocating compressor at least annually, 
but only for those compressor emission sources that have measurement 
requirements for the mode in which they are found (i.e., the defined 
``compressor mode-source combinations''), as described in the following 
paragraph. If a given compressor was not measured in not-operating-
depressurized-mode during the ``as found'' measurements for three 
consecutive years, a measurement in not-operating-depressurized-mode is 
currently required to be taken during the next planned scheduled 
shutdown of the compressor, per existing 40 CFR 98.233(o)(1)(i)(C) and 
(p)(1)(i)(D).
    Subpart W at 40 CFR 98.238 currently defines the following 
``compressor sources'': wet seal degassing vent (for centrifugal 
compressors only); rod packing emissions (for reciprocating compressors 
only); blowdown valve leakage through the blowdown vent (for both 
centrifugal and reciprocating compressors) and unit isolation valve 
leakage through the open blowdown vent without blind flanges (for both 
centrifugal and reciprocating compressors). Subpart W also currently 
defines the following ``compressor modes'': operating-mode (for both 
centrifugal and reciprocating compressors), standby-pressurized-mode 
(for reciprocating compressors only \93\), and not-operating-
depressurized-mode (for both centrifugal and reciprocating 
compressors). Some compressor sources may only release emissions during 
certain compressor modes. Therefore, subpart W uses the term 
``compressor mode-source combination'' to refer to the specific 
compressor sources that must be measured based on the mode in which the 
compressor is found. For centrifugal compressors, subpart W currently 
requires measurement in the following compressor mode-source 
combinations: wet seal oil degassing vents in operating-mode, blowdown 
valve leakage through the blowdown vent in operating-mode, and unit 
isolation valve leakage through an open blowdown vent without blind 
flanges in not-operating-depressurized-mode. For reciprocating 
compressors, subpart W currently requires measurement in the following 
compressor mode-source combinations: rod packing emissions in 
operating-mode, blowdown valve leakage through the blowdown vent in 
operating-mode, blowdown valve leakage through the blowdown vent in 
standby-pressurized-mode, and unit isolation valve leakage through an 
open blowdown vent without blind flanges in not-operating-
depressurized-mode.
---------------------------------------------------------------------------

    \93\ Currently, subpart W does not require measurements for 
centrifugal compressors in standby-pressurized-mode and therefore 
does not define this mode for centrifugal compressors.
---------------------------------------------------------------------------

1. Mode-Source Combination Measurement Requirements
    The EPA is proposing several amendments related to the ``as found'' 
measurement requirements to improve the quality of data collected for 
compressors. First, standby-pressurized-mode was not included as a mode 
for centrifugal compressors in the existing subpart W definition of 
``compressor mode'' and no compressor mode-source combinations were 
defined for centrifugal compressors in standby-pressurized-mode. While 
centrifugal compressors are seldom in the standby-pressurized-mode, 
there have been several occasions when reporters have indicated through 
the GHGRP Help Desk that a centrifugal compressor was in this mode 
during the ``as found'' measurement. Therefore, we are proposing to 
revise the definition of compressor mode in 40 CFR 98.238 to add 
standby-pressurized-mode to the defined modes for centrifugal 
compressors and require measurement of volumetric emissions from the 
wet seal oil degassing vent or dry seal vent, as applicable (see 
discussion in following paragraph) and the volumetric emissions from 
blowdown valve leakage through the blowdown vent when the compressor is 
found in this mode (proposed 40 CFR 98.233(o)(1)(i)(C)), consistent 
with section II.A of this preamble.
    Second, dry seals on centrifugal compressors were not included in 
the existing subpart W definition of ``compressor source'' and no 
compressor mode-source combinations were defined for dry seals on 
centrifugal compressors. While emissions from wet seal oil degassing 
vents are expected to be larger than from dry seals when the dry seal 
compressor is well-maintained and operating normally, dry seals still 
contribute to centrifugal compressor emissions, especially if they are 
poorly maintained or there are unforeseen upset conditions. 
Additionally, the measurement crew will already be at the centrifugal 
compressor to make the ``as found'' measurement for blowdown valve 
leakage, so they can also measure the emissions from the dry seal while 
they are onsite. Therefore, to better characterize the emissions from 
dry seal centrifugal compressors, we are proposing to revise the 
definition of

[[Page 50340]]

compressor source in 40 CFR 98.238 to add dry seal vents to the defined 
compressor sources for centrifugal compressors and require measurement 
of volumetric emissions from the dry seal vents in both operating-mode 
and in standby-pressurized-mode (proposed 40 CFR 98.233(o)(2)(iii)), 
consistent with section II.B of this preamble. Proposed measurement 
methods for the dry seal vents are similar to those provided for 
reciprocating compressor rod packing emissions and would include the 
use of temporary or permanent flow meters, calibrated bags, and high 
volume samplers. We are proposing that screening methods may also be 
used to determine if a quantitative measurement is required. We are 
proposing to specify that acoustical screening or measurement methods 
would not be applicable to screening dry seal vents because emissions 
from dry seal vents are not a result of through-valve leakage. These 
proposed revisions include a proposed new reporting requirement in 
proposed 40 CFR 98.236(o)(1)(x) to report the number of dry seals on 
centrifugal compressors and the reporting of emission measurements made 
on the dry seals.
    Third, we are proposing to revise 40 CFR 98.233(p)(1)(i) to require 
measurement of rod packing emissions for reciprocating compressors when 
found in the standby-pressurized-mode because recent studies indicate 
that rod packing emissions can occur while the compressor is in this 
mode.\94\ The inclusion of this compressor mode-source combination 
would more accurately reflect compressor emissions, consistent with 
section II.A of this preamble. Furthermore, the measurement crew will 
already be at the compressor to make the ``as found'' measurement for 
blowdown valve leakage, so they can also measure the emissions from the 
dry seal while they are onsite, and several reporters already make 
these measurements.
---------------------------------------------------------------------------

    \94\ Subramanian, R. et al. ``Methane Emissions from Natural Gas 
Compressor Stations in the Transmission and Storage Sector: 
Measurements and Comparisons with the EPA Greenhouse Gas Reporting 
Program Protocol.'' Environ. Sci. Technol. 49, 3252-3261. 2015. 
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

    Fourth, as noted in section III.O of this preamble, if a given 
compressor was not measured in not-operating-depressurized-mode during 
the ``as found'' measurements for three consecutive years, a 
measurement in not-operating-depressurized-mode is currently required 
to be taken during the next planned scheduled shutdown of the 
compressor, per 40 CFR 98.233(o)(1)(i)(C) and (p)(1)(i)(D). This 
provision requires reporters to schedule an extra ``as found'' 
measurement to make this required measurement if the compressor was not 
found in this mode when the regularly scheduled ``as found'' 
measurements were taken. We are proposing to eliminate this requirement 
to conduct a measurement in not-operating-depressurized-mode at least 
once every three years, consistent with section II.C of this preamble. 
We originally included this requirement in subpart W in order to obtain 
a sufficient amount of data for this mode (75 FR 74458, November 30, 
2010). However, based on data collected under subpart W thus far, many 
compressors are in not-operating-depressurized-mode for 30 percent of 
the time or more, so facilities would be able to obtain sufficient 
number of measurements in not-operating-depressurized-mode to calculate 
an accurate mode-source specific emission factor without the additional 
requirement. As such, the extra measurements are unnecessary, and we 
are proposing to eliminate this requirement and make the annual ``as 
found'' measurements true ``as found'' measurements. We are also 
proposing to remove the reporting requirement to indicate if the 
compressor had a scheduled depressurized shutdown during the reporting 
year (existing 40 CFR 98.236(o)(1)(xiv) and 40 CFR 98.236(p)(1)(xiv)) 
because that information is only collected to verify compliance with 
the requirement to conduct a measurement in not-operating-
depressurized-mode at least once every three years.
2. Measurement Methods
    The EPA is proposing several amendments related to the measurement 
method requirements to improve the quality of data collected for 
compressors. First, we are proposing to revise the allowable methods 
for measuring wet seal oil degassing vents. Since the inception of 
subpart W, the only method provided in 40 CFR 98.233(o)(2)(ii) for 
measuring volumetric flow from wet seal oil degassing vents has been 
the use of a temporary or permanent flow meter. The limitation in 
methods allowed for wet seal oil degassing vents was due to the 
expectation that the volumetric flows may exceed the quantitative 
limits of these other methods. In reviewing the data reported for the 
wet seal oil degassing vent, we found that the measured flow rates 
using flow meters are often within the limits of other measurement 
methods allowed for other compressor sources. We also found that many 
reporters have overlooked the restriction on the methods allowed for 
wet seal oil degassing vents and often reported using other measurement 
methods (e.g., high volume samplers). We have found that most of these 
measured flow rates appear to be within the capacity limits of a 
typical high volume sampler. In the small minority of cases in which 
flow rates would be outside of the capacity limit of the instrument, 
facilities can use an alternate method, consistent with the 
requirements for other compressor source measurements. Consequently, we 
concluded that the measurement methods allowed for wet seal oil 
degassing vents could be expanded to include the use of calibrated bags 
and high volume samplers. Therefore, we are proposing to revise 40 CFR 
98.233(o)(2)(ii) to allow the use of calibrated bags and high volume 
samplers. However, we are not proposing to allow the use of screening 
methods because wet seal oil degassing vents are expected to always 
have some natural gas flow. Therefore, we are proposing to retain and 
clarify this unique limitation on the use of screening methods for wet 
seal oil degassing vent measurement methods. This proposed revision 
would provide improved clarity of the wet seal oil degassing provisions 
and allow an additional measurement method that was determined to be 
accurate for this source, consistent with section II.B of this 
preamble.
    Second, we are proposing to remove acoustic leak detection from the 
screening and measurement methods allowed for manifolded groups of 
compressor sources. As noted in existing 40 CFR 98.234(a)(5), acoustic 
leak detection is applicable only for through-valve leakage. The 
acoustic method can be applied to individual compressor sources 
associated with through-valve leakage (i.e., blowdown valve leakage or 
isolation valve leakage), but it cannot be applied to a vent that 
contains a group of manifolded compressor sources downstream from the 
individual valves or other sources that may be manifolded together. The 
inclusion of this method for manifolded compressor sources was in error 
and we are proposing to remove it from 40 CFR 98.233(o)(4)(ii)(D) and 
(E) and 40 CFR 98.233(p)(4)(ii)(D) and (E) to improve accuracy of the 
measurements, consistent with section II.B of this preamble.
    Third, we are proposing a number of clarifications to the 
references to the allowed measurement methods to correct errors and 
improve the clarity of the rule, consistent with section II.D of

[[Page 50341]]

this preamble. These proposed revisions include: revising 40 CFR 
98.233(o)(1)(i)(A) and (B) to reference 40 CFR 98.233(o)(2)(i) instead 
of specific subparagraphs of that paragraph that may be construed to 
limit the methods allowed for blowdown or isolation valve leakage 
measurements; revising 40 CFR 98.233(p)(1)(i)(A), (B) and (C) (as 
proposed) to reference 40 CFR 98.233(p)(2)(i) instead of specific 
subparagraphs of that paragraph that may be construed to limit the 
methods allowed for blowdown or isolation valve leakage measurements; 
revising 40 CFR 98.233(p)(1)(i)(A) and (C) (as proposed) to reference 
``paragraph (p)(2)(ii) or (iii) of this section as applicable'' instead 
of only ``paragraph (p)(2)(ii)'' to clarify that measurement of rod 
packing emissions without an open-ended vent line are to be made 
according to 40 CFR 98.233(p)(2)(iii); and revising 40 CFR 
98.233(p)(2)(ii)(C) and (iii)(A) to clarify that acoustic leak 
detection is not an applicable screening method for rod packing 
emissions (not a through-valve leakage).
3. Onshore Petroleum and Natural Gas Production or Onshore Petroleum 
and Natural Gas Gathering and Boosting
    As noted in section III.O of this preamble, subpart W requires 
onshore petroleum and natural gas production and onshore petroleum and 
natural gas gathering and boosting facilities to calculate compressor 
emissions using population emission factors. As noted in the 
introduction to section II of this preamble, the EPA recently proposed 
NSPS OOOOb and EG OOOOc for certain oil and natural gas sources. The 
proposed standards in NSPS OOOOb and the proposed presumptive standards 
in EG OOOOc include emission limits for reciprocating compressors, 
centrifugal compressors with wet seals, and centrifugal compressors 
with dry seals that would apply when the compressor is in operating-
mode or standby-pressurized-mode. The proposed standards would require 
owners or operators to conduct volumetric emissions measurements from 
each reciprocating compressor rod packing or centrifugal compressor wet 
or dry seal on or before 8,760 hours of operation from startup or from 
the previous measurement. Similar to the 2016 amendments to subpart W 
specific to equipment leak surveys (81 FR 4987, January 29, 2016), the 
EPA is proposing to revise the calculation methodology for compressors 
at onshore petroleum and natural gas production and onshore petroleum 
and natural gas gathering and boosting facilities in subpart W so that 
data derived from centrifugal compressor or reciprocating compressor 
monitoring conducted under NSPS OOOOb or the applicable approved state 
plan or applicable Federal plan in 40 CFR part 62 could be used to 
calculate emissions for subpart W reporting, consistent with section 
II.B of this preamble. For compressors at onshore petroleum and natural 
gas production or onshore petroleum and natural gas gathering and 
boosting facilities not subject to either NSPS OOOOb or an applicable 
approved state plan or applicable Federal plan in 40 CFR part 62, we 
are proposing that reporters would have the option to calculate 
emissions for subpart W reporting using the same provisions for ``as 
found'' measurements as other industry segments.
    Because the proposed standards in NSPS OOOOb and the proposed 
presumptive standards in EG OOOOc are not the same as the requirements 
in subpart W, the EPA is proposing a few additional requirements under 
subpart W for compressors subject to the proposed standards in NSPS 
OOOOb or standards in an applicable approved state plan or applicable 
Federal plan codified in 40 CFR part 62. First, subpart W requires 
measurement of compressor sources that would not be required to be 
measured under the proposed standards in NSPS OOOOb and the proposed 
presumptive standards in EG OOOOc (e.g., blowdown valve leakage through 
the blowdown vent). The EPA is proposing that reporters conducting 
measurements of compressors under NSPS OOOOb or the applicable approved 
state plan or applicable Federal plan in 40 CFR part 62 would conduct 
measurements of any other compressor sources required to be measured by 
subpart W at the same time. Second, because the time between 
measurements under the proposed standards in NSPS OOOOb and the 
proposed presumptive standards in EG OOOOc may not result in 
measurements being taken every reporting year, the EPA is proposing to 
specify that reporters would use equation W-22 or equation W-27, as 
applicable, to calculate emissions from all mode-source combinations 
for any reporting year in which measurements are not required. Finally, 
while we are proposing to eliminate the requirement to conduct a 
measurement in not-operating-depressurized-mode at least once every 3 
years for compressors in the industry segments for which reporters are 
currently required to conduct ``as found'' measurements (as described 
in section III.O.1 of this preamble), we note that the proposed 
standards in NSPS OOOOb and the proposed presumptive standards in EG 
OOOOc would only require measurements to be taken in operating-mode or 
standby-pressurized-mode. If no compressor sources are measured in not-
operating-depressurized-mode, reporters would not have data to develop 
reporter emission factors for that mode-source combination using 
equation W-23 and equation W-28. Therefore, we are proposing in 40 CFR 
98.233(o)(10)(i)(B) and 40 CFR 98.233(p)(10)(i)(B) that reporters with 
compressors subject to NSPS OOOOb or the applicable approved state plan 
or applicable Federal plan in 40 CFR part 62 would be required to 
conduct additional measurements of compressors in not-operating-
depressurized-mode such that they can develop an annual reporter 
emission factor for isolation valve leakage in not-operating-
depressurized-mode. Based on an analysis of all reciprocating and 
centrifugal compressor measurements for the other industry segments 
since 2015, approximately one-third of all compressor measurements were 
performed in not-operating-depressurized mode. We propose to maintain 
that percentage for reciprocating and centrifugal compressor 
measurements in the Onshore Petroleum and Natural Gas Production and 
Onshore Petroleum and Natural Gas Gathering and Boosting industry 
segments. Therefore, we are proposing to require reporters to measure 
emissions in not-operating-depressurized mode from isolation valve 
leakage for at least one-third of the subject compressors during any 3 
consecutive calendar year period. We are also proposing to require 
reporters to provide the total count of compressors measured in not-
operating-depressurized-mode over the previous 3 calendar years, as 
well as the total number of compressors subject to NSPS OOOOb or the 
applicable approved state plan or applicable Federal plan in 40 CFR 
part 62. We request comment on other ways to collect sufficient 
measurements to calculate a reporter emission factor for isolation 
valve leakage in not-operating-depressurized-mode.
    For facilities in the Onshore Petroleum and Natural Gas Production 
and Onshore Petroleum and Natural Gas Gathering and Boosting industry 
segments that do not conduct measurements, we are proposing to clarify 
the language at 40 CFR 98.233(o)(10) and (p)(10) for compressors at 
Onshore Petroleum and Natural Gas Production or Onshore

[[Page 50342]]

Petroleum and Natural Gas Gathering and Boosting facilities, consistent 
with section II.B of this preamble. The compressor emission factors for 
these industry segments are specific to uncontrolled wet seal oil 
degassing vents on centrifugal compressors and uncontrolled rod packing 
emissions for reciprocating compressors. The language in 40 CFR 
98.233(o) and (p) clearly indicates that the provisions of 40 CFR 
98.233(o)(10) and (p)(10) do not apply for controlled compressor 
sources. However, proposed revisions are necessary to provide clarity 
regarding the compressor sources for which emissions are required to be 
calculated under 40 CFR 98.233(o)(10) and (p)(10) and reported under 40 
CFR 98.236(o)(5) and (p)(5). Specifically, we are proposing minor 
revisions to 40 CFR 98.233(o)(10) and the corresponding reporting 
requirements in 40 CFR 98.236(o)(5) to clarify that the compressor 
count used in equation W-25 should be the number of centrifugal 
compressors with atmospheric (i.e., uncontrolled) wet seal oil 
degassing vents. Similarly, we are proposing minor revisions to 40 CFR 
98.233(p)(10) and the corresponding reporting requirements in 40 CFR 
98.236(p)(5) to clarify that the compressor count used in equation W-
29D should be the number of reciprocating compressors with atmospheric 
(i.e., uncontrolled) rod packing emissions. We are also proposing to 
add requirements to report the total number of centrifugal compressors 
at the facility and the number of centrifugal compressors that have wet 
seals to 40 CFR 98.236(o)(5) and proposing to add a requirement to 
report the total number of reciprocating compressors at the facility to 
40 CFR 98.236(p)(5). These additional data would provide the EPA with 
an improved understanding of the total number of compressors and the 
number of compressors that are controlled (i.e., routed to flares, 
combustion, or vapor recovery systems) in the Onshore Petroleum and 
Natural Gas Production and Onshore Petroleum and Natural Gas Gathering 
and Boosting industry segments, consistent with section II.C of this 
preamble.
    In addition, consistent with section II.B of this preamble, we are 
proposing to amend the CH4 and CO2 population 
emission factors in equation W-29D for reciprocating compressors at 
onshore petroleum and natural gas production and onshore petroleum and 
natural gas gathering and boosting facilities. The current population 
emission factors were adopted from the 1996 GRI/EPA study Methane 
Emissions from the Natural Gas Industry; Volume 8: Equipment Leaks.\95\ 
\96\ In the time since the promulgation of the current population 
emission factor, Zimmerle et al. (2019) \97\ reported the results of a 
nationally representative field assessment of equipment leak rates from 
facilities in the Onshore Petroleum and Natural Gas Gathering and 
Boosting industry segment. As part of this proposed rulemaking, the EPA 
reviewed Zimmerle et al. (2019) to evaluate the potential for revisions 
to the population emission factor in equation W-29D. We found that 
Zimmerle et al. (2019) uses a larger and more representative sample of 
412 rod packing vent measurements, compared to the 40 compressor 
measurements available in the 1996 GRI/EPA study. Therefore, we are 
proposing a population emission factor for CH4 based on the 
average population emission rate measured by Zimmerle et al. (2019), 
with a proposed CO2 population emission factor derived by 
applying the ratio of the current CO2 emission factor to the 
current CH4 emission factor to the CH4 emission 
factor obtained from Zimmerle et al. (2019). For more information 
regarding our review of Zimmerle et al. (2019) and the derivation of 
the proposed emission factors, see the subpart W TSD, available in the 
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234. We 
request comment on whether there are other studies or data sets that 
provide information that could be used to further refine the emission 
factors for both reciprocating and centrifugal compressors at onshore 
petroleum and natural gas production and onshore petroleum and natural 
gas gathering and boosting facilities, particularly data sets that 
include measurements for all compressor sources (i.e., rod packing and 
blowdown isolation valves for reciprocating compressors and wet seals, 
dry seals, and blowdown isolation valves for centrifugal compressors).
---------------------------------------------------------------------------

    \95\ The development of the current emission factors for 
reciprocating compressors in the Onshore Petroleum and Natural Gas 
Production or Onshore Petroleum and Natural Gas Gathering and 
Boosting sectors are described in Compressor Modes and Thresholds, 
U.S. EPA, November 2010, (Docket Id. No. EPA-HQ-OAR-2009-0923-3580), 
also available in the docket for this rulemaking, Docket Id. No. 
EPA-HQ-OAR-2023-0234.
    \96\ Campbell, L., M. Campbell, M. Cowgill, D. Epperson, M. 
Hall, M. Harrison, K. Hummell, D. Myers, T. Shires, B. Stapper, C. 
Stapper, J. Wessels, AND H. Williamson. Methane Emissions From the 
Natural Gas Industry--Volume 8. Equipment Leaks. U.S. Environmental 
Protection Agency, Washington, DC, EPA/600/R-96/080h, also available 
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-
0234.
    \97\ Zimmerle, D., Bennett, K., Vaughn, T., Luck, B., 
Lauderdale, T., Keen, K., Harrison, M., Marchese, A., Williams, L., 
& Allen, D. (2019). Characterization of methane emissions from 
gathering compressor stations: final report. Mountain Scholar. 
https://doi.org/10.25675/10217/194544. Available in the docket for 
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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4. Compressors Routed to Controls
    Centrifugal and reciprocating compressors are the only sources for 
which capture for fuel use and thermal oxidizers currently are 
specifically listed as dispositions for emissions that would otherwise 
be vented (see 40 CFR 98.233(o) and (p) introductory text). The EPA's 
intent with the provisions is to differentiate flares, which are 
combustion devices that combust waste gases without energy recovery 
(per 40 CFR 98.238), from combustion devices with energy recovery, 
including for fuel use. However, some thermal oxidizers combust waste 
gases without energy recovery and therefore may instead meet the 
subpart W definition of flare. Consistent with section II.D of this 
preamble, in order to emphasize that the EPA's intent is generally to 
treat emissions routed to flares and combustion devices other than 
flares consistently, we are proposing to remove the references to fuel 
use and to thermal oxidizers in 40 CFR 98.233(o) and (p) and 40 CFR 
98.236(o) and (p). Instead, we are proposing to define ``routed to 
combustion'' in 40 CFR 98.238 to specify the types of non-flare 
combustion equipment for which reporters would be expected to calculate 
emissions. In particular, for the Onshore Petroleum and Natural Gas 
Production, Onshore Petroleum and Natural Gas Gathering and Boosting, 
and Natural Gas Distribution industry segments, ``routed to 
combustion'' would mean the combustion equipment specified in 40 CFR 
98.232(c)(22), (i)(7), and (j)(12), respectively (i.e., the combustion 
equipment for which emissions must be calculated per 40 CFR 98.233(z)). 
For all other industry segments, ``routed to combustion'' would mean 
the stationary combustion sources subject to subpart C. The proposed 
definition of ``routed to combustion'' would apply for all subpart W 
emission sources for which that term appears (e.g., natural gas driven 
pneumatic pumps).
5. Reporting of Compressor Activity Data
    We are proposing to remove some data elements that are redundant 
between 40 CFR 98.236(o)(1) and (2) for centrifugal compressors and 
between 40 CFR 98.236(p)(1) and (2) for reciprocating compressors. 
Specifically, current 40 CFR 98.236(o)(1)(vi) and 40 CFR 
98.236(p)(1)(viii) require reporters to indicate which individual 
compressors are part of a manifolded

[[Page 50343]]

group of compressor sources, and current 40 CFR 98.236(o)(1)(vii) 
through (ix) and 40 CFR 98.236(p)(1)(ix) through (xi) require reporters 
to indicate whether individual compressors have compressor sources 
routed to flares, vapor recovery, or combustion. However, current 40 
CFR 98.236(o)(2)(ii)(A) and 40 CFR 98.236(p)(2)(ii)(A) require the same 
information for each compressor leak or vent rather than by compressor. 
The information collected for each leak or vent is more detailed and is 
the information used for emissions calculations. Therefore, the EPA is 
proposing to remove the redundant reporting requirements in existing 40 
CFR 98.236(o)(1)(vi) through (ix) and existing 40 CFR 
98.236(p)(1)(viii) through (xi), consistent with section II.B of this 
preamble.

P. Equipment Leak Surveys

    Subpart W reporters are currently required to quantify emissions 
from equipment leaks using the calculation methods in 40 CFR 98.233(q) 
(equipment leak surveys) and/or 40 CFR 98.233(r) (equipment leaks by 
population count). The equipment leak survey method currently uses the 
count of leakers detected with one of the subpart W leak detection 
methods in 40 CFR 98.234(a), subpart W leaker emission factors, and 
operating time to estimate the emissions from equipment leaks. The 
current leaker emission factors applicable to onshore petroleum and 
natural gas production and onshore petroleum and natural gas gathering 
and boosting facilities are found in existing Table W-1E of subpart W. 
These leaker emission factors are based on the EPA's Protocol for 
Equipment Leak Emission Estimates published in 1995 (Docket Id. No. 
EPA-HQ-OAR-2009-0927-0043), also available in the docket for this 
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234. The leaker emission 
factors are provided for components in gas service, light crude 
service, and heavy crude service that are found to be leaking via 
several different screening methods. In addition to being component- 
and service-specific, subpart W currently provides two different sets 
of leaker emission factors: one based on leak rates for leaks 
identified by Method 21 (see 40 CFR part 60, appendix A-7) using a leak 
definition of 10,000 ppm and one based on leak rates for leaks 
identified by Method 21 using a leak definition of 500 ppm. Currently, 
the other leak screening methods provided in subpart W (OGI, infrared 
laser beam illuminated instrument, and acoustic leak detection device) 
use the leaker emission factors based on Method 21 data with a leak 
definition of 10,000 ppm.
1. Revisions and Addition of Default Leaker Emission Factors
    In the 2022 Proposed Rule, we proposed to revise the leaker 
emission factors to provide separate leaker factors for leaks detected 
using OGI based on recent study data from Zimmerle et al. (2020) and 
Pacsi et al. (2019). For the Onshore Petroleum and Natural Gas 
Production and Onshore Petroleum and Natural Gas Gathering and Boosting 
industry segments, the emission factors were calculated directly from 
these study data. For downstream industry segments, separate OGI 
emission factors were estimated using an ``OGI enhancement factor,'' 
which was estimated as the ratio between the OGI emission factors and 
the Method 21 emission factors for the upstream industry segments. In 
this proposed rulemaking and as described in more detail later in this 
section, we are maintaining our proposal to provide separate emission 
factors for leaks detected using OGI based on recent study data from 
Zimmerle et al. (2020) and Pacsi et al. (2019). In this proposed 
rulemaking, we are proposing an update to the emission factors provided 
for downstream segments based on an ``OGI enhancement factor'' value 
that has been updated since the June 2022 proposal. Additionally, in 
this rulemaking we are proposing to use the Zimmerle et al. (2020) and 
Pacsi et al. (2019) study data to provide Method 21 at leak definitions 
of 500 ppm and 10,000 ppm. We expect these updated emission factors to 
provide a more accurate estimation of emissions estimated with default 
leaker emission factors as they use more recent data and are from a 
dataset of a larger size than the current emission factors.
    In the years that have followed the adoption of the leaker emission 
factors into subpart W, there have been numerous studies regarding 
emissions from equipment leaks that provide measurement data to update 
the existing emission factors for leaks detected using Method 21 at a 
leak definition of either 10,000 ppm or 500 ppm as well as to quantify 
leaker emission factors for OGI screening methods at onshore petroleum 
and natural gas production and onshore petroleum and natural gas 
gathering and boosting facilities.\98\ With respect to the OGI 
screening method, these studies have found that OGI identifies fewer 
yet larger leaks than the EPA's Method 21. Specifically, the average 
leaker emission factor determined from OGI leak detection surveys is 
often a factor of two or more larger than leaker emission factors 
determined when using Method 21 leak detection surveys. Therefore, the 
application of the same leaker emission factor to leaking components 
detected with OGI and Method 21 with a leak definition of 10,000 ppm, 
as is currently done in subpart W, likely understates the emissions 
from leakers detected with OGI.
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    \98\ See, e.g., ERG (Eastern Research Group, Inc.) and Sage 
(Sage Environmental Consulting, LP). City of Fort Worth Natural Gas 
Air Quality Study: Final Report. July 13, 2011, available at https://www.fortworthtexas.gov/departments/development-services/gaswells/air-quality-study/final; Allen, D.T., et al. ``Measurements of 
methane emissions at natural gas production sites in the United 
States.'' Proceedings of the National Academy of Sciences of the 
United States of America, Vol. 110, no. 44. pp. 17768-17773, October 
29, 2013, available at http://dept.ceer.utexas.edu/methane/study. 
Docket Item No. EPA-HQ-OAR-2014-0831-0006; Pacsi, A.P., et al. 
``Equipment leak detection and quantification at 67 oil and gas 
sites in the Western United States.'' Elem Sci Anth, 7: 29, 
available at https://doi.org/10.1525/elementa.368. 2019; Zimmerle, 
D., et al. ``Methane Emissions from Gathering Compressor stations in 
the U.S.'' Environmental Science & Technology 2020, 54(12), 7552-
7561, available at https://doi.org/10.1021/acs.est.0c00516. The 
documents are also available in the docket for this rulemaking, 
Docket Id. No. EPA-HQ-OAR-2023-0234.
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    Based on our review of these studies, we are proposing to amend the 
leaker emission factors in existing Table W-1E (proposed Table W-2) for 
onshore petroleum and natural gas production and onshore petroleum and 
natural gas gathering and boosting facilities to update the Method 21 
emission factors as well as include separate emission factors for 
leakers detected with OGI, consistent with section II.B of this 
preamble. We are proposing to revise the emission factors using study 
data from Zimmerle et al. (2020) and Pacsi et al. (2019). The Zimmerle 
et al. (2020) study contains hundreds of quantified leaks detected 
using OGI. The Pacsi et al. (2019) study also contains hundreds of 
equipment leak measurements from sites that were screened using Method 
21 with a leak definition of 10,000 ppm and 500 ppm as well as OGI. We 
are proposing the use of these studies as the basis for the proposed 
emission factors because they included recent measurements of subpart 
W-specified equipment leak components from both oil and gas production 
and gathering and boosting sites in geographically diverse locations.
    As noted above, numerous studies have found that the average size 
of the leaks detected by OGI are larger than those detected by EPA's 
Method 21. Using the Pacsi et al. study data, we estimate that the 
leaks detected by OGI are 1.63 times larger than leaks detected by 
Method 21 at a leak definition of

[[Page 50344]]

10,000 ppm and 2.81 times larger than leaks detected by Method 21 at a 
leak definition of 500 ppm. As noted, the Pacsi et al. (2019) study 
provided data on leaks detected by Method 21 at a leak definition of 
10,000 ppm and 500 ppm as well as OGI data, however, the sample size of 
leaks screened in the Pacsi et al. (2019) study with Method 21 is 
smaller than those screened with OGI, particularly when combining the 
OGI data from Pacsi et al. (2019) with the Zimmerle et al. (2020) data. 
The combined OGI dataset from Pacsi et al. (2019) and Zimmerle et al. 
(2020) contains more than 700 measurements from leaks detected with 
OGI. Emission factors using these data are derived for each combination 
of well site type (e.g., gas or oil) and component type (e.g., valve). 
The more than 700 measurements in the combined OGI dataset results in 
an average of 44 measurements for each combination of well site type 
(e.g., gas or oil) and component type (e.g., valve). In contrast, the 
Pacsi et al. study has nearly 300 measurements for leaks detected using 
Method 21 at a leak definition of 500 ppm and 140 measurements for 
leaks detected using Method 21 at a leak definition of 10,000 ppm, 
which results in averages of 21 measurements and 10 measurements for 
each combination of site type and component type, respectively.
    For OGI, we are proposing leaker emission factors that were 
developed using the combined data from Pacsi et al. (2019) and Zimmerle 
et al. (2020) by site type (i.e., gas or oil). Equipment leaks are 
inherently variable; therefore, sample size is important when seeking 
to derive representative equipment leak emission factors. Therefore, we 
are proposing to use the OGI data and the ratio between OGI and the 
Method 21 at a leak definition of 10,000 ppm and a leak definition of 
500 ppm (i.e., 1.63 and 2.81, respectively) to derive the proposed 
emission factors for Method 21 at both leak definitions. This approach 
uses the most robust set of data available (OGI) to derive the proposed 
emission factors. 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.
    At onshore petroleum and natural gas production and onshore 
petroleum and natural gas gathering and boosting facilities, very few 
facilities use infrared laser beam illuminated instruments or acoustic 
leak detection devices to conduct equipment leak surveys and there are 
no data available to develop leaker emission factors specific to these 
methods. Based on our understanding of these alternative methods, we 
expect that their leak detection thresholds would be most similar to 
OGI, so that the average emissions per leak identified by these 
alternative methods would be similar to the emissions estimated using 
the proposed OGI leaker factors. Therefore, we are proposing that, if 
these alternative methods are used to conduct leak surveys, the 
proposed OGI leaker emission factors in proposed Table W-2 would be 
used to quantify the emissions from the leaks identified using these 
other monitoring methods. We are seeking comment on the performance of 
infrared laser beam illuminated instruments and acoustic leak detection 
devices including data that may support a separate detection method 
specific emission factor or that supports the proposal that OGI 
emission factors appropriately estimate leakers detected with these 
methods.
    As described in the introductory section III.P of this section of 
this preamble, currently, equipment leak emissions quantified with the 
leaker method are calculated using the count of leakers and a default 
emission factor from existing Table W-1E that is specific to the type 
of component (e.g., valve) and the service (i.e., gas or oil). For 
onshore petroleum and natural gas gathering and boosting facilities, 
subpart W currently specifies and would continue to specify that all 
components should be considered to be in gas service consistent with 
the language in 40 CFR 98.233(q)(2)(iv); thus, the gas service factors 
from proposed Table W-2 should be applied to the count of equipment 
leak components consistent with the leak detection method used.
    For onshore petroleum and natural gas production facilities, we are 
proposing to amend 40 CFR 98.233(q)(2)(iii) to state that onshore 
petroleum and natural gas production facilities must use the 
appropriate default whole gas leaker emission factors consistent with 
the well type (rather than the component-level service type), where 
components associated with gas wells are considered to be in gas 
service and components associated with oil wells are considered to be 
in oil service as listed in proposed Table W-2 to this subpart. This 
proposed amendment is intended to ensure that the application of the 
proposed emission factor using the well site type rather than 
component-level service type is consistent with the derivation of the 
emission factor. The emission factors were derived based on study-
reported well site type, accounting for the idea that a gas well site 
can have components in oil service and vice versa, and thus would be 
required to be applied by well site type.
    As described previously, our analysis of measurement study data 
from onshore production and gathering and boosting facilities 
demonstrates that the OGI screening method finds fewer and larger leaks 
than Method 21. Consequently, the leaker emission factors derived using 
measurement data from the OGI screening method are larger than those 
derived using the measurement data from Method 21 screening method. We 
expect that the leaker emission factors for other industry segments 
that are based on measurements of Method 21-identified leaks may 
similarly underestimate the emissions from leaking equipment when OGI 
(or other alternative methods besides Method 21) are used to detect the 
leaks. In this proposal, we are applying the addition of an ``OGI 
enhancement factor'' to the leaker emission factors for the other 
subpart W industry segments, resulting in new proposed emission 
factors, to ensure that facilities estimate the same equipment leak 
emissions if they either (1) identify leaks with Method 21 and apply 
the Method 21 derived emission factors or (2) identify leaks with OGI 
and apply the OGI enhancement factor adjusted emission factors. More 
specifically, we are proposing to apply the ``OGI enhancement'' factor 
identified from measurement study data in the onshore production and 
gathering and boosting industry segments, a value of 1.63, to the 
leaker emission factors for the other subpart W industry segments as a 
means to estimate and propose an OGI emission factor set. In other 
words, the ``OGI enhancement factor'' is based on the average OGI-
identified leak being 1.63 times larger than the average Method 21-
identified leak when using a leak definition of 10,000 ppm in the 
measurement study data. Analogous to the proposed changes in proposed 
Table W-2 for the Onshore Petroleum and Natural Gas Production and 
Onshore Petroleum and Natural Gas Gathering and Boosting industry 
segments, this results in the proposed addition of emission factor sets 
specific to OGI, infrared laser beam illuminated instrument, or 
acoustic leak detection device screening methods. The proposed emission 
factor sets are included in proposed Tables W-4 and W-6 for the Onshore 
Natural Gas Processing, Onshore Natural Gas Transmission Compression, 
Underground Natural Gas Storage, LNG Storage, LNG Import and Export 
Equipment, and Natural Gas Distribution industry segments. A

[[Page 50345]]

detailed description of the proposed emission factors is provided in 
the subpart W TSD, available in the docket for this rulemaking, Docket 
Id. No. EPA-HQ-OAR-2023-0234.
    The existing reporting requirements for the equipment leak emission 
source types that are quantified by leaker method include activity and 
emissions data (i.e., count of leakers, annual average operating time, 
CO2 emissions and CH4 emissions) on a per 
component basis (e.g., valve, connector), consistent with the 
component-level screening surveys and component-level default emission 
factors. In addition to continuing to collect the existing activity 
data, we are seeking comment on including a requirement to report the 
major equipment type (e.g., wellhead, compressor, dehydrator) at which 
the component-level leak is found. The collection of the major 
equipment type associated with leakers could facilitate future 
development of major equipment-based leaker factors and/or be combined 
with the population of major equipment at facilities to facilitate 
future development of the major equipment population emission factors. 
Since the leak surveys are ground-level, the major equipment type is 
expected to be known and this additional requirement would appear to 
result in minimal increased burden. We are seeking comment on whether 
it is appropriate to require the reporting of the type of major 
equipment type in addition to the component type and specifically if 
there are concerns regarding burden or data collection that should be 
considered.
2. Addition of Undetected Leak Factor for Leaker Emission Estimation 
Methods
    Subpart W currently provides various screening methods for 
detecting leaking components in 40 CFR 98.234(a). Each method includes 
a unique instrument and associated procedure by which leaks are 
detected. Variability inherently exists in each method's ability to 
detect leaks and can be attributed to reasons associated with the 
instrument, leak detection procedures, the operator or site conditions. 
For example, some components may be inaccessible to be surveyed with 
handheld devices that require close proximity to the leak to detect it 
(e.g., Method 21 flame ionization detectors (FID)), while the same leak 
could be visualized using an OGI camera that is less dependent on 
proximity to the leak. Operators with varying levels of training or 
expertise deploy the screening devices, resulting in operator 
variability. Site-level conditions such as wind speed can also impact 
the detection of leaks. We have reviewed recent study data from Pacsi 
et al. (2019) in which multiple leak detection methods, including OGI 
and Method 21, were deployed alongside one another at the same sites. 
This study demonstrates that there are undetected leaks for each 
method. Based on the Pacsi et al. (2019) study data, OGI observes 80 
percent of emissions from measured leaks, Method 21 at a leak 
definition of 10,000 ppm observes 65 percent of emissions from measured 
leaks, and Method 21 at leak definition of 500 ppm observes 79 percent 
of emissions from measured leaks. In order to account for the quantity 
of emissions that remain undetected by each screening method, we are 
proposing to provide a method specific adjustment factor, k, for the 
calculation methods used to quantify emissions from equipment leaks 
using the leaker method in 40 CFR 98.233(q). The proposed addition of a 
method specific adjustment factor would be expected to improve the 
accuracy of emissions data, consistent with section II.B of this 
preamble. Further detail on the development of the adjustment factor 
for each of these screening methods is provided in the subpart W TSD, 
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-
2023-0234.
    As noted in section III.P.2 of this preamble, very few onshore 
petroleum and natural gas production and onshore petroleum and natural 
gas gathering and boosting facilities use infrared laser beam 
illuminated instruments or acoustic leak detection devices to conduct 
equipment leak surveys, so there are no data available to develop a 
method-specific adjustment factor, k, for these detection methods. 
Based on our understanding of these alternative methods, we expect that 
their leak detection thresholds would be most similar to OGI, so that 
the average emissions per leak identified by these alternative methods 
would be similar to the emissions estimated using OGI. Therefore, we 
are proposing that, if these alternative methods are used to conduct 
leak surveys, the proposed OGI adjustment factor, k, would be used in 
the calculation to quantify the emissions from the leaks identified 
using these other monitoring methods. We are seeking comment on the 
performance of infrared laser beam illuminated instruments and acoustic 
leak detection devices, including data that may support a separate 
detection method specific adjustment factor, k.
    We are proposing the survey method-specific k value in equation W-
30 of 40 CFR 98.233(q)(2) such that the factor would be applied to the 
emissions quantified using either the default or the proposed site-
specific emission factors, as discussed in section III.P.4 of this 
preamble, to estimate equipment leak emissions. We are also proposing 
the application of the k value to the emissions quantified using the 
proposed direct measurement method discussed in section III.P.3 of this 
preamble and in proposed 40 CFR 98.233(q)(3). The application of the k 
factor is intended to account for undetected emissions such that the 
reported emissions represent the actual site-level total, not limited 
to the fraction of detected leaks. We are seeking comment on the 
application of this factor to scale detected leak emissions. 
Specifically, we are seeking additional data that either support the 
application of this factor and the appropriate method-specific value 
for this factor or support why the proposed factor should not be 
applied to equipment leak emission estimates.
3. Addition of Method To Quantify Emissions Using Direct Measurement
    As an alternative to the proposed revised default leaker emission 
factors, we are also proposing in 40 CFR 98.233(q)(1) to provide an 
option (provided in proposed 40 CFR 98. 233(q)(3)) that would allow 
reporters to quantify emissions from equipment leak components in 40 
CFR 98.233(q) by performing direct measurement of equipment leaks and 
calculating emissions using those measurement results, consistent with 
section II.B of this preamble. The proposed amendments would provide 
that facilities with components subject to 40 CFR 98.233(q) can elect 
to perform direct measurement of leaks using one of the existing 
subpart W measurement methods in 40 CFR 98.234(b) through (d), such as 
calibrated bagging or a high volume sampler. To use this proposed 
option, all leaks identified during a ``complete leak detection 
survey'' must be quantified; in other words, reporters could not use 
leaker emission factors for some leaks and quantify other leaks 
identified during the same leak detection survey. For the Onshore 
Petroleum and Natural Gas Production industry segment, proposed 40 CFR 
98.233(q)(1) specifies that a complete leak detection survey would be 
the fugitive emissions monitoring of a well site using a method in 40 
CFR 98.234(a) which is conducted to comply with NSPS OOOOa, NSPS OOOOb, 
or the applicable EPA-approved state plan or the applicable Federal 
plan in 40 CFR part 62 or, if the reporter elected to conduct the leak 
detection survey, a complete survey of all equipment on a single well-
pad. For the Onshore Petroleum and Natural Gas Gathering

[[Page 50346]]

and Boosting industry segment, proposed 40 CFR 98.233(q)(1) specifies 
that a complete leak detection survey would be the fugitive emissions 
monitoring of a compressor station using a method in 40 CFR 98.234(a) 
which is conducted to comply with NSPS OOOOa, NSPS OOOOb, or the 
applicable EPA-approved state plan or the applicable Federal plan in 40 
CFR part 62 or, if the reporter elected to conduct the leak detection 
survey, a complete survey of all equipment at a ``gathering and 
boosting site'' (and we are proposing to define this term in 40 CFR 
98.238, as described in section III.D of this preamble). For downstream 
industry segments (e.g., Onshore Natural Gas Transmission Compression), 
a complete leak detection survey is facility-wide, and therefore, the 
election to perform direct measurement of leaks would also be facility-
wide. In other words, this option would allow the use of measurement 
data directly when all leaks identified are quantitatively measured.
    The proposed amendments rely specifically on quantitative 
measurement methods already provided in the rule. We are seeking 
comment on alternative methods for quantifying leaks for use for these 
equipment leak measurements (and for ``as found'' compressor 
measurements) along with supporting information and data. The 
supporting information should include description of the method, 
limitations on the applicability of the method, and calibration 
requirements. Supporting data should include accuracy assessments 
(e.g., controlled release assessments) relative to other quantitative 
measurement methods provided in the rule.
4. Addition of a Method To Develop Site-Specific Component-Level Leaker 
Emission Factors
    As noted in section III.P of this preamble, facilities are 
currently required to perform leak surveys to determine the number of 
leaking components. The results of these surveys (i.e., the count of 
leakers) are used with default emission factors to estimate the 
quantity of resulting emissions. As noted in the previous section, the 
EPA is proposing an additional option for facilities to conduct leak 
surveys and perform direct measurement to quantify the emissions from 
equipment leak components.
    The EPA recognizes that while direct measurement is the most 
accurate method for determining equipment leak emissions, it may also 
be time consuming and costly. In consideration of both the advantages 
of and potential burdens associated with direct measurement, the EPA is 
also proposing to provide facilities with a method to use direct 
measurement from leak surveys to develop component level emission 
factors based on site-specific leak measurement data. The site-specific 
emission factors would provide increased accuracy over the use of 
default emission factors, consistent with section II.B of this 
preamble, while lessening a portion of the burden of directly measuring 
every leak.
    We are proposing that facilities that elect to follow the direct 
measurement provisions in proposed 40 CFR 98.233(q)(3)(i) must track 
the individual measurements of natural gas flow rate by specific 
component type (valve, connector, etcetera, as applicable for the 
industry segment) and leak detection method. We are proposing three 
different bins for the leak detection methods: Method 21 using a leak 
definition of 500 ppm as specified in 40 CFR 98.234(a)(2)(i); Method 21 
using a leak definition of 10,000 ppm as specified in 40 CFR 
98.234(a)(2)(ii); and OGI and other leak detection methods as specified 
in 40 CFR 98.234(a)(1), (3), or (5). We are proposing that reporters 
would have to compile at least 50 individual measurements of natural 
gas flow rate for a specific component type and leak detection method 
(e.g., gas service valves detected by OGI) before they can develop and 
use the site-specific emission factors for the component types at the 
facility. We are proposing that these flow rate measurements would be 
required to be converted to standard conditions following the 
procedures in 40 CFR 98.233(t). We are proposing that the volumetric 
measurements comprised of at least 50 measured leakers must then be 
summed and divided by the total number of leaks measurements for that 
component type and leak detection method combination. The resulting 
value would be an emission factor in units of standard cubic feet per 
hour-component (scf/hr-component). The site-specific emission factor is 
proposed to be used, when available, to calculate equipment leak 
emissions following the procedures in 40 CFR 98.233(q)(2). Because some 
equipment component types are more prevalent and more likely to reach 
50 leak measurements than other components, application of the 
calculation methodology in 40 CFR 98.233(q)(2) may include a default 
leaker factors for some components and site-specific leaker factors for 
other components.
    For example, a hypothetical onshore petroleum and natural gas 
production facility has 30 single well-pad sites, at which during a 
reporting year they perform complete leak surveys of all components and 
direct measurements of all components found leaking at 20 of the single 
well-pad sites and they perform leak detection surveys only (i.e., no 
measurement) at the remaining 10 single well-pad sites. In this 
example, during the leak detection surveys at the 20 sites where 
measurements were also performed, the facility obtained sufficient 
measurements from valves (i.e., more than 50 measurements) to develop a 
site-specific emission factor in accordance with proposed 40 CFR 
98.233(q)(4). They did not measure enough components, however, of any 
other type (e.g., connector, open-ended line, pressure relief valve) to 
develop site-specific emission factors for these components. For this 
example, under the proposed provisions the facility must use the 
methods in 40 CFR 98.233(q)(1) and (3) to quantify emissions for that 
reporting year. The facility would be required to quantify emissions 
from the 20 monitored and directly measured single well-pad sites in 
accordance with proposed 40 CFR 98.233(q)(3). Beginning in the 
reporting year the measurements were made, the facility must develop 
and apply the site-specific emission factor for valves to any valve 
found leaking which was not directly measured (i.e., valves at the 10 
sites where only leak surveys and no measurements were performed) 
rather than applying the default emission factor. This facility would 
quantify emissions from the 10 single well sites where no measurement 
was performed using the count of components found leaking and the 
default leaker emission factors for all components in accordance with 
40 CFR 98.233(q)(1) except valves, where the site-specific emission 
factor must be used. If in subsequent reporting years, the facility is 
required to perform additional surveys or elects to continue to survey 
and perform direct measurement, the facility will accumulate additional 
measurements which may be of a sufficient number to develop other 
component type site-specific emission factors. We also note that in 
accordance with proposed 40 CFR 98.233(q)(4), any additional 
measurements of a component for which a facility has developed a site-
specific emissions factor (e.g., valves in the described example) would 
be required to be used to update the site-specific emission factor 
annually.
    We are proposing to require the use of a minimum of 50 measurements 
to ensure a statistically representative dataset. We have found that 
equipment

[[Page 50347]]

leak measurements are highly variable and it is imperative to ensure a 
robust sample size. We have performed statistical analyses with 
measurements from compressors and determined that a minimum of 50 
measurements is required to reduce uncertainty to factor of 3 of the 
true value.\99\ We are seeking comment on the required number of 
measurements by component type and leak detection method, specifically 
on whether the number is or is not appropriate, whether a different 
number is appropriate, and the supporting rationale.
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    \99\ Greenhouse Gas Reporting Rule: Technical Support for Leak 
Detection Methodology Revisions and Confidentiality Determinations 
for Petroleum and Natural Gas Systems Final Rule. November 2016. 
Docket Item No. EPA-HQ-OAR-2015-0764-0066; also available in the 
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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    We are also proposing in 40 CFR 98.236(q) to require that the 
emissions be reported at the aggregation of calculated or measured 
values for the combination of component type and leak detection method. 
As discussed in more detail in section III.P.1 of this preamble, 
numerous studies have shown that different leak detection methods 
identify different populations of leaking components; therefore, 
consistent with the delineation of the default emission factors by leak 
detection method, site-specific emission factors are proposed to be 
delineated in the same way.
5. Removal of Additional Method 21 Screening Survey for Other Screening 
Survey Methods
    We are proposing to remove the additional Method 21 screening when 
a survey is conducted using a method other than Method 21. Currently, 
facilities using survey methods other than Method 21 to detect 
equipment leaks may then screen the equipment identified as leaking 
using Method 21 to determine if the leak measures greater than 10,000 
parts per million by volume (ppmv) (see, e.g., 40 CFR 98.234(a)(1)). If 
the Method 21 screening of the leaking equipment is less than 10,000 
ppmv, then reporters may consider that equipment as not leaking. In the 
2016 subpart W revisions, we added a leak detection methodology at 40 
CFR 98.234(a)(6) (proposed 40 CFR 98.234(a)(1)(ii) in this proposal) 
for using OGI in accordance with NSPS OOOOa, which does not include an 
option for additional Method 21 screening. As noted in response to 
comments on the subpart W proposal regarding the absence of this 
optional additional Method 21 screening when using OGI in accordance 
with NSPS OOOOa, the additional screening of OGI-identified leaking 
equipment using Method 21 requires additional effort from reporters (81 
FR 86500, November 30, 2016). Furthermore, as noted previously in this 
section, the average emissions of leakers identified by OGI are greater 
than leaks identified by Method 21. Directly applying the number of 
OGI-identified leaks to the subpart W leaker emission factor specific 
to that survey method would provide the most accurate estimate of 
emissions, while selectively screening OGI-identified leaks using 
Method 21 to reduce the number of reportable leakers would yield a low 
bias in the reported emissions. Additionally, this would be incongruous 
with the proposed application and supporting rationale of the proposed 
monitoring method-specific adjustment factor, k (where the k value for 
Method 21 with a leak definition of 10,000 ppm would need to be 
applied) if OGI-identified leaks could be considered non-leaks based on 
subsequent Method 21 monitoring. Therefore, we are proposing to require 
reporters to directly use the leak survey results for the monitoring 
method used to conduct the complete leak survey and are proposing to 
eliminate this additional Method 21 screening provision. These proposed 
amendments are expected to provide more accurate emissions data, 
consistent with section II.B of this preamble.
6. Amendments Related to Oil and Natural Gas Standards and Emissions 
Guidelines in 40 CFR Part 60
    As noted in the introduction to section II. of this preamble, the 
EPA recently proposed NSPS OOOOb and EG OOOOc for certain oil and 
natural gas new and existing affected sources, respectively. Under the 
proposed standards in NSPS OOOOb and the proposed presumptive standards 
in EG OOOOc, owners and operators would be required to implement a 
fugitive emissions monitoring and repair program for the collection of 
fugitive emissions components at well site, centralized production 
facility and compressor station affected sources. In addition, the 
proposed NSPS OOOOb and EG OOOOc include a proposed appendix K to 40 
CFR part 60, specifying an OGI-based method for detecting leaks and 
fugitive emissions from all components that is not currently provided 
in subpart W. The EPA also proposed provisions in NSPS OOOOb and EG 
OOOOc for equipment leak detection and repair at onshore natural gas 
processing facilities. Similar to the 2016 amendments to subpart W (81 
FR 4987, January 29, 2016), the EPA is proposing to revise the 
calculation methodology for equipment leaks in subpart W so that data 
derived from equipment leak and fugitive emissions monitoring using one 
of the methods in 40 CFR 98.234(a) which is conducted under NSPS OOOOb 
or the applicable approved state plan or applicable Federal plan in 40 
CFR part 62 would be used to calculate emissions, consistent with 
section II.B of this preamble.
    First, under these proposed amendments, facilities with certain 
fugitive emissions components at a well site, centralized production 
facility or compressor station subject to NSPS OOOOb or an applicable 
approved state plan or applicable Federal plan in 40 CFR part 62 would 
use the data derived from the NSPS OOOOb or applicable 40 CFR part 62 
fugitive emissions requirements along with the subpart W equipment leak 
survey calculation methodology and leaker emission factors to calculate 
and report their GHG emissions to the GHGRP. Specifically, the proposed 
amendments would expand the existing cross-reference to 40 CFR 60.5397a 
to also include the analogous requirements in NSPS OOOOb or 40 CFR part 
62. Facilities with fugitive emissions components not subject to the 
standards in the proposed NSPS OOOOb or addressed by standards in a 
state or Federal plan following finalization of the proposed EG OOOOc 
would continue to be able to elect to calculate subpart W equipment 
leak emissions using the leak survey calculation methodology and leaker 
emission factors (as is currently provided in 40 CFR 98.233(q)). 
Therefore, reporters with other fugitive emission sources at subpart W 
facilities not covered by NSPS OOOOb or a state or Federal plan in 40 
CFR part 62 (e.g., sources subject to other state regulations and 
sources participating in the Methane Challenge Program or other 
voluntarily implemented programs) would continue to have the 
opportunity to voluntarily use the proposed leak detection methods to 
calculate and report their GHG emissions to the GHGRP. To facilitate 
this proposed requirement, we are also proposing to clarify in proposed 
40 CFR 98.233(q)(1)(vi)(B) and (C) that fugitive emissions monitoring 
conducted using one of the methods in 40 CFR 98.234(a) to comply with 
NSPS OOOOb or an applicable approved state plan or applicable Federal 
plan in 40 CFR part 62, respectively, is considered a ``complete leak 
detection survey,'' so that onshore petroleum and natural gas

[[Page 50348]]

production and onshore petroleum and natural gas gathering and boosting 
facilities would be able to comply with the proposed requirement to use 
NSPS OOOOb or 40 CFR part 62 fugitive emission surveys directly for 
their subpart W reports. We are also proposing to move the 
specification that fugitive emissions monitoring conducted to comply 
with NSPS OOOOa is considered a ``complete leak detection survey'' from 
existing 40 CFR 98.233(q)(2)(i) to proposed 40 CFR 98.233(q)(1)(vi)(A) 
so that all the provisions regarding what constitutes a ``complete leak 
detection survey'' are together. In a corresponding amendment, we are 
also proposing to expand the current reporting requirement in existing 
40 CFR 98.236(q)(1)(iii) (proposed 40 CFR 98.236(q)(1)(iv)) to require 
reporters to indicate if any of the surveys of well sites, centralized 
production facilities or compressor stations used in calculating 
emissions under 40 CFR 98.233(q) were conducted to comply with the 
fugitive emissions standards in NSPS OOOOb or an applicable approved 
state plan or applicable Federal plan in 40 CFR part 62.\100\ We 
request comment on these proposed amendments and whether there are 
other provisions or reporting requirements relative to NSPS OOOOb or EG 
OOOOc that we should consider for revisions to requirements under 
subpart W.
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    \100\ We are similarly proposing to revise the existing 
reporting requirement in subpart W related to NSPS OOOOa, such that 
reporters would report whether any of the surveys of well sites or 
compressor stations used in calculating emissions under 40 CFR 
98.233(q) were conducted to comply with the fugitive emissions 
standards in NSPS OOOOa (rather than simply reporting whether the 
facility has well sites or compressor stations subject to the 
fugitive emissions standards in NSPS OOOOa).
---------------------------------------------------------------------------

    Second, we are proposing to revise 40 CFR 98.234(a) to clarify and 
consolidate the requirements for OGI and Method 21 in 40 CFR 
98.234(a)(1) and (2), respectively. In the 2016 amendments to subpart W 
(81 FR 4987, January 29, 2016), the EPA added 40 CFR 98.234(a)(6) and 
(7) to provide OGI and Method 21 as specified in NSPS OOOOa as leak 
detection survey methods. In part, structuring the amendment this way 
allowed the EPA to provide the NSPS OOOOa leak detection methods as 
allowable methods under subpart W without affecting the requirements 
for facilities and industry segments not subject to NSPS OOOOa. 
However, as the EPA continues to propose additional standards with 
slightly different variations on OGI and Method 21, it would be 
unnecessarily convoluted organizationally to continue to add those 
methods and cross-references to each standard to the end of 40 CFR 
98.234(a). Therefore, the EPA is proposing to move 40 CFR 98.234(a)(1) 
and 40 CFR 98.234(a)(6) to 40 CFR 98.234(a)(1)(i) and 40 CFR 
98.234(a)(1)(ii), respectively, which would consolidate the OGI-based 
methods in 40 CFR 98.234(a)(1). Similarly, the EPA is proposing to 
revise 40 CFR 98.234(a)(2) such that 40 CFR 98.234(a)(2)(i) is Method 
21 with a leak definition of 10,000 ppm and 40 CFR 98.234(a)(2)(ii) is 
Method 21 with a leak definition of 500 ppm. This proposed amendment 
would effectively move 40 CFR 98.234(a)(7) to 40 CFR 98.234(a)(2)(ii). 
We are also proposing that the references to ``components listed in 
Sec.  98.232'' would be replaced with a more specific reference to 40 
CFR 98.233(q)(1). The references to specific provisions in 40 CFR 
60.5397a in 40 CFR 98.234(a)(6) and (7) would be moved to 40 CFR 
98.234(a)(1)(ii) and 40 CFR 98.234(a)(2), as applicable.
    In December 2022, the EPA proposed in NSPS OOOOb and EG OOOOc that 
owners and operators of natural gas processing facilities would detect 
leaks using an OGI-based monitoring method following the concurrently 
proposed appendix K to 40 CFR part 60. We are proposing to include that 
same method in subpart W at 40 CFR 98.234(a)(1)(iii) to ensure that 
reporters of those facilities would be able to comply with the proposed 
subpart W requirement to use data derived from the NSPS OOOOb or 40 CFR 
part 62 fugitive emissions requirements for purposes of calculating 
emissions from equipment leaks. In addition, as part of the December 
2022 proposal of NSPS OOOOb and EG OOOOc, the EPA proposed an 
alternative screening approach for fugitive emissions from well sites, 
centralized production facilities and compressor stations that would 
allow the use of advanced measurement technologies to detect large 
equipment leaks. Under the NSPS OOOOb and EG OOOOc proposal, if 
emissions are detected using one of these advanced technologies, 
facilities would be required to conduct monitoring using OGI or Method 
21 to identify and repair specific leaking equipment. Additionally, 
under the NSPS OOOOb and EG OOOOc proposal, even if no emissions are 
identified during a screening survey, some facilities using these 
advanced technologies would still be required to conduct annual 
fugitive emissions monitoring using OGI. The EPA's intent in this 
proposed rule for subpart W is that the results of those NSPS OOOOb and 
40 CFR part 62 OGI or Method 21 surveys would be used for purposes of 
calculating emissions for subpart W, as OGI and Method 21 are capable 
of identifying leaks from individual components and they are leak 
detection methods provided in subpart W. The EPA also requests comment 
on additional methods or advanced technologies that can identify 
individual leaking components. Based on the information received, the 
EPA would need to review the specific method and leak detection data 
collected using that method to determine what default leaker emission 
factors would apply for that method and whether any adjustments might 
be needed to the subpart W equipment leak survey calculation 
methodology when using that method. Following that review, the EPA may 
undertake a future rulemaking process to include the additional leak 
detection method(s) in 40 CFR 98.234(a).
    Third, we are proposing subpart W requirements for onshore natural 
gas processing facilities consistent with certain requirements for 
equipment leaks in the proposed NSPS OOOOb or EG OOOOc. Currently, 
onshore natural gas processing facilities must conduct at least one 
complete survey of all the components listed in 40 CFR 98.232(d)(7) 
each year, and each complete survey must be considered when calculating 
emissions according to 40 CFR 98.233(q)(2). Under the equipment leak 
detection and repair program included in proposed NSPS OOOOb and the EG 
OOOOc presumptive standards, different component types may be monitored 
on different frequencies, so all equipment at the facility is not 
always monitored at the same time. According to the current 
requirements in 40 CFR 98.233(q), surveys that do not include all of 
the applicable equipment at the facility are not considered complete 
surveys and are not used for purposes of calculating emissions. 
Therefore, we are proposing in 40 CFR 98.233(q)(1)(vi)(F) that onshore 
natural gas processing facilities subject to NSPS OOOOb or an 
applicable approved state plan or the applicable Federal plan in 40 CFR 
part 62 would use the data derived from each equipment leak survey 
conducted as required by NSPS OOOOb or the relevant subpart of 40 CFR 
part 62 along with the subpart W equipment leak survey calculation 
methodology and leaker emission factors to calculate and report GHG 
emissions to the GHGRP, even if a survey required for compliance with 
NSPS OOOOb or 40 CFR part 62 does

[[Page 50349]]

not include all the component types listed in 40 CFR 98.232(d)(7).
    Under this proposed amendment, reporters would still have to meet 
the subpart W requirement to conduct at least one complete survey of 
all applicable equipment at the facility per year, so if there were 
components listed in 40 CFR 98.232(d)(7) not included in any NSPS OOOOb 
or 40 CFR part 62-required surveys conducted during the year (e.g., 
connectors that are monitored only once every 4 years), reporters 
subject to NSPS OOOOb or 40 CFR part 62 would need to either add those 
components to one of their required surveys, making that a complete 
survey for purposes of subpart W, or conduct a separate complete survey 
for purposes of subpart W. We expect that reporters with onshore 
natural gas processing plants implementing traditional leak detection 
and repair programs are already making similar decisions regarding how 
to meet the requirement to conduct a complete survey for subpart W, and 
our intention with this proposed amendment is not to change those 
decisions. Rather, this amendment would specify that surveys conducted 
pursuant to NSPS OOOOb or 40 CFR part 62 that do not include all 
component types listed in 40 CFR 98.232(d)(7) would be used for 
calculating emissions along with each complete survey.
    We are also proposing to add leaker emission factors for all survey 
methods for ``other'' components that would be required to be monitored 
under NSPS OOOOb or an approved state plan or applicable Federal plan 
in 40 CFR part 62 or that reporters elect to survey that are not 
currently included in subpart W. These proposed THC leaker emission 
factors for the ``other'' component type are of the same value as the 
THC leaker emission factors for the ``other'' component type for the 
Onshore Natural Gas Transmission Compression and the Underground 
Natural Gas Storage industry segments (existing Table W-3A and Table W-
4A, respectively, proposed Table W-4). For more information on the 
derivation of the original emission factors, see the 2010 subpart W 
TSD,\101\ and for more information on the derivation of the ``other'' 
component type emission factor proposed to be applied to these types of 
leaks at facilities in the Onshore Natural Gas Processing industry 
segment, see the TSD for the 2016 amendments to subpart W.\102\ In a 
corresponding amendment, we are also proposing to expand the reporting 
requirement in existing 40 CFR 98.236(q)(1)(iii) (proposed 40 CFR 
98.236(q)(1)(iv)) to require onshore natural gas processing reporters 
to indicate if any of the surveys used in calculating emissions under 
40 CFR 98.233(q) were conducted to comply with the equipment leak 
standards in NSPS OOOOb or an applicable approved state plan or the 
applicable Federal plan in 40 CFR part 62. We request comment on the 
proposed amendments to subpart W for onshore natural gas processing 
facilities subject to the equipment leak provisions of NSPS OOOOb or 40 
CFR part 62, as well as whether there are other provisions or reporting 
requirements for these facilities that we should consider.
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    \101\ 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.
    \102\ Greenhouse Gas Reporting Rule: Technical Support for Leak 
Detection Methodology Revisions and Confidentiality Determinations 
for Petroleum and Natural Gas Systems. November 1, 2016. Docket Id. 
No. EPA-HQ-OAR-2015-0764-0066; also available in the docket for this 
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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    Finally, in our review of subpart W equipment leak requirements for 
onshore natural gas processing facilities, we found that the leak 
definition for the Method 21-based requirements for processing plants 
in NSPS OOOOa (as well as proposed NSPS OOOOb and EG OOOOc presumptive 
standards) is not consistent with the leak definition in the Method 21 
option in current 40 CFR 98.234(a)(2), which is the only Method 21-
based method available to onshore natural gas processing facilities 
under subpart W. Based on this review, and to complement the proposed 
addition of default leaker emission factors for survey methods other 
than Method 21 (as described previously in this preamble), we are 
proposing several additions to the equipment leak survey requirements 
for the Onshore Natural Gas Processing industry segment, beyond those 
amendments already described related to the proposed NSPS OOOOb and EG 
OOOOc presumptive standards. First, we are proposing default leaker 
emission factors for Method 21 at a leak definition of 500 ppm in 
proposed Table W-4. As with the proposed ``other'' component type 
leaker emission factors, these proposed leaker emission factors (i.e., 
valve, connector, open-ended line, pressure relief valve and meter) are 
of the same value as the THC leaker emission factors for the Onshore 
Natural Gas Transmission Compression and the Underground Natural Gas 
Storage industry segments (existing Table W-3A and Table W-4A, 
respectively). For more information on the derivation of those emission 
factors, see the TSD for the 2016 amendments to subpart W.\103\ In 
addition, we are proposing to add 40 CFR 98.233(q)(1)(v) to indicate 
that onshore natural gas processing facilities not subject to NSPS 
OOOOb or an approved state plan or the applicable Federal plan in 40 
CFR part 62 may use any method specified in 40 CFR 98.234(a), including 
Method 21 with a leak definition of 500 ppm and OGI following the 
provisions of appendix K to 40 CFR part 60. This proposed amendment 
would ensure that equipment leak surveys conducted using any of the 
approved methods in subpart W would be available for purposes of 
calculating emissions, not just those surveys conducted using one of 
the methods currently provided in 40 CFR 98.234(a)(1) through (5).
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    \103\ Greenhouse Gas Reporting Rule: Technical Support for Leak 
Detection Methodology Revisions and Confidentiality Determinations 
for Petroleum and Natural Gas Systems. November 1, 2016. Docket Id. 
No. EPA-HQ-OAR-2015-0764-0066; also available in the docket for this 
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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7. Exemption for Components in Vacuum Service
    Through correspondence with the EPA via e-GGRT, some reporters have 
stated that certain equipment leak components at their facility are in 
vacuum service. These reporters indicated that there are no fugitive 
emissions expected from components in vacuum service. After 
consideration of these comments and in order to be consistent with 
other EPA equipment leak regulatory programs (e.g., 40 CFR part 60, 
subpart VVa), we have determined that we agree with commenters. 
Therefore, we are proposing an exemption in the introductory paragraphs 
of 40 CFR 98.233(q) and (r) for leak components in vacuum service from 
the requirement to estimate and report emissions from these components. 
We are also proposing a definition in 40 CFR 98.238 for the term ``in 
vacuum service.'' We are proposing to require the reporting of the 
count of equipment in vacuum service to enable verification of the 
reported data (i.e., ability to confirm that all equipment for which 
emissions are expected has been accounted for and an indication that 
other equipment has been confirmed to meet the proposed definition of 
``in vacuum service'').

Q. Equipment Leaks by Population Count

    As noted in section III.P of this preamble, subpart W reporters are 
currently required to quantify emissions from equipment leaks using the

[[Page 50350]]

calculation methods in 40 CFR 98.233(q) (equipment leak surveys) and/or 
40 CFR 98.233(r) (equipment leaks by population count), depending upon 
the industry segment. The equipment leaks by population count method 
uses the count of equipment components, subpart W emission factors 
(e.g., existing Table W-1A for the Onshore Petroleum and Natural Gas 
Production industry segment), and operating time to estimate emissions 
from equipment leaks. For the Onshore Petroleum and Natural Gas 
Production and Onshore Petroleum and Natural Gas Gathering and Boosting 
industry segments, the count of equipment components currently may be 
determined by counting each component individually for each facility 
(Component Count Method 2) or the count of equipment components may be 
estimated using the count of major equipment and subpart W default 
average component counts for major equipment (Component Count Method 1) 
in existing Tables W-1B and W-1C, as applicable. Reporters in other 
industry segments currently must count each applicable component at the 
facility. We are proposing several amendments to the calculation 
methodology provisions of 40 CFR 98.233(r) and the reporting 
requirements in 40 CFR 98.236(r) to improve the quality of the data 
collected, consistent with sections II.B and II.C of this preamble.
1. Onshore Petroleum and Natural Gas Production and Onshore Petroleum 
and Natural Gas Gathering and Boosting Population Count Method
    The current population emission factors for the Onshore Petroleum 
and Natural Gas Production and Onshore Petroleum and Natural Gas 
Gathering and Boosting industry segments are found in existing Table W-
1A of subpart W. The gas service population emission factors are based 
on the 1996 GRI/EPA study Methane Emissions from the Natural Gas 
Industry, Volume 8: Equipment Leaks (available in the docket for this 
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234). The oil service 
population emission factors are based on the American Petroleum 
Institute's (API) Emission Factors for Oil and Gas Production 
Operations, Publication 4615, published in 1995.
    As noted previously in this section, when estimating emissions 
using the population count method, onshore petroleum and natural gas 
production facilities and onshore petroleum and natural gas gathering 
and boosting facilities currently have the option to use actual 
component counts (i.e., Component Count Method 2) or to estimate their 
component counts using the count of major equipment (e.g., wellhead) 
and default component counts per major equipment (e.g., valves per 
wellhead) included in existing Tables W-1B and W-1C of subpart W (i.e., 
Component Count Method 1). In reviewing subpart W data, we find that 
the vast majority (greater than 95 percent) of onshore production and 
natural gas gathering and boosting facilities use Component Count 
Method 1 to estimate the count of components.
    It is important to note that both the population count emission 
factors and the default component counts per major equipment currently 
included in Tables W-1A, W-1B and W-1C are service-specific (i.e., gas 
or oil) as well as region-specific (i.e., eastern or western U.S.). The 
regional designations are provided by U.S. state in existing Table W-1D 
of subpart W such that a facility would determine the facility's region 
and select the appropriate region- and service-specific factors.
    In the years that have followed the adoption of these emission 
factors into subpart W, there have been numerous studies regarding 
emissions from equipment leaks at onshore production and gathering and 
boosting facilities. Two recent field studies, Pacsi et al. (2019) 
\104\ and Zimmerle et al. (2020),\105\ have performed an equipment and 
component inventory alongside equipment leak screening and measurement 
results. Another recent study, Rutherford et al. (2021),\106\ included 
synthesis and analysis of measurements from component-level field 
studies. These studies' data allow development of study-estimated 
population emission factors as well as study-estimated default 
component counts per major equipment and comparison of them to those in 
subpart W. Comparison of the study-estimated default component counts 
per major equipment found that the subpart W values underestimate the 
count of components found on major equipment in the field (Zimmerle et 
al., 2020; Pacsi et al., 2019). Regarding a comparison of the 
population emission factors and component counts per major equipment 
between the subpart W eastern and western values, Zimmerle et al. 
(2020) was the only field study to include both eastern and western 
facilities, and the study values showed ``no statistically significant 
differences between eastern and western U.S. regions.'' Rutherford et 
al. (2021) also found their study-estimated population emission factors 
to be higher than those in subpart W, noting that one of the 
contributing factors to this difference was the use of the eastern 
factors in subpart W, which appear to significantly undercount 
emissions. Rutherford et al. (2021) noted that the impact of the use of 
the eastern factors has grown over time as the production in the 
eastern region of the U.S. has increased from less than 5 percent of 
gas produced to nearly 30 percent of the gas produced.
---------------------------------------------------------------------------

    \104\ Pacsi, A.P. et al. Equipment leak detection and 
quantification at 67 oil and gas sites in the Western United States. 
Elementa (2019). https://doi.org/10.1525/elementa.368. Available in 
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    \105\ Zimmerle, D., et al. Methane Emissions from Gathering 
Compressor Stations in the U.S. Environmental Science & Technology 
54 (12), 7552-7561 (2020). https://doi.org/10.1021/acs.est.0c00516. 
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
    \106\ Rutherford, J.S., Sherwin, E.D., Ravikumar, A.P. et al. 
Closing the methane gap in US oil and natural gas production 
inventories. Nat Commun 12, 4715 (2021). https://doi.org/10.1038/s41467-021-25017-4. Available in the docket for this rulemaking, 
Docket Id. No. EPA-HQ-OAR-2023-0234.
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    In the 2022 Proposed Rule, we proposed to revise the current 
population emission factors to use major equipment-based emission 
factors developed using a combination of data from Zimmerle et al., 
2020 and Pacsi et al., 2019. As described in more detail below, 
consistent with the 2022 Proposed Rule, we are again proposing revised 
emission factors on a per major equipment basis rather than on a per 
component basis. However, in this proposed rulemaking, we are proposing 
to use the data from Rutherford et al. (2021), which is comprised of 
several published studies including Pacsi et al. 2019, to inform the 
emission factor values. As described in more detail below, the 
Rutherford et al. (2021) study represents the largest dataset set 
available and thus, more accurately accounts for the variability 
observed in equipment leak measurement data in terms of the size and 
frequency of leaks.
    Based on our review of these studies, our assessment is that they 
support revision of the population count method and corresponding 
emission factors for onshore petroleum and natural gas production and 
onshore petroleum and natural gas gathering and boosting facilities and 
we are proposing to amend this population count method and 
corresponding emission factors after consideration of these more recent 
study data, consistent with section II.B of this preamble. These 
proposed amendments include new population emission factors that are on 
a per major equipment basis rather than a per component basis. As 
mentioned previously, the vast majority of reporters estimate the 
component counts using

[[Page 50351]]

Component Count Method 1. By providing emission factors on a major 
equipment basis instead of by component, we would eliminate the step to 
estimate the number of components. All facilities would be able to 
count the actual number of major equipment and consistently apply the 
same emission factor to calculate emissions. This would reduce reporter 
burden and reduce the number of errors in the calculation of emissions, 
as we find that numerous facilities incorrectly estimate the number of 
components using Component Count Method 1 while providing consistently 
estimated emission results.
    In comparing the recent study data for this proposal, our 
assessment is that the Rutherford et al. (2021) study represents the 
most robust sample size of approximately 3,700 measurements for 
developing population emission factors by major equipment. The larger 
sample size is likely more representative of varying degrees of leak 
detection and repair programs (i.e., not only facilities conducting 
frequent surveys), which can impact the number of leaks found during 
surveys (i.e., if more frequent surveys are being conducted and leaks 
are being repaired in a timely manner, then each survey likely finds 
less leaks). The Rutherford et al. (2021) study also employs a 
bootstrap resampling statistical approach \107\ that allows for the 
inclusion of infrequent large emitters (i.e., ``super-emitters'') in 
the development of the emission factors, improving the representation 
of the inherent variability of equipment leaks in the developed 
emission factors. Therefore, we are proposing major equipment emission 
factors developed using Rutherford et al. (2021) to provide population 
emission factors by major equipment and site type (i.e., natural gas 
system or petroleum system). The proposed emission factors were taken 
from Supplementary Tables 3 and 4 of Rutherford et al. (2021). The 
average emission factors presented in these study tables were converted 
from units of kilograms per day to standard cubic feet of whole gas per 
hour for cumulative equipment component leaks from different types of 
major equipment including wellheads, separator, heater, meter including 
headers, compressor, dehydrator and tanks. The major equipment 
indicating venting emissions (e.g., tanks--unintentional vents) or 
emissions from other sources also covered by subpart W (e.g., liquids 
unloading, flaring, pumps) are not included in the proposed equipment 
leak population emission factors. Specific to meters/piping and 
consistent with current requirements related to meters/piping at 
existing 40 CFR 98.233(r)(2)(i)(A), we are proposing in 40 CFR 
98.233(r)(2) to specify that one meters/piping equipment should be 
included per well-pad for onshore petroleum and natural gas production 
operations and the count of meters in the facility should be used for 
this equipment category at onshore petroleum and natural gas gathering 
and boosting facilities. As a consequence of the broader scope of 
equipment surveyed in the study data that inform Rutherford et al. 
(2021), the proposed emission factors in proposed Table W-1 include 
more pieces of major equipment than are currently included in Table W-
1B and W-1C of subpart W. A complete description of the 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. The proposed major equipment emission factors 
would replace the current component-based emission factors in the 
existing Table W-1A. We are also proposing to remove Tables W-1B, W-1C, 
and W-1D since they would no longer be needed for the population count 
method for these industry segments. We are proposing amendments to the 
reporting requirements for the use of the population count method to 
align with the reporting of major equipment counts consistent with the 
proposed emission factors in 40 CFR 98.236(r). We are seeking comment 
on the development of population count emission factors based on major 
equipment. We are also seeking comment on the proposed use of the 
Rutherford et al. (2021) study data instead of using study data from 
Zimmerle et al. (2020) and/or Pacsi et al. (2019) to provide the 
population count emission factors by major equipment, and the rationale 
supporting the use of the respective study data.
---------------------------------------------------------------------------

    \107\ Bootstrapping is a type of resampling where a known 
dataset is repeatedly drawn from, with replacement, to generate a 
sample distribution.
---------------------------------------------------------------------------

2. Natural Gas Distribution Emission Factors
    Natural gas distribution companies currently quantify the emissions 
from equipment leaks from pipeline mains and services, below grade 
transmission distribution transfer stations, and below grade metering-
regulating stations following the procedures in 40 CFR 98.233(r). This 
method uses the count of equipment, subpart W population emission 
factors in existing Table W-7 (proposed Table W-5 in this proposal), 
and operating time to estimate emissions. The population emission 
factors for distribution mains and services in existing Table W-7 
(proposed Table W-5) are based on information from the 1996 GRI/EPA 
study.\108\ Specifically for plastic mains, additional data are sourced 
from a 2005 ICF analysis.\109\ The population emission factors for 
distribution mains are published per mile of main by pipeline material 
and emission factors for distribution services are published per 
service by pipeline material. The population emission factors for below 
grade stations in existing Table W-7 (proposed Table W-5) are based on 
information from the 1996 GRI/EPA study.\110\ The population emission 
factors for below grade transmission-distribution transfer stations and 
below grade metering-regulating stations are currently specified in the 
existing Table W-7 per station by three inlet pressure categories (>300 
pounds per square inch gauge (psig), 100-300 psig, < 100 psig).
---------------------------------------------------------------------------

    \108\ GRI/EPA. Methane Emissions from the Natural Gas Industry, 
Volume 9: Underground Pipelines. Prepared for Gas Research Institute 
and U.S. Environmental Protection Agency National Risk Management 
Research Laboratory by L.M. Campbell, M.V. Campbell, and D.L. 
Epperson, Radian International LLC. GRI-94/0257.2b, EPA-600/R-96-
080i. June 1996. Available in the docket for this rulemaking, Docket 
Id. No. EPA-HQ-OAR-2023-0234.
    \109\ ICF. Fugitive Emissions from Plastic Pipe, Memorandum from 
H. Mallya and Z. Schaffer, ICF Consulting to L. Hanle and E. 
Scheehle, EPA. June 30, 2005. Available in the docket for this 
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    \110\ GRI/EPA. Methane Emissions from the Natural Gas Industry, 
Volume 10: Metering and Pressure Regulating Stations in Natural Gas 
Transmission and Distribution. Prepared for Gas Research Institute 
and U.S. Environmental Protection Agency National Risk Management 
Research Laboratory by L.M. Campbell and B.E. Stapper, Radian 
International LLC. GRI-94/0257.27, EPA-600/R-96-080j. June 1996. 
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
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    In this rulemaking, the EPA is proposing to update the population 
emission factors in existing Table W-7 (proposed Table W-5) to subpart 
W using the results of studies and information that were not available 
when the rule was finalized in 2010. Notably, the EPA reviewed recent 
studies and updated the emission factors for several natural gas 
distribution sources, including pipeline mains and services and below 
grade stations, for the 2016 U.S. GHG Inventory.\111\ The majority of 
the U.S. GHG Inventory updates were based on

[[Page 50352]]

data published by Lamb et al. in 2015.\112\ Since the time that the 
2016 U.S. GHG Inventory updates were made, additional studies for 
pipeline distribution mains have been published and reviewed by the 
EPA, notably Weller et al. in 2020.\113\ Our assessment of the studies 
published since subpart W was finalized supports revising the emission 
factors for pipelines in the Natural Gas Distribution industry segment 
of subpart W.
---------------------------------------------------------------------------

    \111\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and 
Sinks 1990-2014: Revisions to Natural Gas Distribution Emissions. 
April 2016. Available at https://www.epa.gov/sites/production/files/2016-08/documents/final_revision_ng_distribution_emissions_2016-04-14.pdf and in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
    \112\ Lamb, B.K. et al. ``Direct Measurements Show Decreasing 
Methane Emissions from Natural Gas Local Distribution Systems in the 
United States.'' Environ. Sci. Technol. 2015, 49, 5161-5169. 
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
    \113\ Weller, Z.D.; Hamburg, S.P.; and Von Fischer, J.C. 2020. 
``A National Estimate of Methane Leakage from Pipeline Mains in 
Natural Gas Local Distribution Systems.'' Environ. Sci. Technol. 
2020, 54(1), 8958. Available in the docket for this rulemaking, 
Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    The population emission factors for distribution mains and services 
are a function of the average measured leak rate (in standard cubic 
feet per hour) and the frequency of annual leaks observed (leaks/mile-
year or leaks/service-year) by pipeline material (e.g., protected 
steel, plastic). The Lamb et al. and Weller et al. studies utilized 
different approaches for quantifying leak rates and determining the 
pipeline material-specific frequency of annual leaks. The Lamb et al. 
study quantified leaks from distribution mains and services using a 
high volume sampling method and some downwind tracer measurements and 
estimated the frequency of leaks by pipeline material using company 
records and Department of Transportation (DOT) repaired leak records 
from six local distribution companies (LDCs). This methodology was 
consistent with the 1996 GRI/EPA study. The Weller et al. study 
quantified leaks from only distribution mains using the AMLD technique, 
which involves mobile surveying using high sensitivity instruments and 
algorithms that predict the leak location and size, attributed leaks to 
the pipeline material using geographic information system (GIS) data, 
and estimated the frequency of leaks using modeling.
    In the 2022 Proposed Rule, we proposed to revise the pipeline main 
equipment leak emission factors using a combination of data from Lamb 
et al. (2015) and Weller et al. (2020). We sought comment on the 
approach of combining data from these two studies. We received numerous 
comments regarding the classification of pipeline materials and 
respective quantified leaks in the Weller et al. (2020) study. In 
response to these comments and as discussed in more detail below, we 
agree with commenters that the categorization of pipeline leaks by 
material type likely resulted in inaccuracies specifically for the 
unprotected and protected steel pipeline material types. In this 
rulemaking, we are continuing to propose revisions of the equipment 
leak pipeline main emission factors using more recent study data, but 
instead of combining data from Lamb et al. (2015) and Weller et al. 
(2020), we are proposing to rely only on the Lamb et al. (2015) study.
    In subpart W, there are currently four categories of pipeline 
mains: unprotected steel, protected steel, plastic, and cast iron. The 
steel categories are differentiated by the presence of cathodic 
protection, and, as evidenced by the 1996 GRI/EPA study and Lamb et al. 
study data, unprotected steel pipelines are considered to be more leak 
prone than cathodically protected steel pipelines. In the Weller et al. 
study, the categories of pipeline mains include bare (unprotected) 
steel, coated (protected) steel, cast iron, and plastic. We note that 
steel pipelines can be protected by cathodic protection and/or coating, 
and in the Weller et al. study, cathodically unprotected yet coated 
steel pipeline mains appear to have been grouped with cathodically 
protected steel pipeline mains. Using the unprotected and protected 
steel classifications in the Weller et al. study would thus result in 
emission factors for protected steel that are higher than for 
unprotected steel, which would conflict with other study data (e.g., 
1996 GRI/EPA, Lamb et al.) as well as voluntary emissions reductions 
programs (e.g., EPA Natural Gas STAR). The pipeline categories in the 
Weller et al. study do not provide the necessary differentiation to 
properly update the emission factors for unprotected (i.e., not 
cathodically protected) steel and cathodically protected steel pipeline 
mains. For more information on the review and analysis of the Lamb et 
al. and Weller et al. studies, see the subpart W TSD, available in the 
docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-2023-0234).
    In consideration of our review and analysis of recent study data 
relative to natural gas pipeline mains and services, and consistent 
with the emission factors used in the 2016 U.S. GHG Inventory, we are 
proposing to provide emission factors for distribution pipeline mains 
and services based on the Lamb et al. study leak rates and the 1996 
GRI/EPA study leak incidence data. For more information on the 
derivation of the proposed emission factors, see the subpart W TSD, 
available in the docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-
2023-0234).
    We are also seeking comments on alternative methods for quantifying 
and reporting emissions from distribution mains and services. For 
distribution mains and services, we are seeking comments on the use of 
direct measurement as well as application of a leaker emission factor 
approach. For the use of direct measurement, we are seeking comment on 
whether facilities should be permitted to develop facility-specific 
distribution main and service emission factors for each type of 
pipeline material 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. For facility-specific emission factors based on 
direct measurement, we are seeking comment on the development of both 
leaker emission factors and population emission factors. We are seeking 
comment on what quantification techniques are best suited for measuring 
emissions from distribution pipeline leaks and whether these techniques 
require digging down to the pipeline in order to quantify emissions and 
also verify pipeline characteristics. For a leaker emission factor 
approach, we are specifically interested in what survey techniques are 
appropriate and why, including supporting information on specific 
instruments and their detection capabilities and whether certain 
methods are more suitable for the survey of distribution pipeline leaks 
than others. We are seeking comment on the scope and frequency of leak 
detection surveys for distribution pipelines and whether annual surveys 
of the entire pipeline system or 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 
application of a leaker emission factor approach using default factors 
(i.e., not facility specific based on direct measurement) and available 
data that could be used in the development of default leaker emission 
factors for distribution mains and services.
    For below grade stations, the 2016 U.S. GHG Inventory also began 
applying a new emission factor from the data published by Lamb et al. 
to the count of stations to estimate emissions from these sources. In 
order to assess the

[[Page 50353]]

appropriateness of incorporating this revision into the subpart W 
requirements for below grade stations (i.e., replacing the set of below 
grade emission factors by station type and inlet pressure with one 
single emission factor), the EPA performed an analysis of the reported 
subpart W data for below grade stations compared to data from the 
recent studies (see the subpart W TSD, available in the docket for this 
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234). We found that the 
subpart W reported station count combined with the current subpart W 
emission factors yields an average emission factor similar to the U.S. 
GHG Inventory emission factor; as such, using either set of emission 
factors would yield approximately the same emissions results for the 
GHGRP.
    Therefore, we are proposing to amend the emission factors for below 
grade transmission-distribution transfer stations and below grade 
metering-regulating stations in existing Table W-7 (proposed Table W-5) 
to a single emission factor without regard to inlet pressure. We are 
also proposing to amend the corresponding section header in existing 
Table W-7 (proposed Table W-5) for below grade station emission factors 
and the references to existing Table W-7 (proposed Table W-5) in 40 CFR 
98.233(r)(6)(i) to clarify the emission factor that should be applied 
to both types of below grade stations (i.e., transmission-distribution 
transfer and metering-regulating). This proposed amendment would impact 
the reporting requirements in 40 CFR 98.236(r) as well, as it would 
consolidate six emission source types to two emission source types 
(below grade transmission-distribution transfer stations and below 
grade metering-regulating stations, without differentiating between 
inlet pressures) for purposes of reporting under 40 CFR 98.236(r)(1). 
This proposed amendment would improve the data quality through use of 
more recent emission factors and would be consistent with changes made 
to the U.S. GHG Inventory. It would also result in reporting of fewer 
data elements, consistent with section II.C of this preamble.
3. Gathering Pipeline Emission Factors
    Facilities in the Onshore Petroleum and Natural Gas Gathering and 
Boosting industry segment currently quantify the emissions from 
equipment leaks from gathering pipelines following the procedures in 40 
CFR 98.233(r). This method uses the count of equipment, subpart W 
population emission factors in existing Table W-1A, and operating time 
to estimate emissions. The population emission factors for gathering 
pipeline mains in existing Table W-1A are based on leak rates from 
natural gas distribution companies and gathering pipeline-specific 
activity data as provided in the 1996 GRI/EPA study.\114\ The 
population emission factors for gathering pipelines are published per 
mile by pipeline material.
---------------------------------------------------------------------------

    \114\ GRI/EPA. Methane Emissions from the Natural Gas Industry, 
Volume 9: Underground Pipelines. Prepared for Gas Research Institute 
and U.S. Environmental Protection Agency National Risk Management 
Research Laboratory by L.M. Campbell, M.V. Campbell, and D.L. 
Epperson, Radian International LLC. GRI-94/0257.2b, EPA-600/R-96-
080i. June 1996. Available in the docket for this rulemaking, Docket 
Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    The EPA is aware of a recent study that characterized emissions 
from gathering pipelines and could potentially be used to develop 
population emission factors, Yu et al. (2022).\115\ The Yu et al. 
(2022) study used measurements acquired over four aerial campaigns of 
the Midland and Delaware sub-basins in the Permian basin. The resulting 
emission rate provides a basin-level population emission factor 
(megagrams CH4 per kilometer-year). The EPA is not proposing 
to use this data in subpart W for the development of gathering pipeline 
emission factors because it does not specify the pipeline material 
type, as the current subpart W and proposed subpart W emission factors 
do. The material-specific emission factors more readily allow operators 
to track and quantify emission reductions from pipeline replacement 
projects (e.g., replacing more leak prone pipeline materials such as 
cast iron with less leak prone materials such as plastic). The 
resulting emission factors from Yu et al. rely on emission estimation 
techniques that have a lower degree of sensitivity than ground-based 
measurements. In order to overcome this limitation, the study authors 
performed sensitivity analyses to account for below detection limit 
leaks. The major finding of this study is that gathering pipelines have 
highly skewed emissions data distribution with very large leaks that 
only occur every few hundred miles. Finally, our assessment is that 
this study is geographically limited and are concerned that an emission 
factor derived with these study data may not be nationally 
representative. Additional discussion of the Yu et al. study, including 
population emission factors developed using study data as they compare 
to subpart W, is included in the subpart W TSD, available in the docket 
for this rulemaking (Docket Id. No. v). We are seeking comment on the 
EPA's decision not to use the Yu et al. study data in developing 
proposed population emission factors, including rationale supporting 
the EPA's decision or rationale for why this study should be used in 
developing proposed population emission factors. Additionally, we are 
seeking comments on whether there are other published studies the EPA 
should evaluate for potential use in developing revised emission 
factors for gathering pipelines.
---------------------------------------------------------------------------

    \115\ Yu, J. et al. ``Methane Emissions from Natural Gas 
Gathering Pipelines in the Permian Basin.'' Environ. Sci. Technol. 
Lett. 2022, 9, 969-974. Available in the docket for this rulemaking, 
Docket Id. No. EPA-HQ-OAR-2023-0234.
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    As noted previously in this section, the EPA is proposing to update 
the natural gas distribution population emission factors in existing 
Table W-7 (proposed Table W-5) to subpart W using the results of 
studies and information that were not available when the rule was 
originally finalized. In particular, the EPA is proposing to update the 
leak rate portion of the emission factor based on data published by 
Lamb et al. in 2015.\116\
---------------------------------------------------------------------------

    \116\ Lamb, B.K. et al. ``Direct Measurements Show Decreasing 
Methane Emissions from Natural Gas Local Distribution Systems in the 
United States.'' Environ. Sci. Technol. 2015, 49, 5161-5169. 
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

    The EPA has reviewed the recent studies published for Onshore 
petroleum and natural gas gathering and boosting facilities including 
the previously discussed Yu et al. study, as well as the additional 
studies for pipeline distribution mains, and concluded none of the 
studies provide new emissions data or activity data specific to 
gathering pipelines suitable to update the existing emission factors. 
Therefore, consistent with the updates to the emission factors for 
distribution mains, and consistent with section II.B of this preamble, 
we are proposing to revise the gathering pipeline population emission 
factors in proposed Table W-1 to use the leak rates from Lamb et al. 
(2015). We are not proposing to update the activity data (leaks per 
mile of pipeline) portion of the emission factors, as the information 
in the 1996 GRI/EPA study continues to be the best available data 
specific to gathering pipelines. For more information on the proposed 
updates to the gathering pipeline population emission factors, see the 
subpart W TSD, available in the docket for this rulemaking (Docket Id. 
No. EPA-HQ-OAR-2023-0234).
    We are also seeking comments on alternative methods for quantifying 
and reporting emissions from gathering pipelines. We are seeking 
comments on the use of direct measurement as well as

[[Page 50354]]

application of a leaker emission factor approach. For the use of direct 
measurement, we are seeking comment on whether facilities should be 
permitted to develop facility-specific emission factors for each type 
of pipeline material 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. For facility-specific emission factors based on 
direct measurement, we are seeking comment on the development of both 
leaker emission factors and population emission factors. We are seeking 
comment on what quantification techniques are best suited for measuring 
emissions from gathering pipeline leaks and whether these techniques 
require digging down to the pipeline in order to quantify emissions and 
also verify pipeline characteristics. For a leaker emission factor 
approach, we are specifically interested in what survey techniques are 
appropriate and why, including supporting information on specific 
instruments and their detection capabilities and whether certain 
methods are more suitable for the survey of gathering pipeline leaks 
than others. We are seeking comment on the scope and frequency of leak 
detection surveys for gathering pipelines and whether annual surveys of 
the entire pipeline system or 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 
application of a leaker emission factor approach using default factors 
(i.e., not facility specific based on direct measurement) and available 
data that could be used in the development of default leaker emission 
factors for gathering pipelines.

R. Offshore Production

    Currently, subpart W requires offshore production facilities to 
report emissions consistent with the methods published by the U.S. 
Department of Interior, Bureau of Ocean Energy Management (BOEM). Since 
subpart W was first promulgated, there have been a number of updates to 
the BOEM requirements and how BOEM implements the requirements (e.g., 
the development of their Outer Continental Shelf Air Quality System 
(OCS AQS) \117\), and the EPA is proposing to amend subpart W to 
reflect those changes. Specifically, the EPA is proposing to update 
outdated acronym ``BOEMRE'' to the current acronym ``BOEM'' in 40 CFR 
98.232(b), 40 CFR 98.233(s), and 40 CFR 98.236(s); to update the cross 
references to the BOEM requirements from ``30 CFR 250.302 through 304'' 
to ``30 CFR 550.302 through 304'' in 40 CFR 98.232(b), 40 CFR 
98.233(s), and the introductory paragraph of 40 CFR 98.234; and to 
remove the outdated references to ``GOADS'' from 40 CFR 98.233(s). The 
EPA is also proposing to adjust some of the language in 40 CFR 
98.232(b) and 40 CFR 98.233(s) to more accurately reflect the current 
BOEM program and requirements (e.g., adjusting the number of years 
between BOEM data collection efforts from 4 to 3 years, referring to 
published data and data submitted to BOEM rather than an emissions 
study).
---------------------------------------------------------------------------

    \117\ For more information on this system and the emissions 
inventories collected by the system, see https://www.boem.gov/environment/environmental-studies/ocs-emissions-inventories.
---------------------------------------------------------------------------

    Emissions data are collected by BOEM every few years. In years that 
coincide with a year in which BOEM collects data, offshore production 
facilities that report emissions inventory data to BOEM report the same 
annual emissions to subpart W as calculated and reported to BOEM 
(existing 40 CFR 98.233(s)(1)) and facilities that do not report 
emissions inventory data to BOEM must use the most recent monitoring 
and calculation methods published by BOEM (existing 40 CFR 
98.233(s)(2)). In the intervening years, reporters currently are 
required to adjust emissions based on the operating time for the 
facility in the current reporting year relative to the operating time 
in the most recent BOEM data submission or BOEM emissions study 
publication year. The EPA is proposing two revisions for these 
intervening years. First the EPA is proposing to require reporters to 
report two new data elements in these years, the facility's operating 
hours in the current year and the facility's operating hours from the 
BOEM emission study publication year that is the basis for the reported 
emissions. This information would improve verification, consistent with 
section II.C of this preamble. Second, as an alternative to the current 
adjustment using operating hours in years that do not overlap with the 
most recent BOEM data submission or BOEM emissions study publication 
year, as applicable, the EPA is also proposing to allow reporters to 
calculate emissions using the most recent monitoring and calculation 
methods published by BOEM referenced in 30 CFR 550.302 through 304 
(implemented through the OCS AQS). This alternative is expected to 
improve data quality through the use of more empirical data, consistent 
with section II.B of this preamble.
    Finally, to better align the emissions reported by offshore 
production facilities between BOEM's Outer Continental Shelf Emissions 
Inventory and the GHGRP, the EPA is proposing that offshore production 
facilities report the BOEM Facility IDs that constitute the GHGRP 
facility. Having a definitive point of reference between the two 
datasets would allow the EPA to better verify the emissions reported to 
the GHGRP.

S. Combustion Equipment

1. Clarifications of Calculation Methodology Applicability
    All facilities reporting under subpart W except those in the 
Onshore Natural Gas Transmission Pipeline industry segment must include 
combustion emissions in their annual report. Facilities in the Onshore 
Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas 
Gathering and Boosting, and Natural Gas Distribution industry segments 
calculate emissions in accordance with the provisions in 40 CFR 
98.233(z) and report combustion emissions per 40 CFR 98.236(z). 
Reporters in the other industry segments calculate and report 
combustion emissions under subpart C (General Stationary Fuel 
Combustion Sources). Subpart W refers reporters in these segments to 
the calculation methodologies in subpart C to determine combustion 
emissions for certain fuels. Specifically, 40 CFR 98.233(z)(1) 
specifies that reporters may use any tier of subpart C if the fuel 
combusted is listed in Table C-1; the paragraph further specifies that 
the subpart C methodologies may only be used for fuel meeting the 
definition of ``natural gas'' in 40 CFR 98.238 if it is also of 
pipeline quality specification and has a minimum HHV of 950 British 
thermal units per standard cubic foot (Btu/scf). If the fuel is natural 
gas that does not meet these criteria, field gas, process vent gas, or 
a blend containing field gas or process vent gas, 40 CFR 98.233(z)(1) 
specifies that the procedures in 40 CFR 98.233(z)(2) should be used to 
calculate combustion emissions.
    Certain stakeholders have identified several concerns with these 
requirements. In general, these stakeholders have stated that the 
ability to use subpart C calculation methodologies is too restrictive, 
and some of their feedback also indicates

[[Page 50355]]

they may have been misinterpreting some of the provisions. We are 
proposing several amendments to these provisions to address these 
concerns, which would improve the accuracy of the emissions calculated 
and therefore the quality of data collected, consistent with section 
II.B of this preamble.
    First, a stakeholder indicated that some member companies have been 
interpreting the existing provisions of 40 CFR 98.233(z)(1)(ii) that 
require emissions to be reported according to 40 CFR 98.236(z) and not 
subpart C to mean that reporters with combustion sources at onshore 
petroleum and natural gas production facilities, at onshore petroleum 
and natural gas gathering and boosting facilities, and at natural gas 
distribution facilities must use the calculation methodologies in 
subpart W for all fuel types rather than subpart C (even given the 
provisions in 40 CFR 98.233(z)(1) that reference subpart C for certain 
fuels).\118\ The existing provisions of 40 CFR 98.233(z)(1)(ii) are 
intended to refer only to the reporting requirements and are not 
intended to define which calculation methodologies can be used. In the 
existing rule, the provisions in the 40 CFR 98.233(z)(1) introductory 
text define which calculation methodologies can be used, and 40 CFR 
98.233(z)(1)(ii) simply indicates that all reporters with combustion 
sources at onshore petroleum and natural gas production facilities, at 
onshore petroleum and natural gas gathering and boosting facilities, 
and at natural gas distribution facilities must report those emissions 
in the e-GGRT system under subpart W rather than under subpart C. As 
part of the amendments described in this section, consistent with 
section II.D of this preamble, 40 CFR 98.233(z)(1)(ii) is proposed to 
be moved to 40 CFR 98.233(z)(5), and we are proposing wording changes 
to highlight that this paragraph refers only to the requirement to 
report combustion emissions under subpart W and does not preclude 
reporters from using subpart C methods to calculate emissions if they 
qualify to do so under proposed 40 CFR 98.233(z)(1) (and proposed 40 
CFR 98.233(z)(2), as described later in this section. We are also 
proposing to add a reference to this new proposed paragraph 40 CFR 
98.233(z)(5) in both proposed 40 CFR 98.233(z)(1)(ii) and proposed 
98.233(z)(2)(ii).
---------------------------------------------------------------------------

    \118\ Letter from GPA Midstream Association to Mark de 
Figueiredo, U.S. EPA, providing information in response to EPA 
questions during the meeting on March 23, 2016. May 18, 2016. 
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

    Second, a stakeholder has asked for EPA guidance regarding whether 
field gas that is of pipeline quality meets the criteria to use the 
subpart C methodologies under the existing 40 CFR 98.233(z)(1),\119\ 
and the stakeholder noted that ``field gas'' is not defined within 
existing subpart W or subpart A (General Provisions). The terms ``field 
gas'' and ``field quality'' are frequently used interchangeably by the 
industry, but the EPA also recognizes that some streams in the Onshore 
Petroleum and Natural Gas Gathering and Boosting industry segment that 
industry would generally call ``field gas'' can be natural gas (as 
defined in 40 CFR 98.238) of pipeline quality with a minimum HHV of 950 
Btu/scf. After consideration of these concerns, the EPA is proposing to 
revise 40 CFR 98.233(z)(1) to remove the references to field gas and 
process vent gas and include only the characteristics for the fuels 
that can use subpart C methodologies. The EPA's intent is to indicate 
that a stream colloquially referred to as ``field gas'' that otherwise 
meets the three criteria to use the subpart C methodologies for 
combustion emissions (i.e., (1) meets the definition of ``natural gas'' 
in 40 CFR 98.238; (2) is of pipeline quality specification; and (3) has 
a minimum HHV of 950 Btu/scf) may use subpart C methodologies. The EPA 
is also proposing conforming edits to existing 40 CFR 98.233(z)(2) 
(proposed 40 CFR 98.233(z)(3) in this proposed rule) for consistency.
---------------------------------------------------------------------------

    \119\ Letter from GPA Midstream Association to Mark de 
Figueiredo, U.S. EPA, providing information in response to EPA 
questions during the meeting on March 23, 2016. May 18, 2016. 
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

    Third, certain reporters have indicated in questions submitted to 
the GHGRP Help Desk that the term ``pipeline quality'' is used in 
existing 40 CFR 98.233(z)(1) but it is not defined in subpart W. In 
addition, a stakeholder has opined that the emissions calculated using 
subpart C and subpart W calculation methodologies are similar for many 
fuel streams that are not natural gas of pipeline quality specification 
with a minimum HHV of 950 Btu/scf. Therefore, the stakeholder suggested 
that the EPA should allow subpart C calculation methodologies to be 
used for a wider variety of fuels (if not all fuels in the segments 
that report combustion emissions under subpart W).\120\
---------------------------------------------------------------------------

    \120\ See Letter from GPA Midstream Association to Mark de 
Figueiredo, U.S. EPA, providing information in response to EPA 
questions during the meeting on March 23, 2016. May 18, 2016. See 
also 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. 
Both letters are available in the docket for this rulemaking, Docket 
Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    We have reviewed this stakeholder's analysis and conducted our own 
analysis of additional hypothetical fuel compositions. In general, we 
observed that the agreement of emissions as calculated using subpart C 
calculation methodologies for natural gas and using subpart W 
calculation methodologies varies based on the composition, with the 
largest differences resulting for fuel streams with high CO2 
content. We also observed that for these fuels, emissions calculated 
using subpart W calculation methodologies generally showed better 
agreement with emissions calculated using the subpart C calculation 
methodology for natural gas when using a site-specific HHV (Tier 2) 
than with emissions calculated using the subpart C calculation 
methodology that uses a default HHV (Tier 1). For more information on 
our fuel composition analysis and the comparison of emissions using 
various composition thresholds, see the subpart W TSD, available in the 
docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-2023-0234).
    Based on our analysis, we are proposing to add numeric composition 
thresholds for natural gas to a new proposed paragraph in 40 CFR 
98.233(z)(2) that define the fuels for which an owner or operator may 
use subpart C methodologies. In particular, we are proposing that 
subpart C methodologies Tier 2 or higher may be used for fuel meeting 
the definition of ``natural gas'' in 40 CFR 98.238 if it has a minimum 
HHV of 950 Btu/scf, a maximum CO2 content of 1 percent by 
volume, and a minimum CH4 content of 85 percent by volume. We are not 
proposing to amend the existing provisions in 40 CFR 98.233(z)(1) that 
allow the use of any subpart C calculation methodology for natural gas 
of pipeline quality specification with a minimum HHV of 950 Btu/scf 
(other than the proposed clarifications noted earlier in this section). 
We are also proposing to move the existing provisions for fuels that do 
not meet the specifications to use subpart C methodologies from 40 CFR 
98.233(z)(2) to a new proposed paragraph 40 CFR 98.233(z)(3). This 
proposed amendment would allow reporters to use subpart C methodologies 
for a wider variety of fuel streams while still ensuring data quality. 
We request comment on the natural gas specifications included in 
proposed 40 CFR 98.233(z)(2), including the values proposed for the 
maximum

[[Page 50356]]

CO2 content and minimum CH4 content, as well as 
whether additional specification criteria should be included (e.g., a 
maximum HHV).
2. Methane Slip from Internal Combustion Equipment
    The authors of several recent studies have examined combustion 
emissions at Onshore Petroleum and Natural Gas Gathering and Boosting 
facilities and have demonstrated that a significant portion of 
emissions can result from unburned CH4 entrained in the 
exhaust of natural gas compressor engines (also referred to as 
``combustion slip'' or ``methane slip''). These studies contend that 
emissions from natural gas compressor engines included in the GHGRP are 
significantly underestimated because they do not account for combustion 
slip.\121\ The EPA performed a review of each of these studies and the 
U.S. GHG Inventory to determine whether and how combustion slip 
emissions have been incorporated into published data and how the 
incorporation of combustion slip would affect the emissions from the 
petroleum and natural gas system sector reported to the GHGRP (see the 
subpart W TSD, available in the docket for this rulemaking, Docket Id. 
No. EPA-HQ-OAR-2023-0234).
---------------------------------------------------------------------------

    \121\ Zimmerle et al., Characterization of Methane Emissions 
from Gathering Compressor Stations: Final Report (October 2019 
Revision) and Vaughn et al., ``Methane Exhaust Measurements at 
Gathering Compressor Stations in the United States,'' Environmental 
Science & Technology. 2021, 55 (2), 1190-1196, both available in the 
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    In the 2022 Proposed Rule, we proposed methods to quantify and 
report combustion slip in subpart C and subpart W from compressor 
drivers for all subpart W industry segments that currently report 
combustion emissions in subpart C or subpart W. The emission estimation 
methods provided in the 2022 Proposed Rule were the use of default 
emission factors or default combustion efficiencies for compressor 
drivers based on recent study data. We received comments on the 2022 
Proposed Rule requesting methods to quantify combustion slip using 
original equipment manufacturer (OEM) data and direct measurement. We 
also received comments that while compressor drivers likely represent 
the largest number of reciprocating engines in service at petroleum and 
natural gas facilities, there are reciprocating engines that do not 
drive compressors and other engine types (e.g., GT) that emit 
CH4 from combustion slip. We have performed additional 
review of the combustion slip emission source type as detailed below. 
In this rulemaking, we are continuing to propose the quantification and 
reporting of combustion slip from subpart W facilities that currently 
report combustion emissions in subpart C or subpart W. However, in 
consideration of the comments received on the 2022 Proposed Rule and 
the directives under CAA 136(h), we are broadening the applicability of 
the combustion slip quantification and reporting methods to all RICE 
and GT and additionally providing three methods for quantifying slip 
including default emission factors or combustion efficiencies, OEM 
data, or direct measurement. We are also proposing some revisions to 
the 2022 Proposed Rule for the reporting of combustion emissions for 
RICE and GT for subpart W facilities that report their combustion 
emissions to subpart C after performing a more detailed review of the 
subpart C e-GGRT combined unit reporting configurations.
    Based on the EPA's review and analysis, there appears to be 
combustion slip for RICE and GT, which are used primarily to drive 
compressors, at oil and gas facilities. In addition, while the recent 
studies are focused on the Onshore Petroleum and Natural Gas Gathering 
and Boosting industry segment, the EPA's literature review found the 
presence of combustion slip in different industry segments, so it 
appears that combustion slip is dependent on the type of internal 
combustion equipment and not the application (i.e., we expect 
combustion slip from RICE or GT regardless of the industry segment). We 
also considered that other EPA programs such as AP-42: Compilation of 
Air Pollutant Emissions Factors; 40 CFR part 60, subpart JJJJ; and 40 
CFR part 63, subpart ZZZZ consider emissions from internal combustion 
equipment (i.e., RICE or GT) irrespective of their use to drive a 
compressor or the industry segment in which the engine operates.
    Therefore, consistent with section II.A of this preamble, we are 
proposing to revise the methodologies for determining combustion 
emissions from RICE and GT, including those that drive compressors, to 
account for combustion slip. For the three subpart W industry segments 
reporting combustion emissions to subpart W (Onshore Petroleum and 
Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and 
Boosting, and Natural Gas Distribution), we are proposing that RICE and 
GT combusting natural gas that qualify to determine emissions using the 
subpart C calculation methodologies per 40 CFR 98.233(z)(1) and 
proposed new 98.233(z)(2),\122\ would have three options in proposed 40 
CFR 98.233(z)(4) to quantify emissions from combustion slip, including 
direct measurement using a performance test, the use of OEM data, or 
the use of default emission factors. For facilities that conduct a 
performance test to calculate combustion slip, we are proposing in 40 
CFR 98.233(z)(4)(i) that the performance test would be required one 
time, in accordance with one of the test methods in proposed 40 CFR 
98.234(i), which include EPA Methods 18 and 320 as well as an alternate 
method, ASTM D6348-12. If a facility is required to or elects to 
conduct a performance test for any reason, we are proposing that they 
must use the results of the test for estimating emissions. The results 
of the performance test would be used to develop an emission factor for 
use in the emissions calculations for CH4. For facilities 
electing to use OEM data, which may include manufacturer specification 
sheets, emissions certification data, or other manufacturer data 
providing expected emission rates from the RICE or GT, we are proposing 
that the reporter would use the OEM data to develop an emission factor 
for use in their emissions calculations for CH4. Concerning 
OEM data, we are seeking comment on whether OEM data is expected to be 
representative of field conditions. Further, we are considering 
proposing requirements for the OEM supplied data including defining a 
standardized testing program for engine families similar to those that 
underly the emissions certification process for the engine NSPS in 40 
CFR part 60 subparts IIII and JJJJ (e.g., Parts 1054 and 1065). These 
programs define the number of engines in a family that are required to 
be tested as a number (e.g., 30) or a percentage of engines produced in 
a year. The programs also define the methods for testing the engines 
(including engine load, test duration, etc.) as well as deterioration 
factors for adjusting for the degradation of performance that is 
expected over time. Alternatively, we are considering that 
manufacturers perform the same type of testing incorporated in proposed 
40 CFR 98.234(i) for a certain number of engines in an engine family. 
We are seeking comments on these considerations including how the 
manufacturer testing program should be structured and more 
specifically: how many engines should be tested in an engine family; 
under

[[Page 50357]]

what load(s) should the engines be tested; what testing methods should 
be used; what is the appropriate duration of the test; and whether a 
deterioration factor be included to account for degradation of 
performance over time. We are also considering whether to add reporting 
requirements for the results of performance tests conducted by 
manufacturers. Finally, for facilities electing to the use the default 
emission factors, which were developed using data from Zimmerle et al. 
(2019), we are proposing that the reporter would be required to select 
the appropriate emission factor by equipment type (e.g., 2-stroke lean-
burn, 4-stroke lean-burn, 4-stroke rich-burn, or GT) in proposed new 
Table W-7 rather than the emission factors in Table C-2 for use in 
their emissions calculations for CH4. 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.
---------------------------------------------------------------------------

    \122\ See section III.S.1 of this preamble for information on 
the proposed amendments to 40 CFR 98.233(z) to increase the 
flexibility for reporters to use the subpart C calculation 
methodologies.
---------------------------------------------------------------------------

    For the three subpart W industry segments reporting combustion 
emissions to subpart W (Onshore Petroleum and Natural Gas Production, 
Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural 
Gas Distribution), we are proposing a default equipment specific 
combustion efficiency (proposed to be provided in equations W-39A and 
W-39B) for RICE and GT that must be used to determine emissions using 
the subpart W calculation methodologies per existing 40 CFR 
98.233(z)(2) (proposed 40 CFR 98.233(z)(3)). The default combustion 
efficiency would account for methane slip, and be combined with fuel 
composition to calculate emissions. We are not proposing to provide 
options for reporters to conduct performance tests or use OEM data for 
such RICE and GT. The fuel types covered by the methods in existing 40 
CFR 98.233(z)(2) (proposed 40 CFR 98.233(z)(3)) are expected to be 
highly variable in composition over the course of the year, such that a 
one-time performance test or OEM data are not expected to be 
representative of the annual emissions.
    We expect that the records necessary to confirm the value for the 
development of an emission factor based on the results of a performance 
test or OEM data are already required to be maintained by the facility 
per 40 CFR 98.237; thus, no new recordkeeping provisions relative to 
the combustion slip amendments are being proposed. We are proposing to 
add new reporting requirements to 40 CFR 98.236(z)(2) specifically for 
internal combustion engines that combust natural gas that meets the 
criteria of proposed 40 CFR 98.233(z)(1) or (2) to specify the 
equipment type of reported internal combustion units, the method used 
to estimate the CH4 emission factor, and the value of the 
emission factor to facilitate verification of the reported emissions. 
Under the existing reporting structure, facilities can group internal 
combustion engines by the unit type and the fuel type. The proposed 
amendments would require further disaggregation of the reporting of 
natural gas-fired internal combustion engine and GT CH4 
emissions as units grouped for reporting must share the same equipment 
type (e.g., 4-stroke rich burn), fuel type, and method for determining 
the CH4 emission factor, which will allow the EPA to 
adequately verify the data.
    For the subpart W industry segments that estimate and report their 
combustion emissions to subpart C, we are proposing amendments in 
subpart C analogous to the proposed amendments described in this 
section for the three industry segments that estimate and report their 
combustion emissions to subpart W (i.e., Onshore Petroleum and Natural 
Gas Production, Onshore Petroleum and Natural Gas Gathering and 
Boosting, and Natural Gas Distribution). Specifically, the facilities 
that report their combustion emissions to subpart C and currently use 
either equation C-8, C-8a, C-8b, C-9, C-9a, or C-10 in 40 CFR 98.33(c), 
as it corresponds to the Tier methodology selected to estimate their 
CO2 emissions, to estimate CH4 emissions. These 
equations rely on the use of a default CH4 emission factor 
from Table C-2 to estimate emissions. We are proposing to require that 
natural gas-fired RICE or GT located at these facilities would be 
required to use one of the options in proposed 40 CFR 98.233(z)(4) to 
estimate CH4 emissions. Specifically, we are proposing to 
revise the ``EF'' term in each of the equations in 40 CFR 98.33(c) 
(i.e., equations C-8, C-8a, C-8b, C-9a, C-9b, and C-10) to reference 
the options for developing a CH4 emission factor in proposed 
40 CFR 98.233(z)(4) for natural gas-fired RICE or GT. We are also 
proposing to add a footnote to Table C-2 that specifies that for 
reporters subject to subpart W, the default CH4 emission 
factor in Table C-2 for natural gas may only be used for natural gas-
fired combustion units that are not RICE or GT. Finally, we are 
proposing to amend 40 CFR 98.36(b), (c)(1), and (c)(3) specifically for 
RICE or GT at facilities that are subject to subpart W. These 
provisions currently provide the requirements for reporting by emission 
unit, by aggregation of units or by common pipe configurations. Under 
the proposed amendments, we are requiring reporters which report 
emissions in accordance with 40 CFR 98.36(b), (c)(1), or (c)(3) to 
provide the equipment type (e.g., two stroke lean burn RICE), the 
method used to determine the CH4 emission factor and the 
average value of the CH4 emission factor. This proposed 
change would ensure that sufficient data in the overall aggregation of 
units or common pipe (i.e., multiple units combusting natural gas) is 
reported such that we can perform review of the supplied emission 
factor data and perform verification on the corresponding emissions. 
Overall, these proposed amendments to the subpart C reporting 
requirements are analogous to and consistent with what is being 
required for RICE or GT for facilities that report combustion emissions 
to subpart W.
3. Higher Heating Value for Calculating N2O
    As noted previously, there are subpart W specific methods for 
quantifying combustion equipment emissions for facilities that report 
their combustion emissions to subpart W in existing 40 CFR 98.233(z)(2) 
(proposed (z)(3) in this proposed rule). For quantifying emissions from 
N2O specifically, the existing rule specifies the use of 
equation W-40. This equation requires the fuel throughput, the HHV of 
the fuel, and the use of a default emission factor. For field gas or 
process vent gas, the variable definition for the HHV provides that 
either a site-specific or default value may be used. We are proposing, 
consistent with section II.B of this preamble, to amend the definition 
of the variable for the HHV to require the use of a site-specific value 
because we believe the site-specific value more accurately accounts for 
the more variable fuel compositions that exist in field or process gas. 
Our assessment is that the methods for calculating CO2 and 
CH4 in 40 CFR 98.233(z)(2)(ii) (proposed (z)(3)(ii) in this 
proposed rule) already require the use of site-specific values for the 
hydrocarbon streams going to the combustion unit; therefore, we expect 
that a site-specific HHV is known (or can be calculated using the 
compositional data) without incurring additional burden, while 
increasing the accuracy of the emissions estimate.
4. Other Calculation Methodology Clarifications Applicability
    To determine the concentrations of hydrocarbon constituents in the 
flow of gas to the combustion unit, existing 40

[[Page 50358]]

CFR 98.233(z)(2)(ii) specifies that reporters must either use a 
continuous gas composition analyzer (if one is present) or the 
procedures specified in 40 CFR 98.233(u)(2). For onshore petroleum and 
natural gas gathering and boosting facilities, 40 CFR 98.233(u)(2) 
specifies use of the annual average gas composition based on the most 
recent available analysis of the gas received at the facility. However, 
one stakeholder has indicated that for fuels using the existing 
provisions of 40 CFR 98.233(z)(2) to calculate emissions, the 
requirements for determining the gas composition could result in 
inaccurate calculations of emissions for some facilities because 
onshore petroleum and natural gas gathering and boosting facilities do 
not necessarily use the gas received at their facility for 
combustion.\123\ For example, if the gas received at the facility is 
not suitable for combustion, they may mix the gas with purchased 
natural gas. In that case, the annual average composition of gas 
received at the facility would not be representative of the gas sent to 
the combustion unit (as required by existing 40 CFR 98.233(z)(2)), 
which could result in inaccurate emissions. Therefore, the EPA is 
proposing to revise the language in 40 CFR 98.233(z)(2)(ii) (proposed 
40 CFR 98.233(z)(3)(ii)(B) in this proposed rule) to allow the use of 
engineering estimates based on best available data to determine the 
concentration of gas hydrocarbon constituent in the flow of gas to the 
unit. This proposed amendment would allow reporters to use the best 
information available to determine the gas composition while 
maintaining the option for reporters to use 40 CFR 98.233(u)(2) if they 
do not have other stream-specific information. This proposed amendment 
is expected to improve the accuracy of the emissions calculated and 
therefore the quality of data collected, consistent with section II.B 
of this preamble.
---------------------------------------------------------------------------

    \123\ See Letter from GPA Midstream Association to Mark de 
Figueiredo, U.S. EPA, providing information in response to EPA 
questions during the meeting on March 23, 2016. May 18, 2016. See 
also 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. 
Both letters are available in the docket for this rulemaking, Docket 
Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    We are also proposing amendments to clarify that emissions may be 
calculated for groups of combustion units. The existing provisions of 
40 CFR 98.233(z)(2) (proposed 40 CFR 98.233(z)(3)(ii)) could be 
interpreted to specify that emissions must be calculated for each 
individual combustion unit. However, because combustion emissions and 
activity data are reported as combined totals for each type of 
combustion device, fuel type, and method for determining the 
CH4 emission factor (for RICE and GT), it is generally not 
necessary to calculate emissions for each individual unit before 
aggregating the total emissions. For example, if the volume of fuel 
combusted is determined at a single location upstream of several 
combustion units, emissions may be determined for that combined volume 
of fuel (i.e., for that group of combustion units). In other words, it 
would not be necessary in this example case to apportion a volume of 
fuel to each unit, calculate emissions separately, and then combine 
them again. If the combustion units downstream of this shared 
measurement point are a mix of combustion device types, the emissions 
and the volume of fuel would still need to be apportioned between those 
combustion device types for reporting purposes; however, reporters may 
elect to perform that apportioning either before or after emissions are 
calculated, as appropriate, as long as the group of combustion units 
does not include any natural gas internal combustion equipment 
including RICE or GT. If any of the combustion units downstream of this 
shared measurement point are natural gas-driven internal combustion 
equipment including RICE or GT, the volumes of fuel for those units 
would have to be separated from the total before emissions are 
calculated to account for the differences in combustion efficiency, as 
described in section III.S.2 of this preamble. Some of the tiers in 
subpart C similarly allow for calculation of emissions by groups of 
units combusting the same fuel, so we are proposing to include 
analogous language to that in subpart C in 40 CFR 98.233(z)(1)(ii) and 
40 CFR 98.233(z)(2)(ii) to provide for these clarifications in how to 
calculate.
5. Location of Reporting Requirements for Combustion Equipment
    Section 136(h) of the CAA specifies the following concerning 
reporting: ``Not later than 2 years after the date of enactment of this 
section, the Administrator shall revise the requirements of subpart W 
of part 98 of title 40, Code of Federal Regulations, to ensure the 
reporting under such subpart, and calculation of charges under 
subsections (e) and (f) of this section, are based on empirical data, 
including data collected pursuant to subsection (a)(4), accurately 
reflect the total CH4 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 under subsection (c) is owed.'' As noted in this excerpt, the 
IRA directs the Administrator to ensure reporting under subpart W 
accurately reflects total CH4 emissions from applicable 
facilities.
    Apart from onshore natural gas transmission pipeline facilities, 
all facilities subject to subpart W must include combustion emissions 
in their annual report. As noted in section III.S.1 of this preamble, 
facilities in the Onshore Petroleum and Natural Gas Production, Onshore 
Petroleum and Natural Gas Gathering and Boosting, and Natural Gas 
Distribution industry segments must calculate combustion emissions in 
accordance with 40 CFR 98.233(z) and report emissions under subpart W. 
Facilities in the remaining industry segments (i.e., Offshore Petroleum 
and Natural Gas Production, Onshore Natural Gas Processing, Onshore 
Natural Gas Transmission Compression, Underground Natural Gas Storage, 
LNG Storage, and LNG Import and Export Equipment) are required to 
calculate combustion emissions in accordance with the provisions of 40 
CFR 98.33 and report emissions under subpart C.
    The EPA is seeking comment on amending subpart W to specify that 
all industry segments would be required to report their combustion 
emissions, including CH4, under subpart W to more accurately 
reflect the total CH4 emissions from such facilities within 
the emissions reported under subpart W. Using RY2021 data for 
combustion sources, we determined that requiring combustion emissions 
from all oil and gas operations to be reported to subpart W rather than 
subpart C would increase total subpart W CH4 emissions by 
less than 1 percent. If the amendments to combustion slip discussed in 
section III.S.2 of this preamble are finalized, the reported 
CH4 emissions from combustion are expected to increase, but 
we estimate the increase in total CH4 emissions from 
combustion devices at facilities subject to subpart W would be less 
than 5 percent. Under this approach, we would consider continuing to 
allow all the industry segments that currently report combustion 
emissions under subpart C (i.e., Offshore Petroleum and Natural Gas 
Production, Onshore Natural Gas Processing, Onshore Natural Gas 
Transmission Compression, Underground Natural Gas Storage, LNG Storage, 
and LNG Import and Export Equipment) to use the same subpart C 
calculation methodologies as they

[[Page 50359]]

currently use in order to minimize the burden on affected facilities. 
This amendment, however, would result in changes to their reporting 
structure, as subpart W does not currently contain the same methods to 
report via a common pipe for fuel streams or by aggregation of units as 
provided in subpart C. Instead, for subpart W, combustion emissions are 
aggregated by fuel type, combustion equipment type, and if finalized, 
by the method used for estimating combustion slip, when applicable. 
There are also exclusions for reporting combustion emissions in 40 CFR 
98.233(z)(5) and (6), specifically for external combustion equipment 
with a rated heat capacity of less than 5 million British thermal units 
per hour (MMBtu/hr) and internal combustion equipment with a rated heat 
capacity of less than 1 MMBtu/hr. Under this approach, we expect that 
these exemptions would apply to the facilities newly subject to subpart 
W. Similarly, under this approach, we expect that the exemptions in 
subpart C would no longer apply to these facilities. The exemptions 
that we expect may impact facilities under this approach are the 
subpart C exclusions of reporting emissions from portable and emergency 
equipment in 40 CFR 98.30(a) and (b).

T. Leak Detection and Measurement Methods

1. Acoustic Leak Detection
    For emission source types for which measurements are required, 
subpart W specifies the methods that may be used to make those 
measurements in 40 CFR 98.234(a). To improve the quality of the data 
when an acoustic leak detection device is used, consistent with section 
II.B of this preamble, we are proposing two revisions to the acoustic 
measurement requirements in 40 CFR 98.234(a)(5). First, for stethoscope 
type acoustic leak detection devices (i.e., those designed to detect 
through-valve leakage when put in contact with the valve body and that 
provide an audible leak signal but do not calculate a leak rate), we 
are proposing that a leak is detected if an audible leak signal is 
observed or registered by the device. Second, we are proposing that if 
a leak is detected using a stethoscope type device, then that leak must 
be measured using one of the quantification methods specified in 40 CFR 
98.234(b) through (d) and that leak measurement must be reported 
regardless of the volumetric flow rate measured. These proposed 
revisions would improve the accuracy of emissions reported for 
compressors and transmission tanks when an acoustic leak detection 
device is used.
2. High Volume Samplers
    We are proposing two revisions to the high volume sampler methods 
to improve the quality of the data when high volume samplers are used 
for flow measurements, consistent with section II.B of this preamble. 
First, we are proposing to add detail to 40 CFR 98.234(d)(3) to clarify 
the calculation methods associated with high volume sampler 
measurements. Generally, high volume samplers measure CH4 
flow, not whole gas flow. However, the current calculation methods in 
40 CFR 98.234(d)(3) treat the measurement as a whole gas measurement. 
Therefore, we are proposing to clarify the calculation methods needed 
if the high volume sampler outputs CH4 flow in either a mass 
flow or volumetric flow basis. Specifically, we are proposing methods 
to determine natural gas (whole gas) flows based on measured 
CH4 flows.
    Second, we are proposing to add a paragraph at 40 CFR 98.234(d)(5) 
to clarify how to assess the capacity limits of a high volume sampler. 
Currently, 40 CFR 98.234(d) simply states to ``Use a high volume 
sampler to measure emissions within the capacity of the instrument''; 
there is no other information provided to clarify what ``within the 
capacity of the instrument'' means or how it is determined. We 
understand that there are different manufacturers, but most common high 
volume samplers report maximum sampling rates of 10 to 11 cubic feet 
per minute (cfm) and maximum CH4 flow quantitation limits of 
6 to 8 cfm. Based on our review of reported high volume sampler 
measurements, we found that 2 to 5 percent of high volume sampler 
measurements for all types of compressor sources (for both centrifugal 
and reciprocating compressors) are likely at or beyond the expected 
capacity limits of the high volume sampler instrument. Considering 
actual sampling rates, gas collection efficiencies near the sampling 
rates, and reported CH4 quantitation limits relative to 
maximum sampling rates, we determined that whole gas flow rates 
exceeding 70 percent of the device's maximum rated sampling rate is an 
indication that the device will not accurately quantify the volumetric 
emissions, which we deem to exceed the capacity of the device. 
Therefore, we are proposing to specify that CH4 flows above 
the manufacturer's CH4 flow quantitation limit or total 
volumetric flows exceeding 70 percent of the manufacturer's maximum 
sampling rate indicate that the flow is beyond the capacity of the 
instrument and that flow meters or calibrated bags must be used to 
quantify the flow rate. For more information on our review, see the 
subpart W TSD, available in the docket for this rulemaking (Docket Id. 
No. EPA-HQ-OAR-2023-0234).

U. Industry Segment-Specific Throughput Quantity Reporting

1. Throughput Information for the Future Implementation of the Waste 
Emissions Charge
    As noted in section I.E of this preamble, the waste emissions 
charge specifies segment-specific thresholds (Waste Emissions 
Threshold) for segments subject to the waste emissions charge. For the 
Onshore Petroleum and Natural Gas Production and Offshore Petroleum and 
Natural Gas Production industry segments, the Waste Emissions Threshold 
is specified in CAA section 136(f)(1) as, ``(A) 0.20 percent of the 
natural gas sent to sale from such facility;'' or ``(B) 10 metric tons 
of methane per million barrels of oil sent to sale from such facility, 
if such facility sent no natural gas to sale.'' For the Onshore 
Petroleum And Natural Gas Gathering And Boosting, Onshore Natural Gas 
Processing, Onshore Natural Gas Transmission Compression, LNG Storage, 
LNG Import and Export Equipment, and Onshore Natural Gas Transmission 
Pipeline industry segments, the Waste Emissions Threshold is defined in 
CAA section 136(f)(2) and (3) as a percentage of ``natural gas sent to 
sale from or through such facility,'' with the percentages specified 
varying by segment.
    To align the subpart W reporting elements with text used in CAA 
section 136 and enable verification of throughput-related reporting 
elements, consistent with section II.C of this preamble, we are 
proposing a combination of new reporting elements and amendments to 
existing segment-specific throughput reporting requirements in 40 CFR 
98.236(aa).
    We are proposing to add the word ``natural'' in front of ``gas'' at 
each occurrence where it is used in the throughput reporting elements 
in subpart W that are being revised to align with CAA section 136. We 
note that the CAA section 136 text uses the term ``oil'' and we are 
clarifying in this preamble that for the purposes of subpart W the term 
``oil'' has the same meaning as ``crude oil,'' which is used in the 
throughput reporting elements in subpart W and defined in subpart A of 
part 98.
    We are also generally proposing revisions to ensure that the 
verbiage of ``sent to sales'' or ``through the facility'' is reflected 
in the reporting elements, as

[[Page 50360]]

applicable. We are also proposing in 40 CFR 98.236(aa) that the 
quantities sent to sales or through the facility be measured, as it is 
reasonable to expect that the quantities of these products are closely 
tracked. We request comment on situations in which a reporter may not 
be measuring the quantity ``sent to sales'' or ``through the 
facility.''
    Aside from these overarching proposed amendments, there are 
industry segment-specific proposed amendments for the Onshore Petroleum 
and Natural Gas Production, Offshore Petroleum and Natural Gas 
Production, Onshore Petroleum and Natural Gas Gathering and Boosting, 
and Onshore Natural Gas Processing industry segments as described in 
the remainder of this section.
a. Onshore Petroleum and Natural Gas Production and Offshore Petroleum 
and Natural Gas Production
    For the Onshore Petroleum and Natural Gas Production and Offshore 
Petroleum and Natural Gas Production industry segments, the current 
requirements for reporting throughputs of crude oil are combined with 
volumes of condensate. These volumes will need to be reported 
separately in order to align with the CAA section 136(f) oil threshold 
for production facilities, when applicable. Therefore, we are proposing 
the separation of these reporting elements into two distinct reporting 
elements in both 40 CFR 98.236(aa)(1)(i) and 98.236(aa)(2).
    For consistency with CAA section 136, we are proposing to use the 
phrase ``sent to sale'' in 40 CFR 98.236(aa)(1)(i)(B) through (D), 40 
CFR 98.236(aa)(1)(iii)(C) through (E), and 40 CFR 98.236(aa)(2)(i) 
through (vi) instead of ``for sale,'' the phrase used in the existing 
data elements. This proposed amendment is for consistency in language 
rather than any expected difference in the volumes to be reported or 
the interpretation of the terms, as the existing term was intended to 
have the same meaning. As described in section III.D of this preamble, 
we are also proposing additional throughput data elements to provide 
separate, well-level reporting of throughputs associated with wells in 
the Onshore Petroleum and Natural Gas Production and Offshore Petroleum 
and Natural Gas Production industry segments that are permanently shut-
in and plugged. These proposed data elements, if finalized, are 
anticipated to be useful in the future evaluation of the associated 
exemptions in CAA section 136(f)(7).
    Specifically for the Offshore Petroleum and Natural Gas Production 
industry segment, the existing throughput requirements are for ``gas 
handled'' at the platform, which includes production volumes as well as 
volumes transferred via pipeline from another location. We note that 
the term ``gas handled'' is not used by other reporting programs to 
which offshore production facilities also report, such as the BOEM or 
the U.S. Energy Information Administration (EIA). We have also recently 
received a question through the GHGRP Help Desk asking about 
differences in throughput between the published BOEM data for the 
parameter, lease production reporting, and throughput volumes published 
in the subpart W data, so there are potentially differences in the ways 
reporters are interpretating and reporting the ``gas handled'' data 
element as compared to production volumes reported to other programs. 
In order to provide consistency with the language in CAA section 136 
across both production industry segments and help the EPA implement CAA 
section 136, we are proposing to revise the reporting elements in 40 
CFR 98.236(aa)(2) for the Offshore Petroleum and Natural Gas Production 
industry segment so they are analogous to those in Onshore Petroleum 
and Natural Gas Production. We are seeking comment on whether we should 
add the proposed throughputs as new data elements and continue to 
retain the existing reporting elements in 40 CFR 98.236(aa)(2)(i) and 
(ii), including the rationale for maintaining the existing reporting 
elements.
b. Onshore Petroleum and Natural Gas Gathering and Boosting
    Through our verification efforts, it has become apparent that the 
reporting of some of the throughput volumes for the Onshore Petroleum 
and Natural Gas Gathering and Boosting industry segment are incomplete 
in the sense that they do not include all the quantities of natural gas 
(and hydrocarbon liquids) transported from the facility (i.e., leaving 
the facility). In some cases, this appears to be due to the specific 
wording of the reporting elements in existing 40 CFR 98.236(aa)(10)(ii) 
and (iv) that appear to limit the quantities to the quantities 
transported to four specific downstream endpoints (e.g., processing 
plants). However, the EPA indicated in the preamble to the final rule 
that added the Onshore Petroleum and Natural Gas Gathering and Boosting 
industry segment that the throughputs transported from the facility 
were intended to be the total quantities transported downstream (80 FR 
64280, October 22, 2015). Therefore, be consistent with the EPA's 
original intent for these data elements, we are proposing to amend 40 
CFR 98.236(aa)(10)(ii) and (iv) to clarify that the downstream 
endpoints listed in the current reporting elements are examples of 
potential destinations and to specify that the reported quantities 
should be the natural gas or hydrocarbon liquids, respectively, 
transported to downstream operations such as one of those endpoints. We 
are also proposing to add storage facilities to the list of downstream 
operations to make the list of examples more comprehensive. Finally, 
for consistency with the text in CAA section 136 and to help the EPA 
implement CAA section 136 in the future, we are proposing to amend 40 
CFR 98.236(aa)(10)(ii) to specify that the natural gas is transported 
``through the facility'' and then to a downstream operation. As a 
result of these proposed amendments, the reported quantities should 
include all natural gas and hydrocarbon liquids transported downstream 
from the facility (i.e., leaving the basin or leaving the gathering 
system owner or operator).
    In addition to reviewing the reported throughputs, we also reviewed 
the definitions in subpart W associated with the industry segment and 
the facility. For the Onshore Petroleum and Natural Gas Gathering and 
Boosting industry segment, we found that the definitions for 
``Gathering and boosting system'' and ``Gathering and boosting system 
owner or operator'' in 40 CFR 98.238 specified that an onshore 
petroleum and natural gas gathering and boosting system or owner or 
operator must receive natural gas or petroleum from an onshore 
petroleum and natural gas production facility. Those definitions would 
exclude facilities that receive natural gas or petroleum from other 
onshore petroleum and natural gas gathering and boosting facilities and 
do not receive any natural gas or petroleum from onshore petroleum and 
natural gas production facilities. Therefore, there are potentially 
entire onshore petroleum and natural gas gathering and boosting 
facilities or volumes of gas through onshore petroleum and natural gas 
gathering and boosting facilities that are unaccounted for under the 
existing rule. We are proposing to amend the definition of ``Gathering 
and boosting system'' and ``Gathering and boosting owner or operator'' 
in 40 CFR 98.238 to specify that these systems may receive natural gas 
and/or petroleum from one or more other onshore petroleum and natural 
gas gathering and boosting systems in addition to production 
facilities.

[[Page 50361]]

c. Onshore Natural Gas Processing
    Subpart W currently requires onshore natural gas processing 
facilities to report the quantity of natural gas received at the gas 
processing plant in existing 40 CFR 98.236(aa)(3)(i), however, the rule 
does not currently specify whether the volume is all natural gas that 
enters the facility--including natural gas that passes through the 
facility without being processed further (i.e., ``pass-through 
volumes'')--or just natural gas received for processing. As discussed 
in section III.U.1 of this preamble, to maintain consistency with 
subpart NN and reduce burden for fractionators, the EPA is proposing to 
revise 40 CFR 98.236(aa)(3)(i) to specify that the subpart W quantity 
of gas received is the gas received for processing and is also 
proposing that fractionators do not have to report a quantity under 40 
CFR 98.236(aa)(3)(i) if they report under subpart NN. Subpart NN does 
not require reporting of the gas leaving the facility, but to maintain 
consistency in the interpretation of the throughputs, to date, the EPA 
has provided guidance to facilities that the volume reported in 
accordance with 40 CFR 98.236(aa)(3)(ii) is that which has been 
processed at the facility and should exclude volumes of gas that are of 
pipeline specification and only passed through the facility.
    However, to be consistent with CAA section 136(f)(2), the 
throughput should include all volumes of natural gas which pass through 
the facility or are sent to sales. Therefore, considering the proposed 
amendments to 40 CFR 98.236(aa)(3)(i) and guidance that has been 
historically provided for 40 CFR 98.236(aa)(3)(ii), a new reporting 
element for natural gas processing throughput is needed to fully 
capture all volumes through the facility (i.e., those that are 
processed and those that pass through the facility which are not 
processed). As such, we are proposing to add a new reporting element 
for the Onshore Natural Gas Processing industry segment in 40 CFR 
98.236(aa)(3)(ix) to capture all natural gas that is processed and/or 
passed through the facility consistent with the text in CAA section 136 
(i.e., ``natural gas sent to sale from or through facilities'').
2. Onshore Natural Gas Processing and Natural Gas Distribution 
Throughputs Also Reported Under Subpart NN
    Onshore Natural Gas Processing plants are required to report seven 
facility-level throughput-related items under subpart W, as specified 
in existing 40 CFR 98.236(aa)(3). These seven data reporting elements 
include: quantities of natural gas received and processed gas leaving 
the gas processing plant, cumulative quantities of NGLs received and 
leaving the gas processing plant, the average mole fractions of 
CH4 and CO2 in the natural gas received, and an 
indication of whether the facility fractionates NGLs. Natural Gas 
Distribution companies are also required to report seven throughput 
volumes under subpart W, as specified in existing 40 CFR 98.236(aa)(9). 
These seven data reporting elements include: the quantity of gas 
received at all custody transfer stations; the quantity of natural gas 
withdrawn from in-system storage; the quantity of gas added to in-
system storage; the quantity of gas delivered to end users; the 
quantity of gas transferred to third parties; the quantity of gas 
consumed by the LDC for operational purposes; and the quantity of gas 
stolen.
    The EPA has received stakeholder comments related to some of these 
reporting elements.\124\ These stakeholders have commented that the 
reporting elements included in subpart W are redundant with data 
reported elsewhere within the GHGRP, specifically under subpart NN 
(Suppliers of Natural Gas and Natural Gas Liquids). Subpart NN requires 
NGL fractionators and LDCs to report the quantities of natural gas and 
natural gas liquid products supplied downstream and their associated 
emissions. For example, for natural gas processing plants, commenters 
stated that both subparts require reporting of the volume of natural 
gas received and the volume of NGLs received. Subpart W also requires 
reporting of total NGLs leaving the processing plant, while subpart NN 
requires reporting of the volume of each individual NGL product 
supplied. For LDCs, these commenters have stated that some duplicative 
reporting is required as well. For example, commenters stated that both 
subparts require reporting of the volume of natural gas received, 
volume placed into and out of storage each year, and volume transferred 
to other LDCs or to a pipeline as well as some other duplicative data. 
In addition, commenters stated that the reporting elements included in 
subparts W and NN for LDCs are redundant with data reported to the EIA 
on Form EIA-176, the Annual Report of Natural and Supplemental Gas 
Supply and Disposition.\125\ The commenters explained that subpart W 
and subpart NN collect nearly the same data, and stated that 
discrepancies between the data sets are due to the use of inconsistent 
terminology. Commenters also suggested that due to the redundancy and 
availability of data reported to the EIA for LDCs, the EPA should 
remove the throughput-related reporting requirements for the Natural 
Gas Distribution industry segment from the GHGRP altogether. Commenters 
added that if the requirements are maintained, the EPA should reconcile 
the terminology used within the GHGRP and clarify the reporting 
elements.
---------------------------------------------------------------------------

    \124\ See Docket Id. Nos. EPA-HQ-OA-2017-0190-46726, EPA-HQ-OA-
2017-0190-1958, EPA-HQ-OA-2017-0190-2066 available in Compilation of 
Comments Related to the Greenhouse Gas Reporting Program submitted 
to the Department of Commerce under Docket ID No. DOC-2017-0001 and 
the Environmental Protection Agency under Docket ID No. EPA-HQ-OA-
2017-0190 and in the docket for this rulemaking, Docket Id. No. EPA-
HQ-OAR-2023-0234.
    \125\ Form EIA-176 is available at the U.S. EIA website at 
https://www.eia.gov/survey/form/eia_176/form.pdf; the Form EIA-176 
Instructions are available at https://www.eia.gov/survey/form/eia_176/instructions.pdf.
---------------------------------------------------------------------------

    The EIA report is submitted in the spring of each year and covers 
the previous calendar year. After completing internal audits of the 
reports, EIA publishes the data for each LDC on its website in the 
fall. The EIA data provides detailed information on the volume of gas 
received, gas stored, gas removed from storage, gas deliveries by 
sector, and HHV data. The EPA previously reviewed the possibility of 
obtaining data by accessing existing Federal Government reporting and 
provided the following response in the subpart NN response to public 
comments document accompanying the 2009 Final Rule: \126\
---------------------------------------------------------------------------

    \126\ See page 7 of EPA Response to Public Comment Vol. 39 
Subpart NN at https://www.epa.gov/ghgreporting/ghgrp-2009-final-rule-response-comments-documents, also available in the docket for 
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

     The EPA ``decided not to modify the final rule because 
collecting data directly in a central system will enable the EPA to 
electronically verify all data reported under this rule quickly and 
consistently, to use the information for non-statistical purposes, and 
to handle confidential business information in accordance with the 
Clean Air Act.''
     In the specific case of subpart NN, the EPA also 
``determined that it could not rely on EIA data to collect facility-
level data from fractionators and company-level data from LDCs.''
     Additionally, the EPA ``seeks data that is beyond what EIA 
collects, such as quality assurance information, verification data, and 
information on odorized propane'' and ``data on site-specific HHV and 
carbon content from those sites that choose to sample and

[[Page 50362]]

test products rather than use default emission factors.''
    After further review of the data available through EIA, the 
stakeholder comments described earlier in this section, and the 
reporting requirements in subpart W and subpart NN, the EPA is 
proposing to eliminate duplicative elements from subpart W for 
facilities that report to subpart NN, consistent with section II.C of 
this preamble. The EPA is proposing to amend the reporting requirements 
in 40 CFR 98.236(aa)(3) for Onshore Natural Gas Processing plants that 
both fractionate NGLs (approximately 100 of the 450 subpart W natural 
gas processing plants) and also report as a supplier under subpart NN. 
For this subset of facilities, the EPA reviewed the data from subpart W 
and subpart NN and determined that there are no gas processing plants 
that report as fractionators under subpart W that do not also report 
under subpart NN without supplying a valid explanation.\127\ During 
this review, the EPA found that some of the data elements included in 
subpart W overlap with data elements in subpart NN. Specifically, the 
data elements in 40 CFR 98.236(aa)(3)(i), (iii) and (iv) of subpart W 
overlap with data elements in subpart NN as specified in 40 CFR 
98.406(a)(3), 98.406(a)(1) and (2), 98.406(a)(4)(i) and (ii), 
respectively.\128\
---------------------------------------------------------------------------

    \127\ One such explanation is that the gas processing plant 
fractionates NGLs to supply fuel for use entirely on-site (i.e., the 
fuel is not supplied downstream). Due to definitional differences 
between the two subparts, this facility is defined as a fractionator 
for purposes of subpart W but is not a supplier that must report 
under subpart NN.
    \128\ While it is the EPA's intention that the reported quantity 
of natural gas received at the facility in existing 40 CFR 
98.236(aa)(3)(i) should be the quantity of natural gas received for 
processing, consistent with the requirement to report the annual 
volume of natural gas received for processing in existing 40 CFR 
98.406(a)(3), some reporters have indicated in correspondence with 
the EPA via e-GGRT that they are including gas that is received at 
but not processed by the onshore natural gas processing facility 
(i.e., gas that was processed elsewhere and passes through the 
onshore natural gas processing facility). Therefore, to clarify the 
EPA's intention and reinforce the consistency of the subpart W and 
subpart NN quantities, the EPA is proposing to revise 40 CFR 
98.236(aa)(3)(i) to indicate that that reported quantity should be 
natural gas received at the gas processing plant for processing in 
the calendar year.
---------------------------------------------------------------------------

    To eliminate reporting redundancies, the EPA is proposing several 
amendments to 40 CFR 98.236(aa)(3). First, to clarify which facilities 
have data overlap between subparts W and NN, the EPA is proposing to 
add a reporting element for natural gas processing plants at 40 CFR 
98.236(aa)(3)(viii) to indicate whether they report as a supplier under 
subpart NN. Next, the EPA is proposing that facilities that indicate 
that they both fractionate NGLs and report as a supplier under subpart 
NN would no longer be required to report the quantities of natural gas 
received or NGLs received or leaving the gas processing plant as 
specified in 40 CFR 98.236(aa)(3)(i), (iii) and (iv); this data would 
continue to be reported under subpart NN as specified in 40 CFR 
98.406(a)(3), 98.406(a)(1) and (2), 98.406(a)(4)(i) and (ii), 
respectively, thus, maintaining the ability to verify associated 
emissions reported under subpart W. See Table 3 of this preamble for 
more information.
    These facilities would, however, be required to continue reporting 
the data elements specified in 40 CFR 98.236(aa)(3)(ii) and (v) through 
(viii), as these reporting elements do not overlap with subpart NN 
reporting elements. Natural gas processing plants that do not 
fractionate or that fractionate but do not report as a supplier under 
subpart NN would continue to report all of the reporting elements for 
natural gas processing plants as specified in 40 CFR 98.236(aa)(3).
    The EPA is also proposing to remove the reporting elements for 
throughput for LDCs in 40 CFR 98.236(aa)(9). The EPA reviewed the data 
from subpart W and subpart NN and determined that there are no LDCs 
that report under subpart W that do not also report under subpart NN. 
In fact, an average of 385 LDCs report under subpart NN, while 170 LDCs 
report under subpart W. Subpart NN therefore provides more 
comprehensive coverage of the Natural Gas Distribution industry 
segment. Additionally, subpart NN has been in effect for LDCs since 
RY2011 while subpart W throughput information has only been collected 
since RY2015; thus, subpart NN has a more robust historical data set. 
During this review, the EPA determined that the data elements found in 
40 CFR 98.236(aa)(9)(i) through (v) of subpart W overlap with data 
elements in subpart NN as specified in 40 CFR 98.406(b)(1) through (3), 
98.406(b)(5) and (6), and 98.406(b)(13). To eliminate reporting 
redundancies, the EPA is proposing to remove these reporting elements 
from subpart W.
    Table 3 of this preamble shows all the duplicative data elements 
that the EPA is proposing to remove from subpart W for facilities that 
also report to subpart NN.

  Table 3--List of Proposed Subpart W Data Elements To Be Removed Where Analogous Subpart NN Data Elements are
                                                    Reported
----------------------------------------------------------------------------------------------------------------
       Subpart W data elements proposed to be eliminated               Analogous Subpart NN data elements
----------------------------------------------------------------------------------------------------------------
             Citation                       Description                Citation               Description
----------------------------------------------------------------------------------------------------------------
                                          Local Distribution Companies
----------------------------------------------------------------------------------------------------------------
Sec.   98.236(aa)(9)(i)...........  Quantity of natural gas     Sec.   98.406(b)(1)    Annual volume of natural
                                     received at all custody     Sec.   98.406(b)(5).   gas received by the LDC
                                     transfer stations.                                 at its city gate
                                                                                        stations and Annual
                                                                                        volume natural gas that
                                                                                        bypassed the city
                                                                                        gate(s).
Sec.   98.236(aa)(9)(ii)..........  Quantity of natural gas     Sec.   98.406(b)(3)..  Annual volume natural gas
                                     withdrawn from in-system                           withdrawn from on-system
                                     storage.                                           storage and annual
                                                                                        volume of vaporized LNG
                                                                                        withdrawn from storage.
Sec.   98.236(aa)(9)(iii).........  Quantity of natural gas     Sec.   98.406(b)(2)..  Annual volume of natural
                                     added to in-system                                 gas placed into storage
                                     storage.                                           or liquefied and stored.
Sec.   98.236(aa)(9)(iv)..........  Quantity of natural gas     Sec.                   Annual volume of natural
                                     delivered to end users.     98.406(b)(13)(i)       gas delivered by the LDC
                                                                 through (iv).          to residential
                                                                                        consumers, commercial
                                                                                        consumers, industrial
                                                                                        consumers, electricity
                                                                                        generating facilities.

[[Page 50363]]

 
Sec.   98.236(aa)(9)(v)...........  Quantity of natural gas     Sec.   98.406(b)(6)..  Annual volume of natural
                                     transferred to third                               gas delivered to
                                     parties.                                           downstream gas
                                                                                        transmission pipelines
                                                                                        and other LDCs.
----------------------------------------------------------------------------------------------------------------
                               Natural Gas Processing Plants That Fractionate NGLs
----------------------------------------------------------------------------------------------------------------
Sec.   98.236(aa)(3)(i)...........  Quantity of natural gas     Sec.   98.406(a)(3)..  Annual volume of natural
                                     received.                                          gas received for
                                                                                        processing.
Sec.   98.236(aa)(3)(iii).........  Cumulative quantity of all  Sec.   98.406(a)(2)    Annual quantity of each
                                     NGLs (bulk and              Sec.                   NGL product received and
                                     fractionated) received.     98.406(a)(4)(i).       annual quantities of y-
                                                                                        grade, o-grade and other
                                                                                        bulk NGLs received.
Sec.   98.236(aa)(3)(iv)..........  Cumulative quantity of all  Sec.   98.406(a)(1)    Annual quantity of each
                                     NGLs (bulk and              Sec.                   NGL product supplied and
                                     fractionated) leaving.      98.406(a)(4)(ii).      annual quantities of y-
                                                                                        grade, o-grade and other
                                                                                        bulk NGLs supplied.
----------------------------------------------------------------------------------------------------------------

    The EPA is also proposing to remove the reporting elements for the 
volume of natural gas used for operational purposes and natural gas 
stolen specified in 40 CFR 98.236(aa)(9)(vi) and (vii). These reporting 
elements are unique to subpart W, require additional burden to 
estimate, and have not been used for the EPA's analyses of the subpart 
W data. As a result of proposing to remove all of the 40 CFR 
98.236(aa)(9) data elements for the reasons explained in this section 
of this preamble, the EPA proposes to reserve paragraph 40 CFR 
98.236(aa)(9).
3. Onshore Natural Gas Transmission Pipeline Storage Throughputs
    Similar to Natural Gas Distribution facilities, Onshore Natural Gas 
Transmission Pipeline facilities are currently required to report five 
throughput volumes under subpart W, as specified in existing 40 CFR 
98.236(aa)(11). These five data reporting elements include: the 
quantity of natural gas received at all custody transfer stations; the 
quantity of natural gas withdrawn from in-system storage; the quantity 
of gas added to in-system storage; the quantity of gas transferred to 
third parties; and the quantity of gas consumed by the transmission 
pipeline facility for operational purposes. As noted in section III.U.1 
of this preamble, the EPA has received stakeholder feedback on the 
reporting elements for Natural Gas Distribution facilities, including 
questions submitted to the GHGRP Help Desk, regarding the term ``in-
system storage.'' Although the questions were specific to Natural Gas 
Distribution facilities, the term ``in-system storage'' is also 
included in the throughput reporting elements for Onshore Natural Gas 
Transmission Pipeline facilities at existing 40 CFR 98.236(aa)(11)(ii) 
and (iii). After consideration of the stakeholder feedback, the EPA is 
proposing to revise these provisions to better characterize the 
existing term ``in-system.'' Specifically, we are proposing to amend 40 
CFR 98.236(aa)(11)(ii) and (iii) to replace the term ``in-system'' with 
clarifying language that specifies withdrawals/additions of natural gas 
from storage are referring to Underground Natural Gas Storage and LNG 
Storage facilities that are owned and operated by the onshore natural 
gas transmission pipeline owner or operator that do not report under 
subpart W as direct emitters themselves. These amendments are expected 
to improve data quality consistent with section II.D of this preamble.

V. Other Proposed Minor Revisions or Clarifications

    See Table 4 of this preamble for the miscellaneous minor technical 
corrections not previously described in this preamble that we are 
proposing throughout subpart W, consistent with section II.D of this 
preamble.

          Table 4--Proposed Technical Corrections to Subpart W
------------------------------------------------------------------------
       Section (40 CFR)            Description of proposed amendment
------------------------------------------------------------------------
98.230(a)(2).................  Revise the instance of ``well pad'' to
                                read ``well-pad'' to correct
                                inconsistency in the term.
98.230(a)(9).................  Remove the ``)'' after ``GOR'' to correct
                                a typographical error.
98.232 introductory text.....  Add reference to paragraph (l) of this
                                section to clarify that annual reports
                                must include the information specified
                                in paragraph (l) if applicable.
98.232(c)(17), (d)(5) and      Revise the instances of ``acid gas
 (j)(3).                        removal vents'' to read ``acid gas
                                removal unit vents'' for consistency
                                with the defined term ``Acid gas removal
                                unit (AGR)'' in 40 CFR 98.238.
98.233(d)....................  Revise the instances of ``AGR unit'' to
                                read ``AGR'' for consistency with the
                                defined term ``Acid gas removal unit
                                (AGR)'' in 40 CFR 98.238.
98.233(e)(1)(x),               Add ``at the absorber inlet'' to the end
 98.236(e)(1)(xi) and (xii).    of the paragraph to clarify the location
                                for the wet natural gas temperature and
                                pressure to be used for modeling.
98.233(j), 98.236(j).........  Revise the instances of ``oil,'' ``oil/
                                condensate,'' and ``liquid'' to read
                                ``hydrocarbon liquids'' for consistency
                                with the requirement in 40 CFR 98.233(j)
                                to calculate emissions from
                                ``atmospheric pressure fixed roof
                                storage tanks receiving hydrocarbon
                                produced liquids,'' as noted in the 2015
                                amendments to subpart W (80 FR 64272,
                                October 22, 2015).
98.233(k)....................  Revise the introductory sentence in this
                                section to specify that 40 CFR 98.233(k)
                                does not apply to condensate storage
                                tanks that route emissions to flares or
                                other controls for consistency with
                                proposed amendment that would move
                                procedures for calculating flared
                                emissions from 40 CFR 98.233(k) to 40
                                CFR 98.233(n).

[[Page 50364]]

 
98.233(n)(5).................  Correct the cross reference in the
                                definition of the equation variable
                                ``Yj'' from paragraph (n)(1) to (n)(2).
98.233(o) introductory text    Move the last sentence in each paragraph
 and (p) introductory text.     to be the second sentence to clarify
                                that the calculation methodology for
                                compressors routed to flares,
                                combustion, or vapor recovery systems
                                apply to all industry segments.
98.233(o) introductory text    Revise the instances of ``vapor
 and (p) introductory text,     recovery'' to read ``vapor recovery
 236(o)(2)(ii) and (p)(2)(ii).  system'' to correct inconsistency in the
                                term.
98.233(p)(1)(i)..............  Correct the internal cross reference from
                                paragraph (o) to paragraph (p).
98.233(p)(4)(ii)(C)..........  Add missing ``in'' to read ``according to
                                methods set forth in Sec.   98.234(d).''
98.233(r) introductory text..  Revise the instance of ``CH'' in the
                                third sentence to read ``CH4'' to
                                correct a typographical error.
98.233(r), equations W-32A     Correct the cross reference in the
 and W-32B.                     definition of the equation variable
                                ``Es,MR,i'' and the equation variable
                                ``CountMR'' from paragraph (q)(9) to
                                (q)(2)(xi) or (q)(3)(vii)(B).
98.233(r)(6)(ii).............  Add reference to components listed in 40
                                CFR 98.232(i)(3), for consistency with
                                proposed amendments to 40 CFR
                                98.233(r)(6)(i).
98.233(t)(2).................  Revise the definition of equation
                                variable ``Za'' to include the sentence
                                following the definition of that
                                variable to correct a typographical
                                error.
98.233(u)(2)(ii).............  Format the heading to be in italicized
                                text.
98.233(z)....................  Revise the instances of ``high heat
                                value'' to read ``higher heating value''
                                to correct inconsistency in the term.
98.233(z), equations W-39A     Remove unnecessary ``constituent'' from
 and W-39B.                     ``CO2 constituent'' and ``methane
                                constituent'' and remove ``gas'' from
                                ``gas hydrocarbon constituent.'' Add
                                missing ``the'' to read ``to the
                                combustion unit'' in several variable
                                definitions.
98.234(e)....................  Renumber the Peng Robinson equation of
                                state from equation W-41 to equation W-
                                46 to provide space for five new
                                equations related to new source types in
                                proposed 40 CFR 98.233(dd) and (ee).
98.234(f)....................  Remove and reserve paragraph for
                                provisions for best available monitoring
                                methods for RY2015, as reports for that
                                reporting year can no longer be
                                submitted to the EPA.
98.234(g)....................  Remove and reserve paragraph for
                                provisions for best available monitoring
                                methods for RY2016, as reports for that
                                reporting year can no longer be
                                submitted to the EPA.
98.236 introductory text.....  Add missing ``than'' to read ``report gas
                                volumes at standard conditions rather
                                than the gas volumes at actual
                                conditions''
98.236(c)(5)(i) through (iii)  Edits to explicitly state that the
                                reporting requirements in this section
                                apply to pneumatic pumps that are vented
                                direct to atmosphere and for which
                                emissions are calculated using the
                                default emission factor (Calculation
                                Method 3).
                               Revise ``operational'' to ``pumping
                                liquid'' in the description of the
                                reported time element in 98.236(c)(5)(i)
                                to be consistent with the proposed
                                change described in section III.E.3 of
                                this preamble for Calculation Method 2.
98.236(d)(2)(iii)(B).........  Revise ``natural gas flow rate'' to read
                                ``natural gas feed flow rate'' for
                                consistency with the parameters listed
                                in 40 CFR 98.233(d)(4)(i).
98.236(e)(1) and (2).........  Revise the instances of ``vented to'' a
                                control device, vapor recovery, or a
                                flare to read ``routed to'' to correct
                                inconsistency in the phrases ``vented
                                to'' and ``routed to.''
                               Revise the instances of ``vapor recovery
                                device'' to read ``vapor recovery
                                system'' to correct inconsistency in the
                                term.
98.236(j)(2).................  Clarify that the reported information in
                                paragraphs (j)(1)(i) through (xvi)
                                should only include those atmospheric
                                storage tanks with emissions calculated
                                using Calculation Method 3.
98.236(k)(1)(iii)............  Correct the internal cross reference from
                                ``Sec.   98.233(k)(2)'' to ``Sec.
                                98.233(k)(1).''
98.236(k)(2).................  Add a cross reference to Sec.
                                98.233(k)(2) and revise sentence to
                                specify that the reported method used to
                                measure leak rates should be one
                                provided in that section.
98.236(l)(1), (2), (3), and    Revise the instances of ``vented to a
 (4) introductory text.         flare'' to read ``routed to a flare'' to
                                correct inconsistency in the phrases
                                ``vented to'' and ``routed to.''
98.236(p)(3)(ii).............  Add a missing period at the end of the
                                sentence.
98.236(bb)...................  Clarify that reporting for missing data
                                procedures includes the procedures used
                                to substitute an unavailable value of a
                                parameter (per 40 CFR 98.235(h)).
98.236(cc)...................  Correct the cross references from
                                paragraph (l)(1)(iv), (l)(2)(iv),
                                (l)(3)(iii), and (l)(4)(iii) to
                                (l)(1)(v), (l)(2)(v), (l)(3)(iv), and
                                (l)(4)(iv), respectively.
98.238.......................  Remove the second definition of
                                ``Facility with respect to natural gas
                                distribution for purposes of reporting
                                under this subpart and for the
                                corresponding subpart A requirements''
                                to eliminate an inadvertent identical
                                duplicative definition.
Tables W-1 through W-7 to      Replace Tables W-1 through W-7 with new
 subpart W of part 98.          Tables W-1 through W-6 to reorganize and
                                consolidate the emission factor tables
                                so that there are separate tables by
                                pollutant (whole gas, THC, and CH4) and
                                by type of factor (population and leaker
                                emission factors). Update cross
                                references to these tables accordingly
                                throughout subpart W.
------------------------------------------------------------------------

IV. Schedule for the Proposed Amendments

    The EPA is planning to consider the comments on these proposed 
changes, and, if any of the proposed amendments are finalized, to 
respond to the comments and promulgate any amendments by August 16, 
2024.\129\ We

[[Page 50365]]

are proposing that these amendments would become effective on January 
1, 2025, and that reporters would implement the majority of the changes 
beginning with reports prepared for RY2025 and submitted March 31, 
2026. The exception is the proposed reporting of the quantities of 
natural gas, crude oil, and condensate produced that is sent to sale in 
the calendar year for each well permanently shut-in and plugged 
(proposed 40 CFR 98.236(aa)(1)(iii)(C) through (E) and proposed 40 CFR 
98.236(aa)(2)(iv) through (vi)); those provisions would become 
effective on January 1, 2025 and reporters would include that 
information in their reports prepared for RY2024 and submitted March 
31, 2025. The submission date for RY2025 reports is over a year after 
we expect a final rule based on this proposal to be finalized, if 
finalized, thus providing a reasonable period for reporters to adjust 
to any finalized amendments. The proposed effective date would also 
allow ample time for the EPA to implement the changes into e-GGRT.
---------------------------------------------------------------------------

    \129\ Section 136(h) of the CAA requires subpart W to be revised 
as specified in that provision ``not later than 2 years after the 
date of enactment of this section.'' The section was enacted via 
Public Law No: 117-169 on August 16, 2022.
---------------------------------------------------------------------------

    We are likewise proposing that the proposed CBI determinations 
discussed in section VI of this preamble would become effective on 
January 1, 2025. The majority of the determinations are for new or 
revised data elements that would be included in annual GHG reports 
prepared for RY2025 and submitted March 31, 2026. The determinations 
related to the reporting of the quantities of natural gas, crude oil, 
and condensate produced that is sent to sale in the calendar year for 
each well permanently shut-in and plugged would apply the first year 
that data is collected (i.e., RY2024 data submitted on or before March 
31, 2025). Finally, there is one circumstance, discussed in detail in 
section V of this preamble, where the proposed determination covers 
data included in annual GHG reports submitted for prior years. In all 
cases, the proposed determinations for the data that the EPA has 
already received for these prior years or receives going forward for 
any reporting year would become effective on January 1, 2025.

V. Proposed Confidentiality and Reporting Determinations for Certain 
Data Reporting Elements

A. Overview and Background

    In this action we are proposing confidentiality determinations for 
new or substantially revised data elements that would be collected 
under the proposed rule amendments.
1. Background on EPA's Treatment of Data Collected Under Part 98
    Following proposal of part 98 (74 FR 16448, April 10, 2009), the 
EPA received comments addressing the issue of whether certain data 
could be entitled to confidential treatment. In response to these 
comments, the EPA stated in the preamble to the 2009 Final Rule (74 FR 
56387, October 30, 2009) that through a notice and comment process, we 
would establish those data elements that are entitled to confidential 
treatment. This proposal is one of a series of rules dealing with 
confidentiality determinations for data reported under part 98, 
including subpart C (General Stationary Fuel Combustion) and W 
(Petroleum and Natural Gas Systems).
     75 FR 39094, July 7, 2010. Describes the data categories 
and category-based determinations the EPA developed for the part 98 
data elements.
     76 FR 30782, May 26, 2011; hereafter referred to as the 
``2011 Final CBI Rule.'' Assigned data elements to data categories and 
published the final CBI determinations for the data elements in 34 part 
98 subparts, except for those data elements that were assigned to the 
``Inputs to Emission Equations'' data category.
     77 FR 48072, August 13, 2012. Finalized confidentiality 
determinations for data elements reported under nine subparts, 
including subpart W, except for those data elements that are ``inputs 
to emission equations''.
     78 FR 69337, November 29, 2013. Finalized determinations 
for new and revised data elements in 15 subparts, including subpart C, 
except for those data elements that are ``inputs to emission 
equations''.
     79 FR 63750, October 24, 2014. Revised recordkeeping and 
reporting requirements for ``inputs to emission equations'' for 23 
subparts and finalized confidentiality determinations for new data 
elements in 11 subparts, including subpart W.
     79 FR 70352, November 25, 2014. Finalized confidentiality 
determinations for new and substantially revised data elements in 
subpart W.
     80 FR 64262, October 22, 2015. Finalized confidentiality 
determinations for new data elements in subpart W.
     81 FR 86490, November 30, 2016. Finalized confidentiality 
determinations for new or substantially revised data elements in 
subpart W.
     81 FR 89188, December 9, 2016. Finalized confidentiality 
determinations for new or substantially revised data elements in 18 
subparts, including subpart C.
     87 FR 36920, June 21, 2022. Describes the EPA's revised 
approach to assessing data in response to Food Marketing Institute v. 
Argus Leader Media, 139 S. Ct. 2356 (2019) (hereafter referred to as 
Argus Leader).\130\
---------------------------------------------------------------------------

    \130\ See Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    To support the proposed amendments to part 98 described in section 
III of this preamble, we are proposing confidentiality determinations 
or ``emission data'' designations, in keeping with our existing 
approach (see section V.B.1 of this preamble), for the following:
     New or substantially revised reporting requirements (i.e., 
the proposed change requires additional or different data to be 
reported);
     Existing reporting requirements for which the EPA did not 
previously finalize a confidentiality determination or ``emission 
data'' designation.
    Further, we propose to designate certain new or substantially 
revised data elements as ``inputs to emission equations'' falling 
within the definition of ``emission data.'' For each element that we 
propose would fall in this category, we further propose whether the 
data element would be directly reported to the EPA or whether it would 
be entered into e-GGRT's Inputs Verification Tool (IVT) (see section 
V.C of this preamble for a discussion of ``inputs to emission 
equations'').
2. Summary of Data Elements Affected by the Proposed Amendments to Part 
98
    Table 5 of this preamble provides the number of affected data 
elements and the affected subparts for each of these proposed actions.

[[Page 50366]]



  Table 5--Summary of Proposed Actions Related to Data Confidentiality
------------------------------------------------------------------------
  Proposed actions related to data    Number of data
           confidentiality             elements \a\       Subpart(s)
------------------------------------------------------------------------
New or substantially revised                     522  C, W
 reporting requirements for which
 the EPA is proposing a
 confidentiality determination or
 ``emission data'' designation.
Existing reporting requirements for                1  W
 which the EPA is proposing a
 confidentiality determination or
 ``emission data'' designation
 because the EPA did not previously
 make a confidentiality
 determination or ``emission data''
 designation.
New or substantially revised                     162  W
 reporting requirements that the EPA
 is proposing be designated as
 ``inputs to emission equations''
 and for which the EPA is proposing
 reporting determinations.
------------------------------------------------------------------------
\a\ These data elements are individually listed in the memoranda: (1)
  Proposed Confidentiality Determinations and Emission Data Designations
  for Data Elements in Proposed Revisions to the Greenhouse Gas
  Reporting Rule for Petroleum and Natural Gas Systems (2) Proposed
  Reporting Determinations for Data Elements Assigned to the Inputs to
  Emission Equations Data Category in Proposed Revisions to the
  Greenhouse Gas Reporting Rule for Petroleum and Natural Gas Systems,
  available in the docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-
  2023-0234).

    The majority of the proposed determinations would apply at the same 
time as the proposed schedule described in section IV of this preamble. 
In the case where the EPA is re-proposing from the June 2022 proposal a 
determination for an existing data element where one was not previously 
made, the proposed determination would be effective on January 1, 2025, 
and would apply to annual reports submitted for RY2025, as well as all 
prior years that the data were collected. The determination related to 
the treatment of this prior year data will not change how the data was 
actually treated by the Agency, it will only conform the text of the 
determination to the actual confidentiality status the data has had 
since it was first collected.

B. Proposed Confidentiality Determinations and Emissions Data 
Designations

1. Proposed Approach
    The EPA is proposing to assess the data elements in this proposed 
rule, following the same approach as described in the 2022 Proposed 
Rule (87 FR 36920, June 21, 2022). In that proposal, the EPA described 
a revised approach to assessing data in response to Food Marketing 
Institute v. Argus Leader Media, 139 S. Ct. 2356 (2019) (hereafter 
referred to as Argus Leader).\131\
---------------------------------------------------------------------------

    \131\ In the 2022 Proposed Rule (87 FR 36920, June 21, 2022), 
the EPA proposed that the Argus Leader decision does not affect our 
historical approach to designating data elements as ``inputs to 
emission equations'' or our previous approach for designating new 
and revised reporting requirements as ``emission data,'' which are 
described in the July 7, 2010 proposal (75 FR 39094), 2011 Final CBI 
Rule, and October 24, 2014 final rule (79 FR 63750). For reporting 
elements that the EPA did not designate as ``emission data'' or 
``inputs to emission equations,'' the EPA proposed to revise the 
historical approach to assign data elements to data categories 
established in the 2011 Final CBI Rule, and instead proposed to 
assess each individual reporting element according to the Argus 
Leader criteria.
---------------------------------------------------------------------------

    We propose to continue identifying new and revised reporting 
elements that qualify as ``emission data'' (i.e., data necessary to 
determine the identity, amount, frequency, or concentration of the 
emission emitted by the reporting facilities) by evaluating the data 
for assignment to one of the four data categories designated by the 
2011 Final CBI Rule to meet the CAA definition of ``emission data'' in 
40 CFR 2.301(a)(2)(i) \132\ (hereafter referred to as ``emission data 
categories''). Refer to section II.B of the July 7, 2010, proposal for 
descriptions of each of these data categories and the EPA's rationale 
for designating each data category as ``emission data.''
---------------------------------------------------------------------------

    \132\ See section I.C of the July 7, 2010 proposal (75 FR 39100) 
for a discussion of the definition of ``emission data.'' As 
discussed therein, the relevant paragraphs (to the GHGRP) of the CAA 
definition of ``emission data'' include 40 CFR 2.301(a)(2)(i)(A) and 
(C), as follows: (A) ``Information necessary to determine the 
identity, amount, frequency, concentration, or other characteristics 
(to the extent related to air quality) of any emission which has 
been emitted by the source (or of any pollutant resulting from any 
emission by the source), or any combination of the foregoing;'' and 
(C) ``A general description of the location and/or nature of the 
source to the extent necessary to identify the source and to 
distinguish it from other sources (including, to the extent 
necessary for such purposes, a description of the device, 
installation, or operation constituting the source).''
---------------------------------------------------------------------------

    For data elements designated as ``inputs to emission equations,'' 
the EPA proposes to assign data elements to one of two subcategories, 
including data elements entered into IVT and those directly reported to 
the EPA. See section V.C of this preamble for further descriptions of 
each of these data categories.
    For new or revised data elements that the EPA does not propose to 
designate as ``emission data'' or ``inputs to emission equations,'' the 
EPA proposes to assess each individual reporting element according to 
the Argus Leader standard, established in 2019. Accordingly, we propose 
to evaluate each new or revised data element not designated as 
``emission data'' or ``inputs to emission equations'' individually to 
determine whether the information is customarily and actually treated 
as private by the reporter and are proposing a confidentiality 
determination based on that evaluation.
    Consistent with the 40 CFR part 2 procedures, this rulemaking 
provides an opportunity for affected stakeholders to justify any 
confidentiality claim they may have for the data they are required to 
submit under parts 98 (except for emission data which are not entitled 
to confidential treatment).

2. Proposed Confidentiality Determinations and ``Emission Data'' 
Designations

    In this section, we discuss the proposed confidentiality 
determinations and ``emission data'' designations for 522 new or 
substantially revised data elements. We also discuss one existing data 
element (i.e., not proposed to be substantially revised) for which for 
no determination has been previously established.
a. Proposed Confidentiality Determinations and ``Emission Data'' 
Designations for New or Substantially Revised Data Reporting Elements
    For the 522 new and substantially revised data elements, the EPA is 
proposing ``emission data'' designations for 277 data elements and 
confidentiality determinations for 245 data elements. The EPA is 
proposing to designate 277 new or substantially revised data elements 
as ``emission data'' by assigning the data elements to three emission 
data categories (established in the 2011 Final CBI Rule as discussed in 
section V.B.1 of this preamble), as follows:
     114 data elements that are proposed to be reported under 
subpart W are proposed to be assigned to the ``Emissions'' emission 
data category;

[[Page 50367]]

     126 data elements that are proposed to be reported under 
subparts C and W are proposed to be assigned to the ``Facility and Unit 
Identifier Information'' emission data category; and
     37 data elements that are proposed to be reported under 
subparts C and W are proposed to be assigned to the ``Calculation 
Methodology and Methodological Tier'' emission data category.
    Refer to Table 1 in the memorandum, Proposed Confidentiality 
Determinations and Emission Data Designations for Data Elements in 
Proposed Revisions to the Greenhouse Gas Reporting Rule for Petroleum 
and Natural Gas Systems, available in the docket for this rulemaking 
(Docket Id. No. EPA-HQ-OAR-2023-0234), for a list of these 277 data 
elements proposed to be designated as ``emission data,'' the proposed 
emission data category assignment for each data element, and the EPA's 
rationale for each proposed ``emission data'' category assignment.
    The remaining 245 new and substantially revised data elements 
proposed to be reported under subpart W are not proposed to be 
designated as ``emission data,'' or ``inputs to emission equations.'' 
Rather, this proposal assesses each individual reporting element 
according to the Argus Leader criteria as discussed in section V.B.1 of 
this preamble. Refer to Table 2 in the memorandum, Proposed 
Confidentiality Determinations and Emission Data Designations for Data 
Elements in Proposed Revisions to the Greenhouse Gas Reporting Rule for 
Petroleum and Natural Gas Systems, to see a list of these 245 specific 
data elements, the proposed confidentiality determination for each data 
element, and the EPA's rationale for each proposed confidentiality 
determination. These determinations show the data elements that would 
be entitled to confidential treatment if submitted to the EPA, and 
those that the EPA would publish.
b. Proposed Confidentiality Determinations for Existing Part 98 Data 
Elements for Which No Determination Has Been Previously Established
    We are re-proposing one confidentiality determination for a single 
data element currently reported under subpart W for which no 
confidentiality determination or ``emission data'' designation has been 
previously finalized under part 98. In the 2022 Proposed Rule, we 
reviewed previous rulemakings and found 26 data elements where a 
confidentiality determination or ``emission data'' designation had not 
been made under subpart W. In the 2022 Proposed Rule, we had evaluated 
these data elements and proposed either confidentiality determinations 
or ``emission data'' designations, using the categories established in 
the 2011 Final CBI Rule. This proposal would revise 25 out of 26 of 
these data elements. Therefore, these 25 revised data elements are 
included in the proposed confidentiality determinations and ``emission 
data'' designations discussed in section V.B.2.a of this preamble, 
consistent with our approach for other data elements that we are 
proposing to revise in this proposed rulemaking. That leaves one 
existing data element for which no previous determination has been 
finalized. We assessed the one remaining data element with no existing 
confidentiality determination according to the Argus Leader criteria 
and are re-proposing the confidentiality determination from the June 
2022 Proposed Rule. Refer to Table 3 in the memorandum, Proposed 
Confidentiality Determinations and Emission Data Designations for Data 
Elements in Proposed Revisions to the Greenhouse Gas Reporting Rule for 
Petroleum and Natural Gas Systems, available in the docket for this 
rulemaking (Docket Id. No. EPA-HQ-OAR-2023-0234), for details of the 
confidentiality determinations.

C. Proposed Reporting Determinations for Inputs to Emissions Equations

    In this section, we discuss data elements that the EPA proposes to 
assign to the ``Inputs to Emission Equations'' data category. This data 
category includes data elements that are the inputs to the emission 
equations used by sources that directly emit GHGs to calculate their 
annual GHG emissions.\133\ As discussed in section VI.B.1 of the 2022 
Proposed Rule (87 FR 36920, June 21, 2022), the EPA determined that the 
Argus Leader standard does not apply to our approach for handling data 
elements assigned to the ``Inputs to Emission Equations'' data 
category.
---------------------------------------------------------------------------

    \133\ For facilities that directly emit GHGs, part 98 includes 
equations that facilities use to calculate emission values. The 
``Inputs to Emission Equations'' data category includes the data 
elements that facilities would be required to enter in the equations 
to calculate the facility emissions values, e.g., monthly 
consumption or production data or measured values from required 
monitoring, such as carbon content. See 75 FR 39094, July 7, 2010 
for a full description of the ``Inputs to Emission Equations'' data 
category.
---------------------------------------------------------------------------

    The EPA organizes data assigned to the ``Inputs to Emission 
Equations'' data category into two subcategories. The first subcategory 
includes ``inputs to emission equations'' that must be directly 
reported to the EPA. This is done in circumstances where the EPA has 
determined that the data elements do not meet the criteria necessary 
for them to be entered into the IVT system. These ``inputs to emission 
equations,'' once received by the EPA, are not entitled to confidential 
treatment. The second subcategory includes ``inputs to emission 
equations'' that are entered into IVT. These ``inputs to emission 
equations'' are entered into IVT to satisfy the EPA's verification 
requirements. These data must be maintained as verification software 
records by the submitter, but the data are not included in the annual 
report that is submitted to the EPA. This is done in circumstances 
where the EPA has determined that the data elements meet the criteria 
necessary for them to be entered into the IVT system. Refer to the 
memorandum, Proposed Reporting Determinations for Data Elements 
Assigned to the Inputs to Emission Equations Data Category in Proposed 
Revisions to the Greenhouse Gas Reporting Rule for Petroleum and 
Natural Gas Systems, available in the docket for this rulemaking 
(Docket Id. No. EPA-HQ-OAR-2023-0234), for a discussion of the criteria 
established in 2011 for evaluating whether data assigned to the 
``Inputs to Emission Equations'' data category should be entered into 
the IVT system.
    We are proposing to assign 162 new or substantially revised data 
elements in subparts C and W to the ``Inputs to Emission Equations'' 
data category. We evaluated each of the 162 proposed new or 
substantially revised data elements assigned to the ``Inputs to 
Emission Equations'' data category and determined that none of these 
162 data elements meet the criteria necessary for them to be entered 
into the IVT system; therefore, we propose that these 162 data elements 
be directly reported to the EPA. As ``inputs to emission equations'' 
are emissions data, these 162 data elements would not be eligible for 
confidential treatment once directly reported to the EPA, and they 
would be published once received by the EPA. Refer to Table 1 in the 
memorandum, Proposed Reporting Determinations for Data Elements 
Assigned to the Inputs to Emission Equations Data Category in Proposed 
Revisions to the Greenhouse Gas Reporting Rule for Petroleum and 
Natural Gas Systems, available in the docket for this rulemaking 
(Docket Id. No. EPA-HQ-OAR-2023-0234), for a list of these 162 data 
elements proposed to be designated as ``inputs to emission equations'' 
that would be directly reported to the EPA and the EPA's

[[Page 50368]]

rationale for the proposed reporting determinations.

D. Request for Comments on Proposed Amendments to 40 CFR Part 2, 
Category Assignments, Confidentiality Determinations, or Determinations 
of Inputs To Be Reported

    We solicit comment on the proposed categories, confidentiality, and 
reporting determinations in this proposed rule. By proposing 
confidentiality determinations prior to data reporting through this 
proposal and rulemaking process, we are providing potential reporters 
an opportunity to submit comments, particularly comments addressing any 
data elements not entitled to confidential treatment under this 
proposal, but which reporters customarily and actually treat as 
private. Likewise, we provide potential reporters an opportunity to 
submit comments on whether there are disclosure concerns for data 
elements proposed to be categorized as ``inputs to emission equations'' 
that we propose would be directly reported to the EPA via annual 
reports and subsequently released by the EPA. This opportunity to 
submit comments is intended to provide reporters with the opportunity 
to substantiate their confidentiality claims that would ordinarily be 
afforded to reporters when the EPA considers claims for confidential 
treatment of information in case-by-case confidentiality determinations 
under 40 CFR part 2. In addition, the comment period provides an 
opportunity to respond to the EPA's proposed determinations with more 
information for the Agency to consider prior to finalization. We will 
evaluate the comments on our proposed determinations, including claims 
of confidentiality and information substantiating such claims, before 
finalizing the confidentiality determinations. Please note that this 
will be reporters' only opportunity to substantiate a confidentiality 
claim for data elements included in this proposed rule where a 
confidentiality determination or reporting determination is being 
proposed. Upon finalizing the confidentiality determinations and 
reporting determinations of the data elements identified in this 
proposed rule, the EPA will release or withhold these data in 
accordance with 40 CFR 2.301(d), which contains special provisions 
governing the treatment of part 98 data for which confidentiality 
determinations have been made through rulemaking pursuant to CAA 
sections 114 and 307(d).
    If members of the public have reason to believe any data elements 
in this proposed rule that are proposed to be treated as confidential 
are not customarily and actually treated as private by reporters, 
please provide comment explaining why the Agency should not provide an 
assurance of confidential treatment for such data. Likewise, if members 
of the public have reason to disagree with the EPA's proposal that 
``inputs to emission equations'' qualify to be entered into IVT and 
retained as verification software records instead of being directly 
reported to the EPA, please provide comment explaining why the ``inputs 
to emission equations'' do not qualify to be entered into IVT, should 
be directly reported to the EPA, and subsequently released by the EPA. 
As described in section III.D, the EPA is proposing revisions to 
several existing data elements within the Onshore Petroleum and Natural 
Gas Production and Onshore Petroleum and Natural Gas Gathering and 
Boosting industry segments such that the data would be reported by 
facilities at the site level. Under the current requirements, 
facilities report much of this information aggregated across multiple 
sites. Given that the proposed revisions would require that facilities 
report more specific information, the EPA is requesting comment on the 
confidentiality and reporting determinations for this site-level 
reporting. For any revised data elements that fall into an ``emissions 
data'' category, the EPA is proposing that the data would continue to 
be released regardless of whether it is collected at the site level or 
aggregated across sites. However, for data elements that do not fall 
into an ``emissions data'' category, the EPA is seeking comment 
regarding whether any of these particular data elements are customarily 
and actually treated as private together with specific information 
supporting this position when reported at the site level. The EPA 
believes that the information in this category that would not already 
be released as emission data is not information that is customarily and 
actually treated as confidential by submitters, even at the site level. 
The EPA is aware of outlets where much of this information is already 
released publicly, such as State and local records including records 
from oil and gas permitting authorities, taxing authorities, and 
environmental agencies, U.S. Securities and Exchange Commission (SEC) 
forms for publicly traded companies, company websites, data services 
such as Enverus, S&P Global/IHS Markit, Rystad Energy and Wood 
Mackenzie, and publications like Oil &Gas Journal, Petroleum Economist, 
and Upstream. Upon consideration of comments, the EPA will consider 
releasing this information directly as proposed, or other options that 
may take into account confidentiality concerns, but still release as 
much of this valuable information to the public as possible.
    When submitting comments regarding the confidentiality 
determinations or reporting determinations we are proposing in this 
action, please identify each individual proposed new, revised, or 
existing data element you consider to be confidential or do not 
consider to be ``emission data'' in your comments. If the data element 
has been designated as ``emission data,'' please explain why you do not 
believe the information should be considered ``emission data'' as 
defined in 40 CFR 2.301(a)(2)(i). If the data has not been designated 
as ``emission data'' and is proposed to not be entitled to confidential 
treatment, please explain specifically how the data element is 
commercial or financial information that is both customarily and 
actually treated as private. Particularly describe the measures 
currently taken to keep the data confidential and how that information 
has been customarily treated by your company and/or business sector in 
the past. This explanation is based on the requirements for 
confidential treatment set forth in Argus Leader. If the data element 
has been designated as an ``input to an emission equation'' (i.e., not 
entitled to confidential treatment) and proposed to be directly 
reported to the EPA via annual reports and subsequently released by the 
EPA, please explain specifically why there are disclosure concerns.
    Please also discuss how this data element may be different from or 
similar to data that are already publicly available, including data 
already collected and published annually by the GHGRP, as applicable. 
Please submit information identifying any publicly available sources of 
information containing the specific data elements in question. Data 
that are already available through other sources would likely be found 
not to qualify for confidential treatment. In your comments, please 
identify the manner and location in which each specific data element 
you identify is publicly available, including a citation. If the data 
are physically published, such as in a book, industry trade 
publication, or Federal agency publication, provide the title, volume 
number (if applicable), author(s), publisher, publication date, and 
International Standard Book Number

[[Page 50369]]

(ISBN) or other identifier. For data published on a website, provide 
the address of the website, the date you last visited the website and 
identify the website publisher and content author. Please avoid 
conclusory and unsubstantiated statements, or general assertions 
regarding the confidential nature of the information.
    Finally, we are not proposing new confidentiality determinations 
and reporting determinations for data reporting elements proposed to be 
unchanged or minimally revised because the final confidentiality 
determinations and reporting determinations that the EPA made in 
previous rules for these unchanged or minimally revised data elements 
are unaffected by this proposed amendment and will continue to apply. 
The minimally revised data elements are those where we are proposing 
revisions that would not require additional or different data to be 
reported. For example, we are proposing to amend 40 CFR 
98.236(aa)(5)(ii) to clarify that facilities reporting to the 
Underground Natural Gas Storage industry segment must report the 
quantity of natural gas withdrawn from storage and sent to sale in the 
calendar year. As discussed in section III.U of this preamble, we are 
proposing several text edits to include ``natural'' before each 
instance of ``gas'' and to use the phrase ``sent to sale'' for 
consistency with CAA section 136 language. This proposed change is for 
consistency in language and would not affect the data collected or the 
interpretation of the terms, and therefore we are not proposing a new 
or revised confidentiality determination. However, we are soliciting 
comment on any cases where a minor revision would affect the previous 
confidentiality determination or reporting determination. In your 
comments, please identify the specific data element, including name and 
citation, and explain why the minor revision would affect the previous 
confidentiality determination or reporting determination.

VI. Impacts of the Proposed Amendments

    The proposed revisions would amend requirements that apply to the 
petroleum and natural gas systems source category of the Greenhouse Gas 
Reporting Rule consistent with CAA section 136(h) to ensure that 
reporting under subpart W is based on empirical data and accurately 
reflects total CH4 emissions and waste emissions from applicable 
facilities, 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 future implementation of CAA 
section 136. These proposed revisions include improving the existing 
calculation, recordkeeping, and reporting requirements. The EPA is 
proposing amendments to part 98 in order to implement improvements to 
the GHGRP, including revisions to update existing emission factors and 
emissions estimation methodologies, revisions to require reporting of 
additional data for new emission sources and address potential gaps in 
reporting, and revisions to collect data that would improve the EPA's 
understanding of the sector-specific processes or other factors that 
influence GHG emission rates, verification of collected data, or to 
complement or inform other EPA programs. The EPA is also proposing 
revisions that would improve implementation of the program, such as 
those that would update applicability estimation methodologies, provide 
flexibility for or simplifying calculation and monitoring 
methodologies, streamline recordkeeping and reporting, and other minor 
technical corrections or clarifications identified as a result of 
working with the affected sources during rule implementation and 
outreach. The EPA anticipates that the proposed revisions to improve 
accuracy of reporting would increase costs for reporters. To the extent 
consideration of costs is relevant to the EPA's proposal for meeting 
its obligation under CAA section 136(h), these anticipated costs are 
reasonable.
    As discussed in section V of this preamble, we are proposing to 
implement these changes beginning in RY2025. Costs have been estimated 
over the three years following the year of implementation. The 
incremental implementation costs for each reporting year are summarized 
in Table 6 of this preamble. The estimated annual average labor burden 
is $41.4 million per year and the annual average labor burden per 
reporter is $13,500. The incremental burden for subpart W and the 
incremental costs per reporter are shown in Table 6 of this preamble.

                      Table 6--Total Incremental Labor Burden for Reporting Years 2025-2027
                                                  [$2021/year]
----------------------------------------------------------------------------------------------------------------
          Cost summary                  RY2025              RY2026              RY2027          Annual  average
----------------------------------------------------------------------------------------------------------------
Burden by Year..................  $41.4 million.....  $41.4 million.....  $41.4 million.....  $41.4 million.
Number of Reporters.............  3,077.............  3,077.............  3,077.............  3,077.
Incremental Labor Cost per        $13,500...........  $13,500...........  $13,500...........  $13,500.
 Reporter.
----------------------------------------------------------------------------------------------------------------

    There is an additional annualized incremental burden of $50.9 
million for capital and operation and maintenance (O&M) costs, which 
reflects changes to applicability and monitoring. Including capital and 
O&M costs, the total annual average burden is $92.3 million over the 
next 3 years.
    The total incremental burden and burden by reporter per subpart W 
industry segment are shown in Table 7 of this preamble.

[[Page 50370]]



                                          Table 7--Total Incremental Burden by Industry Segment and by Reporter
                                                                    [$2021/year] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                           Total annual
                        Industry segment                            Count of      Labor costs \c\    Capital and O&M   Total annual cost     cost per
                                                                  reporters \b\                        (annualized)                          reporter
--------------------------------------------------------------------------------------------------------------------------------------------------------
Onshore Petroleum and Natural Gas Production...................             777        $27,957,105        $36,301,841        $64,258,946         $82,701
Offshore Petroleum and Natural Gas Production..................             141              3,793                  0              3,793              27
Onshore Petroleum and Natural Gas Gathering and Boosting.......             361          1,490,222          4,013,157          5,503,379          15,245
Onshore Natural Gas Processing.................................             515          8,768,994          3,936,094         12,705,088          24,670
Onshore Natural Gas Transmission Compression...................           1,008          2,755,614          6,028,399          8,784,013           8,714
Natural Gas Transmission Pipeline..............................              53             87,596                187             87,783           1,656
Underground Natural Gas Storage................................              68            167,324            417,348            584,673           8,598
LNG Import and Export Equipment................................              11              4,605             18,649             23,254           2,114
LNG Storage....................................................               7             14,714             20,953             35,667           5,095
Natural Gas Distribution.......................................             164            163,069            161,370            324,439           1,978
                                                                ----------------------------------------------------------------------------------------
    Total......................................................           3,077         41,413,037         50,897,998         92,311,035          30,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Includes estimated increase in costs following implementation of revisions in RY2025.
\b\ Counts are based on GHGRP data reported in RY2020 and 567 new facilities, as detailed in the memorandum, Assessment of Burden Impacts for Proposed
  Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas Systems.
\c\ Initial year and subsequent year labor costs are $41.4 million per year.

    A full discussion of the cost and emission impacts may be found in 
the memorandum, Assessment of Burden Impacts for Proposed Greenhouse 
Gas Reporting Rule Revisions for Petroleum and Natural Gas Systems 
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-
2023-0234. The EPA is requesting comment on the assumptions and 
methodology used in this memorandum.
    The national costs of the proposed rule reflect the fact that there 
are a large number of affected entities, but per entity costs are low. 
To further assess the economic impacts of the proposed rule, the EPA 
conducted a screening analysis comparing the estimated total annualized 
compliance costs for the petroleum and natural gas systems industry 
segments with industry mean cost-to-revenue ratios based on the total 
facility costs that are applicable to parent entities in each segment. 
This analysis shows that the per-entity impacts within each industry 
segment are low. These low mean cost-to-revenue ratios indicate that 
the proposed rule is unlikely to result in significant changes in 
parent entity production decisions or other choices that would result 
in significant fluctuations in prices or quantities in affected 
markets.

Table 8--Mean CRRs for Parent Entities by Industry Segment, All Business
                                  Sizes
------------------------------------------------------------------------
                                                    Mean CRR (standard
                Industry segment                          error)
------------------------------------------------------------------------
Onshore petroleum and natural gas production...       0.87% (0.81-0.92%)
Offshore petroleum and natural gas production..       0.06% (0.04-0.09%)
Onshore petroleum and natural gas gathering and       0.41% (0.33-0.48%)
 boosting......................................
Onshore natural gas processing.................       0.50% (0.37-0.63%)
Onshore natural gas transmission compression...       0.09% (0.06-0.12%)
Onshore natural gas transmission pipeline......       0.07% (0.05-0.10%)
Underground natural gas storage................       0.07% (0.05-0.09%)
LNG import and export equipment................       0.01% (0.00-0.01%)
LNG storage....................................       0.00% (0.00-0.00%)
Natural gas distribution.......................       0.08% (0.05-0.10%)
All segments...................................       0.60% (0.55-0.64%)
------------------------------------------------------------------------
CRR = cost-to-revenue ratio.

    The EPA also evaluated the mean costs to individual facilities and 
mean costs to parents (accounting for multiple owned facilities) for 
reporters (shown in Table 9 of this preamble), which are relatively 
small given the high revenues of parent companies within the petroleum 
and natural gas systems sector. There are currently 2,322 existing 
facilities reporting to subpart W that are owned by approximately 600 
parent entities. Based on a review of revenue data available for 
approximately 585 parent entities, the proposed rule costs represent 
less than one percent of the total annual revenue for entities that 
would be reporting under subpart W.

[[Page 50371]]



   Table 9--Estimated Mean Costs and Revenues for Facility and Parent
                         Entities, All Segments
------------------------------------------------------------------------
                                                Estimated values (95%
                  Metric                        confidence interval)
------------------------------------------------------------------------
Mean cost to parent entity per facility     $21.7 ($21.5-$21.8).
 (thousands).
Mean number of facilities owned per parent  4.9 (4.4-5.4).
Mean cost to parent for all associated      $105.7 ($100.8-$110.7).
 facilities (thousands).
Mean parent entity revenue (billions).....  $5.18 ($4.59-$5.77).
Total revenue for all subpart W parents     $3.89 ($3.45-$4.33).
 (trillions).
Mean CRR for parent entities, using all     0.60% (0.55-0.64%).
 facility costs.
------------------------------------------------------------------------
Note: Because parent revenues are heavily skewed towards higher
  revenues, the ratio of mean cost to mean revenue (which is
  approximately 0.002%) differs substantially from the mean cost-to-
  revenue ratio (which is approximately 0.60%).

    The EPA has also considered the potential benefits of the proposed 
amendments to subpart W. Because this is a proposed reporting rule, the 
EPA did not quantify estimated emission reductions or monetize the 
benefits from such reductions that could be associated with this 
proposed action. The benefits of the proposed amendments are based on 
their relevance to policy making, transparency, and market efficiency. 
The proposed amendments to the reporting system for petroleum and 
natural gas systems would benefit policymakers and the public by 
increasing the completeness and accuracy of facility emissions data. 
Public data on emissions allows for accountability of emitters to the 
public. Improved facility-specific emissions data would aid local, 
state, and national policymakers as they evaluate and consider future 
climate change policy decisions and other policy decisions for criteria 
pollutants, ambient air quality standards, and toxic air emissions. The 
benefits of improved reporting of petroleum and natural gas systems GHG 
emissions to government also include enhancing existing programs, such 
as the Natural Gas STAR Program, that provide significant benefits, 
such as identifying cost-effective technologies and practices to reduce 
emissions of CH4 from operations in all of the major industry sectors--
production, gathering and processing, transmission, and distribution. 
The Natural Gas STAR program leverages GHGRP reporting data to track 
partner petroleum and natural gas company activities related to their 
Methane Challenge commitments. The proposed changes to subpart W would 
increase knowledge of the location and magnitude of significant CH4 
emissions sources in the petroleum and natural gas industry, and 
associated activities and technologies, which can result in 
improvements in technologies and the identification of new emissions 
reducing technologies.
    Benefits to industry of improved GHG emissions monitoring and 
reporting under the proposed amendments include the value of having 
verifiable empirical data to present to the public to demonstrate 
appropriate environmental stewardship, and a better understanding of 
their emission levels and sources to identify opportunities to reduce 
emissions. The EPA also anticipates that improvements to monitoring and 
implementation of empirical measurement methods would result in 
emissions reductions. Based on activity data used to inform the U.S. 
GHG Inventory, the EPA estimated approximately 403.4 billion cubic feet 
of fugitive CH4 emissions (including fugitive leaks, venting, and 
flaring) in 2021, representing a potential loss of over $871 million 
\134\ to industry. To the extent that more frequent monitoring helps to 
identify and mitigate emissions from leakage, a robust reporting 
program based on empirical data can help industry and achieve and 
disseminate their environmental achievements. Businesses and other 
innovators can use the data to determine and track their GHG 
footprints, find cost-saving efficiencies that reduce GHG emissions and 
save product, and foster technologies to protect public health and the 
environment. to reduce costs associated with fugitive emissions. Such 
monitoring also allows for inclusion of standardized GHG data into 
environmental management systems, providing the necessary information 
to track actual company performance and to achieve and disseminate 
their environmental achievements. Once facilities invest in the 
institutional knowledge and systems to monitor and report emissions, 
the cost of monitoring should fall and the accuracy of the accounting 
should continue to improve. The proposed amendments would continue to 
allow for facilities to benchmark themselves against similar facilities 
to understand better their relative standing within their industry and 
achieve and disseminate information about their environmental 
performance.
---------------------------------------------------------------------------

    \134\ Based on natural gas prices from EIA (current monthly 
average, April 2023). See https://www.eia.gov/dnav/ng/hist/rngwhhdm.htm.
---------------------------------------------------------------------------

    In addition, transparent public data on emissions allows for 
accountability of polluters to the public who bear the cost of the 
pollution. The GHGRP serves as a powerful data resource and provides a 
critical tool for communities to identify nearby sources of GHGs and 
provide information to state and local governments. GHGRP data are 
easily accessible to the public via the EPA's online data publication 
tool, also known as FLIGHT (Facility Level Information on Greenhouse 
gases Tool) at: https://ghgdata.epa.gov/ghgp/main.do. FLIGHT is 
designed for the general public and allows users to view and sort GHG 
data from over 8,000 entities in a variety of ways including by 
location, industrial sector, and type of GHG emitted, and includes 
demographic data. Although the emissions reported to the EPA by 
reporting facilities are global pollutants, many of these facilities 
also release pollutants that have a more direct and local impact in the 
surrounding communities. Citizens, community groups, and labor unions 
have made use of public pollutant release data to negotiate directly 
with emitters to lower emissions, avoiding the need for additional 
regulatory action.
    The proposed amendments would improve the quality and transparency 
of this reported data to affected communities, for example, by 
providing data on other large release events. The proposed 
disaggregation of reporting requirements within the Onshore Petroleum 
and Natural Gas Production and Onshore Petroleum and Natural Gas 
Gathering and Boosting industry segments to at least the well-pad and 
gathering boosting site-level, respectively, would provide communities 
with more localized information on GHG emissions from these segments. 
Therefore, while the EPA has not quantified the benefits of the 
proposed amendments to subpart W, the agency believes that they would 
be substantial and justify the estimated costs, if finalized as 
proposed. In

[[Page 50372]]

addition, the focus on empirical data that is the foundation of this 
proposed rule was mandated by Congress in the IRA.

VII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This action is a ``significant regulatory action'' as defined in 
Executive Order 12866, as amended by Executive Order 14094. 
Accordingly, the EPA submitted this action to the Office of Management 
and Budget (OMB) for Executive Order 12866 review. Documentation of any 
changes made in response to the Executive Order 12866 review is 
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-
2023-0234. The EPA prepared an analysis of the potential impacts 
associated with this action. This analysis, Assessment of Burden 
Impacts for Proposed Greenhouse Gas Reporting Rule Revisions for 
Petroleum and Natural Gas Systems, is also available in the docket to 
this rulemaking and is briefly summarized in section VI of this 
preamble.

B. Paperwork Reduction Act

    The information collection activities in this proposed rule have 
been submitted for approval to the OMB under the PRA. The ICR document 
that the EPA prepared has been assigned OMB No. 2060-NEW (EPA ICR 
number 2774.01). You can find a copy of the ICR in the docket for this 
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234, and it is briefly 
summarized here.
    The EPA estimates that the proposed amendments would result in an 
increase in burden. The burden associated with the proposed rule is due 
to revisions that would expand reporting to include new emission 
sources or that expand the industry segments covered by existing 
emissions sources and that may impact the facilities that are required 
to report to subpart W; revisions to emissions calculation 
methodologies that would require additional monitoring; and revisions 
to collect additional data to more accurately reflect and verify total 
CH4 emissions in reports submitted to the GHGRP or to 
provide information for future implementation of the waste emissions 
charge under CAA section 136. As a result of these proposed revisions, 
567 new sources are expected to become subject to subpart W. Labor and 
O&M costs are included for those new sources to comply with the 
reporting and recordkeeping costs detailed in EPA ICR No. 2300.18, as 
well as costs to comply with these proposed revisions.
    The estimated annual average burden is 417,821 hours and $92.3 
million over the 3 years covered by this information collection. 
Further information on the EPA's assessment on the impact on burden can 
be found in the memorandum, Assessment of Burden Impacts for Proposed 
Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas 
Systems, in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-
2023-0234.
    Respondents/affected entities: Owners and operators of petroleum 
and natural gas systems that must report their GHG emissions and other 
data to the EPA to comply with 40 CFR part 98.
    Respondent's obligation to respond: The respondent's obligation to 
respond is mandatory under the authority provided in CAA sections 114 
and 136.
    Estimated number of respondents: 3,077 (affected by proposed 
amendments).
    Frequency of response: Annually.
    Total estimated burden: 417,821 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total estimated cost: $92.3 million, includes $50.9 million 
annualized capital or operation & maintenance costs.
    An Agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    Submit your comments on the Agency's need for this information, the 
accuracy of the provided burden estimates and any suggested methods for 
minimizing respondent burden to the EPA using the docket identified at 
the beginning of this rulemaking. You may also send your ICR-related 
comments to OMB's Office of Information and Regulatory Affairs using 
the interface at https://www.reginfo.gov/public/do/PRAMain. Find this 
particular information collection by selecting ``Currently under 
Review--Open for Public Comments'' or by using the search function. OMB 
must receive comments no later than October 2, 2023. The EPA will 
respond to any ICR-related comments in the final rule.

C. Regulatory Flexibility Act (RFA)

    I certify that this proposed action would not have a significant 
economic impact on a substantial number of small entities under the 
RFA. The small entities subject to the requirements of this action are 
small businesses in the petroleum and natural gas industry. Small 
entities include small businesses, small organizations, and small 
governmental jurisdictions. The EPA has determined that some small 
entities are affected because their production processes emit GHGs that 
must be reported.
    In the implementation of the GHGRP, the EPA previously determined 
thresholds that reduced the number of small businesses reporting. The 
proposed revisions would not revise the threshold for existing subpart 
W reporters, therefore, we do not expect a significant number of small 
entities would be newly impacted under the proposed rule revisions.
    The proposed rule amendments predominantly apply to existing 
reporters and are amendments that would expand reporting to include new 
emission sources; add, remove, or refine emissions estimation 
methodologies to improve the accuracy and transparency of reported 
emission data; for the Onshore Natural Gas Production and Onshore 
Natural Gas Gathering and Boosting segments, revise reporting of 
emissions from a basin level to a site level; implement requirements to 
collect new or revised data; clarify or update provisions that have 
been misinterpreted; or streamline or simplify requirements by 
increasing flexibility for reporters or removing redundant 
requirements.
    The EPA conducted a small entity analysis that assessed the costs 
and impacts to small entities, including: (1) Revisions to add new 
emissions sources and expand the industry segments covered by existing 
emissions sources, (2) changes to improve existing monitoring or 
calculation methodologies, and (3) revisions to reporting and 
recordkeeping requirements for data provided to the program. The Agency 
anticipates that although a subset of small reporters (108-116) have a 
cost-to-revenue ratio (CRR) >1%, there are only a limited number (29-
30) of very small entities (1-19 employees) that would be likely to 
have significant impacts with CRR >3%, reflecting only a small 
proportion of the affected small entities (2.0%-5.2%). The mean CRR for 
these very small entities (1-19 employees) is estimated to be between 
1.55% (1.46-1.64%) and 2.06% (1.77-2.34%) based on the incremental 
costs for existing reporting entities and between 2.35% (2.16-2.55%) 
and 3.12% (2.59-3.66%) based on the costs for newly reporting 
entities.\135\ Details of this analysis are

[[Page 50373]]

presented in the memorandum, Assessment of Burden Impacts for Proposed 
Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas 
Systems, available in the docket for this rulemaking, Docket Id. No. 
EPA-HQ-OAR-2023-0234. Based on the results of this analysis, we have 
concluded that this proposed action is not likely to have a significant 
regulatory burden for a substantial number of directly regulated small 
entities and thus that this proposed action would not have a 
significant economic impact on a substantial number of small entities. 
The EPA continues to conduct significant outreach on the GHGRP and 
maintains an ``open door'' policy for stakeholders to help inform the 
EPA's understanding of key issues for the industries. We continue to be 
interested in the potential impacts of the proposed rule amendments on 
small entities and welcome comments on issues related to such impacts.
---------------------------------------------------------------------------

    \135\ The EPA conducted a multi-level analysis to estimate mean 
CRRs for multiple scenarios. The mean CRR and associated 95-percent 
confidence intervals provide an estimate of the range of cost-to-
sales ratios expected to apply to affected very small entities that 
would be expected in the total population.
---------------------------------------------------------------------------

D. Unfunded Mandates Reform Act (UMRA)

    This action does not contain an unfunded mandate of $100 million or 
more as described in UMRA, 2 U.S.C. 1531-1538, and does not 
significantly or uniquely affect small governments. The action in part 
implements mandate(s) specifically and explicitly set forth in CAA 
section 136.
    This proposed rule does not apply to governmental entities unless 
the government entity owns a facility in the petroleum and gas industry 
that directly emits GHG above part 98 applicability threshold levels. 
It does not impose any implementation responsibilities on state, local, 
or tribal governments and it is not expected to increase the cost of 
existing regulatory programs managed by those governments. Thus, the 
impact on governments affected by the proposed rule is expected to be 
minimal.
    However, consistent with the EPA's policy to promote communications 
between the EPA and state and local governments, the EPA sought 
comments from small governments concerning the regulatory requirements 
that might significantly or uniquely affect them in the development of 
this proposed rule. Specifically, the EPA previously published an RFI 
seeking public comment in a non-regulatory docket to collect responses 
to a range of questions related to the Methane Emissions Reduction 
Program, including subpart W revisions (see Docket Id. No. EPA-HQ-OAR-
2022-0875). The EPA received two comments from government entities 
supporting the use of empirical data and improvements to the accuracy 
of calculation methods under subpart W; these comments were considered 
during the development of the proposed rule. The EPA continues to be 
interested in the potential impacts of the proposed rule amendments on 
state, local, or tribal governments and welcomes comments on issues 
related to such impacts.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government. This 
proposed rule does not apply to governmental entities unless the 
government entity owns a facility in the petroleum and gas industry 
(e.g., an LDC) that directly emits GHG above part 98 applicability 
threshold levels. Therefore, the EPA anticipates relatively few state 
or local government facilities would be affected. However, consistent 
with the EPA's policy to promote communications between the EPA and 
state and local governments, the EPA specifically solicits comment on 
this proposed action from state and local officials.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action has tribal implications. However, it will neither 
impose substantial direct compliance costs on federally recognized 
Tribal governments, nor preempt tribal law. This regulation will apply 
directly to petroleum and natural gas facilities that may be owned by 
tribal governments that emit GHGs. However, it will generally only have 
tribal implications where the tribal entity owns a facility that 
directly emits GHGs above threshold levels; therefore, relatively few 
tribal facilities would be affected. Of the subpart W facilities 
currently reporting to the GHGRP in RY2021, we identified four 
facilities currently reporting to part 98 that are owned by one tribal 
parent company.
    In addition to tribes that would be directly impacted by the 
proposed revisions due to owning a facility subject to the proposed 
requirements, the EPA anticipates that tribes could be impacted in 
cases where facilities subject to the proposed revisions are located on 
Tribal land. In particular, the EPA reviewed the location of the 
production wells reported by facilities under the Onshore Petroleum and 
Natural Gas Production segment and found production wells reported 
under subpart W on lands associated with approximately 20 tribes. 
Therefore, although the EPA anticipates that only one tribe would be 
subject to the rule, the EPA has sought opportunities to provide 
information to tribal governments and representatives during rule 
development. On November 4, 2022, the EPA published an RFI seeking 
public comment on a range of questions related to the Methane Emissions 
Reduction Program, including subpart W revisions (see Docket Id. No. 
EPA-HQ-OAR-2022-0875). The EPA received one comment from a tribal 
entity relevant to subpart W. The commenter supported the use of 
empirical data and improvements to the accuracy of calculation methods 
under subpart W, including the use of advanced CH4 detection 
technologies for leak surveys at well sites and compressor stations; 
these comments were considered during the development of the proposed 
rule. Further, consistent with the EPA Policy on Consultation and 
Coordination with Indian Tribes, the EPA will engage in consultation 
with Tribal officials during the development of this action.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    The EPA interprets Executive Order 13045 as applying only to those 
regulatory actions that concern environmental health or safety risks 
that the EPA has reason to believe may disproportionately affect 
children, per the definition of ``covered regulatory action'' in 
section 2-202 of the Executive order. This action is not subject to 
Executive Order 13045 because it does not concern an environmental 
health risk or safety risk.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution, or Use

    This action is not a ``significant energy action'' because it is 
not likely to have a significant adverse effect on the supply, 
distribution or use of energy. The proposed amendments would expand 
reporting to include new emission sources; add, remove, or refine 
emissions estimation methodologies improve the accuracy and 
transparency of reported emission data; for the Onshore Natural Gas 
Production and Onshore Natural Gas Gathering and Boosting segments, 
revise reporting of

[[Page 50374]]

emissions from a basin level to a site level; implement requirements to 
collect new or revised data; clarify or update provisions that have 
been misinterpreted; or streamline or simplify requirements by 
increasing flexibility for reporters or removing redundant 
requirements. We are also proposing revisions that streamline or 
simplify requirements or alleviate burden through revision, 
simplification, or removal of certain calculation, monitoring, 
recordkeeping, or reporting requirements. In general, these changes 
would not have a significant, adverse effect on the supply, 
distribution, or use of energy. In addition, the EPA is proposing 
confidentiality determinations for new and revised data elements 
proposed in this rulemaking and for certain existing data elements for 
which a confidentiality determination has not previously been proposed. 
These proposed amendments and confidentiality determinations do not 
make any changes to the existing monitoring, calculation, and reporting 
requirements under subpart W and are not likely to have a significant 
adverse effect on the supply, distribution, or use of energy.

I. National Technology Transfer and Advancement Act and 1 CFR Part 51

    This action involves technical standards. For facilities that 
conduct a performance test to calculate combustion slip, the EPA is 
proposing that the performance test would be conducted in accordance 
with one of the test methods in proposed 40 CFR 98.234(i), which 
include EPA Methods 18 and 320 as well as an alternate method, ASTM 
D6348-12. The EPA is proposing to allow the use of the alternate method 
ASTM D6348-12, which is based on the use of a Fourier transform 
infrared (FTIR) spectrometer for the identification and quantification 
of multicomponent gaseous compounds, in lieu of EPA Method 320. The EPA 
currently allows for the use of an earlier version of this method, ASTM 
D6348-03, under other subparts of part 98, including subparts I 
(Electronics Manufacturing), V (Nitric Acid Production), and OO 
(Fluorinated Gas Production), for the quantification of other GHGs. 
Therefore, the EPA is proposing to allow ASTM D6348-12 to be used in 
subpart W to quantify CH4 emissions from combustion slip. 
Anyone may access the standards on the ASTM website (https://www.astm.org/) for additional information. These standards are 
available to everyone at a cost determined by the ASTM ($76). The ASTM 
also offers memberships or subscriptions that allow unlimited access to 
their methods. The cost of obtaining these methods is not a significant 
financial burden, making the methods reasonably available for 
reporters. The EPA will also make a copy of these documents available 
in hard copy at the appropriate EPA office (see the FOR FURTHER 
INFORMATION CONTACT section of this preamble for more information) for 
review purposes only.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    The EPA anticipates that the human health or environmental risk 
addressed by this action will not have potential disproportionately 
high and adverse human health or environmental effects on minority, 
low-income or indigenous populations as it does not directly affect the 
level of protection provided to human health or the environment because 
it is a rule addressing information collection and reporting 
procedures.
    However, the data that would be collected through this action would 
provide an important data resource for communities and the public to 
understand GHG emissions. Since facilities would be required to use 
prescribed calculation and monitoring methods, emissions data can be 
compared and analyzed, including locations of emissions sources. GHGRP 
data are easily accessible to the public via the EPA's online data 
publication tool, also known as FLIGHT at: https://ghgdata.epa.gov/ghgp/main.do. FLIGHT is designed for the general public and allows 
users to view and sort GHG data for every reporting year starting with 
2010 from over 8,000 entities in a variety of ways including by 
location, industrial sector, and type of GHG emitted. This powerful 
data resource provides a critical tool for communities to identify 
nearby sources of GHGs and provide information to state and local 
governments.
    The proposed revisions to part 98 include requirements for 
reporting of GHG data from additional emission sources (other large 
release events, nitrogen removal units, produced water tanks, crankcase 
venting, and mud degassing), improvements to emissions calculation 
methodologies, and collection of data to support verification of GHG 
emissions and transparency. The proposed disaggregation of reporting 
requirements within the Onshore Petroleum and Natural Gas Production 
and Onshore Petroleum and Natural Gas Gathering and Boosting industry 
segments to at least the well-pad and gathering boosting site-level, 
respectively, and the required reporting of geographical coordinates 
for other large release events would provide communities with more 
localized information on GHG emissions from these segments.
    Overall, these revisions would improve the quality of the data 
collected under the program and available to communities, if finalized.

K. Determination Under CAA Section 307(d)

    Pursuant to CAA section 307(d)(1)(V), the Administrator determines 
that this action is subject to the provisions of CAA section 307(d). 
Section 307(d)(1)(V) of the CAA provides that the provisions of CAA 
section 307(d) apply to ``such other actions as the Administrator may 
determine.''

List of Subjects in 40 CFR Part 98

    Environmental protection, Greenhouse gases, Incorporation by 
reference, Reporting and recordkeeping requirements.

Michael S. Regan,
Administrator.

    For the reasons stated in the preamble, the Environmental 
Protection Agency proposes to amend title 40, chapter I, of the Code of 
Federal Regulations as follows:

PART 98--MANDATORY GREENHOUSE GAS REPORTING

0
1. The authority citation for part 98 continues to read as follows:

    Authority:  42 U.S.C. 7401-7671q.

Subpart A--General Provision

0
2. Amend Sec.  98.1 by revising paragraph (c) to read as follows:


Sec.  98.1  Purpose and scope.

* * * * *
    (c) For facilities required to report under onshore petroleum and 
natural gas production under subpart W of this part, the terms Owner 
and Operator used in this subpart have the same definition as Onshore 
petroleum and natural gas production owner or operator, as defined in 
Sec.  98.238. For facilities required to report under onshore petroleum 
and natural gas gathering and boosting under subpart W of this part, 
the terms Owner and Operator used in this subpart have the same 
definition as Gathering and boosting system owner or operator, as 
defined in Sec.  98.238. For facilities required to report under 
onshore natural gas transmission pipeline under subpart W of this part, 
the terms Owner and

[[Page 50375]]

Operator used in this subpart have the same definition as Onshore 
natural gas transmission pipeline owner or operator, as defined in 
Sec.  98.238.
0
3. Amend Sec.  98.2 by revising paragraph (i)(3) to read as follows:


Sec.  98.2  Who must report?

* * * * *
    (i) * * *
    (3) If the operations of a facility or supplier are changed such 
that all applicable processes and operations subject to paragraphs 
(a)(1) through (4) of this section cease to operate, then the owner or 
operator may discontinue complying with this part for the reporting 
years following the year in which cessation of such operations occurs, 
provided that the owner or operator submits a notification to the 
Administrator that announces the cessation of reporting and certifies 
to the closure of all applicable processes and operations no later than 
March 31 of the year following such changes. If one or more processes 
or operations subject to paragraphs (a)(1) through (4) of this section 
at a facility or supplier cease to operate, but not all applicable 
processes or operations cease to operate, then the owner or operator is 
exempt from reporting for any such processes or operations in the 
reporting years following the reporting year in which cessation of the 
process or operation occurs, provided that the owner or operator 
submits a notification to the Administrator that announces the 
cessation of reporting for the process or operation no later than March 
31 following the first reporting year in which the process or operation 
has ceased for an entire reporting year. Cessation of operations in the 
context of underground coal mines includes, but is not limited to, 
abandoning and sealing the facility. This paragraph (i)(3) does not 
apply to seasonal or other temporary cessation of operations. This 
paragraph (i)(3) does not apply to the municipal solid waste landfills 
source category (subpart HH of this part), or the industrial waste 
landfills source category (subpart TT of this part). This paragraph 
(i)(3) does not apply when there is a change in the owner or operator 
for facilities in industry segments with a unique definition of 
facility as defined in Sec.  98.238 of the petroleum and natural gas 
systems source category (subpart W of this part), unless the changes 
result in permanent cessation of all applicable processes and 
operations. The owner or operator must resume reporting for any future 
calendar year during which any of the GHG-emitting processes or 
operations resume operation.
* * * * *
0
4. Amend Sec.  98.4 by revising the first sentence of paragraph (h) and 
adding paragraph (n) to read as follows:


Sec.  98.4  Authorization and responsibilities of the designated 
representative.

* * * * *
    (h) Changes in owners and operators. Except as provided in 
paragraph (n) of this section, in the event an owner or operator of the 
facility or supplier is not included in the list of owners and 
operators in the certificate of representation under this section for 
the facility or supplier, such owner or operator shall be deemed to be 
subject to and bound by the certificate of representation, the 
representations, actions, inactions, and submissions of the designated 
representative and any alternate designated representative of the 
facility or supplier, as if the owner or operator were included in such 
list. * * *
* * * * *
    (n) Alternative provisions for changes in owners and operators for 
industry segments with a unique definition of facility as defined in 
Sec.  98.238. When there is a change to the owner or operator of a 
facility required to report under the onshore petroleum and natural gas 
production, natural gas distribution, onshore petroleum and natural gas 
gathering and boosting, or onshore natural gas transmission pipeline 
industry segments of subpart W of this part, or a change to the owner 
or operator for some emission sources from the facility in one of these 
industry segments, the provisions specified in paragraphs (n)(1) 
through (4) of this section apply for the respective type of change in 
owner or operator. The provisions specified in paragraph (n)(5) of this 
section apply to the types of change in owner or operator specified in 
paragraphs (n)(3) and (4) of this section.
    (1) If the entire facility is acquired by an owner or operator that 
does not already have a reporting facility in the same industry segment 
and basin (for onshore petroleum and natural gas production or onshore 
petroleum and natural gas gathering and boosting) or state (for natural 
gas distribution), then within 90 days after the change in the owner or 
operator, the designated representative or any alternate designated 
representative shall submit a certificate of representation that is 
complete under this section. If the new owner or operator already had 
emission sources specified in Sec.  98.232(c), (i), (j) or (m), as 
applicable, prior to the acquisition in the same basin (for onshore 
petroleum and natural gas production or onshore petroleum and natural 
gas gathering and boosting) or state (for natural gas distribution) as 
the acquired facility but had not previously met the applicability 
requirements in Sec. Sec.  98.2(a) and 98.231, then per the applicable 
definition of facility in Sec.  98.238, the previously owned applicable 
emission sources must be included in the acquired facility. The new 
owner or operator and the new designated representative shall be 
responsible for submitting the annual report for the facility for the 
entire reporting year beginning with the reporting year in which the 
acquisition occurred. The new owner or operator and the new designated 
representative shall also be responsible for submitting any required 
annual GHG report revisions required by Sec.  98.3(h) for reporting 
years prior to the reporting year in which the acquisition occurred.
    (2) If the entire facility is acquired by an owner or operator that 
already has a reporting facility in the same industry segment and basin 
(for onshore petroleum and natural gas production or onshore petroleum 
and natural gas gathering and boosting) or state (for natural gas 
distribution), the new owner or operator shall merge the acquired 
facility with their existing facility for purposes of the annual GHG 
report. Within 90 days after the change in the owner or operator, the 
designated representative or any alternate designated representative 
shall submit a certificate of representation that is complete under 
this section to reflect the new owner or operator for the acquired 
facility. The owner or operator shall also follow the provisions of 
Sec.  98.2(i)(6) to notify EPA that the acquired facility will 
discontinue reporting and shall provide the e-GGRT identification 
number of the merged, or reconstituted, facility. The owner or operator 
of the merged facility shall be responsible for submitting the annual 
report for the merged facility for the entire reporting year beginning 
with the reporting year in which the acquisition occurred. The new 
owner or operator and the new designated representative shall also be 
responsible for submitting any required annual GHG report revisions 
required by Sec.  98.3(h) for reporting years prior to the reporting 
year in which the acquisition occurred.
    (3) If only some emission sources from the facility are acquired by 
one or more new owners or operators, the existing owner or operator 
(i.e., the owner or operator of the portion of the facility that is not 
sold) shall continue to report under subpart W of this part for the 
retained emission sources unless

[[Page 50376]]

and until that facility meets one of the criteria in Sec.  98.2(i). 
Each owner or operator that acquires emission sources from the facility 
must account for those acquired emission sources according to paragraph 
(n)(3)(i) or (ii) of this section, as applicable.
    (i) If the purchasing owner or operator that acquires only some of 
the emission sources from the existing facility does not already have a 
reporting facility in the same industry segment and basin (for onshore 
petroleum and natural gas production or onshore petroleum and natural 
gas gathering and boosting) or state (for natural gas distribution), 
the purchasing owner or operator shall begin reporting as a new 
facility. The new facility must include the acquired emission sources 
specified in Sec.  98.232(c), (i), (j), or (m), as applicable, and any 
emission sources the purchasing owner or operator already owned in the 
same industry segment and basin (for onshore petroleum and natural gas 
production or onshore petroleum and natural gas gathering and boosting) 
or state (for natural gas distribution). The designated representative 
for the new facility must be selected by the purchasing owner or 
operator according to the schedule and procedure specified in 
paragraphs (b) through (d) of this section. The purchasing owner or 
operator shall be responsible for submitting the annual report for the 
new facility for the entire reporting year beginning with the reporting 
year in which the acquisition occurred. The purchasing owner or 
operator shall continue to report under subpart W of this part for the 
new facility unless and until that facility meets one of the criteria 
in Sec.  98.2(i).
    (ii) If the purchasing owner or operator that acquires only some of 
the emission sources from the existing facility already has a reporting 
facility in the same industry segment and basin (for onshore petroleum 
and natural gas production or onshore petroleum and natural gas 
gathering and boosting) or state (for natural gas distribution), then 
per the applicable definition of facility in Sec.  98.238, the 
purchasing owner or operator must add the acquired emission sources 
specified in Sec.  98.232(c), (i), (j), or (m), as applicable, to their 
existing facility for purposes of reporting under subpart W. The 
purchasing owner or operator shall be responsible for submitting the 
annual report for the entire facility, including the acquired emission 
sources, for the entire reporting year beginning with the reporting 
year in which the acquisition occurred.
    (4) If all the emission sources from a reporting facility are sold 
to multiple owners or operators within the same reporting year, such 
that the current owner or operator of the existing facility does not 
retain any of the emission sources, then the current owner or operator 
of the existing facility shall notify EPA within 90 days of the last 
transaction that all of the facility's emission sources were acquired 
by multiple purchasers, including the identity of the purchasers. Each 
owner or operator that acquires emission sources from a facility shall 
account for those sources according to paragraph (n)(3)(i) or (ii) of 
this section, as applicable.
    (5) Within 90 days of a transaction that results in a change to the 
owner or operator of a facility as described in paragraph (n)(3) or (4) 
of this section, the owners or operators involved in that transaction 
shall select a historic reporting representative who will be 
responsible for revisions to annual GHG reports under Sec.  98.3(h) for 
reporting years prior to the reporting year in which the transaction 
occurred. The historic reporting representative shall be an individual 
selected by an agreement binding on each of the owners and operators 
involved in the transaction, following the provisions of paragraph (b) 
of this section. The provisions of paragraphs (b), (c), (e), and (g) of 
this section apply to the historic reporting representative by 
substituting the term ``historic reporting representative'' for 
``designated representative.'' The provisions of paragraph (i) of this 
section apply to the historic reporting representative by adding the 
term ``historic reporting representative'' to instances of ``the 
designated representative and any alternate designated 
representative.''
0
5. Amend Sec.  98.6 by revising the definitions for ``Dehydrator'', 
``Dehydrator vent emissions'', ``Desiccant'', and ``Vapor recovery 
system'' to read as follows:


Sec.  98.6  Definitions.

* * * * *
    Dehydrator means a device in which a liquid absorbent (including 
ethylene glycol, diethylene glycol, or triethylene glycol) or desiccant 
directly contacts a natural gas stream to remove water vapor.
    Dehydrator vent emissions means natural gas and CO2 released from a 
natural gas dehydrator system absorbent (typically glycol) regenerator 
still vent and, if present, a flash tank separator, to the atmosphere, 
flare, regenerator fire-box/fire tubes, or vapor recovery system. 
Emissions include stripping natural gas and motive natural gas used in 
absorbent circulation pumps.
* * * * *
    Desiccant means a material used in solid-bed dehydrators to remove 
water from raw natural gas by adsorption or absorption. Desiccants 
include, but are not limited to, molecular sieves, activated alumina, 
pelletized calcium chloride, lithium chloride and granular silica gel 
material. Wet natural gas is passed through a bed of the granular or 
pelletized solid adsorbent or absorbent in these dehydrators. As the 
wet gas contacts the surface of the particles of desiccant material, 
water is adsorbed on the surface or absorbed and dissolves the surface 
of these desiccant particles. Passing through the entire desiccant bed, 
almost all of the water is adsorbed onto or absorbed into the desiccant 
material, leaving the dry gas to exit the contactor.
* * * * *
    Vapor recovery system means any equipment located at the source of 
potential gas emissions to the atmosphere or to a flare, that is 
composed of piping, connections, and, if necessary, flow-inducing 
devices, and that is used for routing the gas back into the process as 
a product and/or fuel. For purposes of Sec.  98.233, routing emissions 
from a dehydrator regenerator still vent or flash tank separator vent 
to a regenerator fire-box/fire tubes does not meet the definition of 
vapor recovery system.
* * * * *
0
6. Amend Sec.  98.7 by adding paragraph (e)(53) to read as follows:


Sec.  98.7  What standardized methods are incorporated by reference 
into this part?

* * * * *
    (e) * * *
    (53) ASTM D6348-12 Standard Test Method for Determination of 
Gaseous Compounds by Extractive Direct Interface Fourier Transform 
Infrared (FTIR) Spectroscopy, IBR approved for Sec.  98.234(j).
* * * * *
    Subpart C--General Stationary Fuel Combustion Sources
0
7. Amend Sec.  98.33 by revising parameter ``EF'' of Equation C-8 in 
paragraph (c)(1) introductory text, Equation C-8a in paragraph 
(c)(1)(i), Equation C-8b in paragraph (c)(1)(ii), Equation C-9a in 
paragraph (c)(2), and Equation C-10 in paragraph (c)(4) introductory 
text to read as follows:


Sec.  98.33  Calculating GHG emissions.

* * * * *
    (c) * * *
    (1) * * *


[[Page 50377]]


Where: * * *

EF = Fuel-specific default emission factor for CH4 or 
N2O, from Table C-2 of this subpart (kg CH4 or 
N2O per mmBtu), except for natural gas-fired 
reciprocating internal combustion engines and gas turbines at 
facilities subject to subpart W of this part, which must use a 
CH4 emission factor determined in accordance with Sec.  
98.233(z)(4).
* * * * *

    (i) * * *

Where: * * *

EF = Fuel-specific default emission factor for CH4 or 
N2O, from Table C-2 of this subpart (kg CH4 or 
N2O per mmBtu), except for natural gas-fired 
reciprocating internal combustion engines and gas turbines at 
facilities subject to subpart W of this part, which must use a 
CH4 emission factor determined in accordance with Sec.  
98.233(z)(4).
* * * * *

    (ii) * * *

Where: * * *

EF = Fuel-specific default emission factor for CH4 or 
N2O, from Table C-2 of this subpart (kg CH4 or 
N2O per mmBtu), except for natural gas-fired 
reciprocating internal combustion engines and gas turbines at 
facilities subject to subpart W of this part, which must use a 
CH4 emission factor determined in accordance with Sec.  
98.233(z)(4).
* * * * *

    (2) * * *

Where: * * *

EF = Fuel-specific default emission factor for CH4 or 
N2O, from Table C-2 of this subpart (kg CH4 or 
N2O per mmBtu), except for natural gas-fired 
reciprocating internal combustion engines and gas turbines at 
facilities subject to subpart W of this part, which must use a 
CH4 emission factor determined in accordance with Sec.  
98.233(z)(4).
* * * * *

    (4) * * *

Where: * * *

EF = Fuel-specific default emission factor for CH4 or 
N2O, from Table C-2 of this subpart (kg CH4 or 
N2O per mmBtu), except for natural gas-fired 
reciprocating internal combustion engines and gas turbines at 
facilities subject to subpart W of this part, which must use a 
CH4 emission factor determined in accordance with Sec.  
98.233(z)(4).
* * * * *
0
8. Amend Sec.  98.36 by adding paragraphs (b)(13), (c)(1)(xiii), and 
(c)(3)(xiii) to read as follows:


Sec.  98.36  Data reporting requirements.

* * * * *
    (b) * * *
    (13) For natural gas-fired reciprocating internal combustion 
engines or gas turbines at facilities subject to subpart W of this 
part, which must use a CH4 emission factor determined in 
accordance with Sec.  98.233(z)(4), you must also report:
    (i) Type of equipment: two-stroke lean-burn reciprocating internal 
combustion engine, four-stroke lean-burn reciprocating internal 
combustion engine, four-stroke rich-burn reciprocating internal 
combustion engine, or gas turbine.
    (ii) Method by which the CH4 emission factor was 
determined: performance test, manufacturer data, or default emission 
factor.
    (iii) Value of the CH4 emission factor.
    (c) * * *
    (1) * * *
    (xiii) For natural gas-fired reciprocating internal combustion 
engines or gas turbines at facilities subject to subpart W of this 
part, which must use a CH4 emission factor determined in 
accordance with Sec.  98.233(z)(4), you must report the equipment type 
(i.e., two-stroke lean-burn reciprocating internal combustion engine, 
four-stroke lean-burn reciprocating internal combustion engine, four-
stroke rich-burn reciprocating internal combustion engine, and gas 
turbine), the method by which the CH4 emission factor was 
determined (i.e., performance test, manufacturer data, or default 
emission factor), and the average value of the CH4 emission 
factor.
* * * * *
    (3) * * *
    (xiii) For natural gas-fired reciprocating internal combustion 
engines or gas turbines at facilities subject to subpart W of this 
part, which must use a CH4 emission factor determined in 
accordance with Sec.  98.233(z)(4), you must report the equipment type 
(i.e., two-stroke lean-burn reciprocating internal combustion engine, 
four-stroke lean-burn reciprocating internal combustion engine, four-
stroke rich-burn reciprocating internal combustion engine, and gas 
turbine) the method by which the CH4 emission factor was 
determined (i.e., performance test, manufacturer data, or default 
emission factor), and the average value of the CH4 emission 
factor.
* * * * *
0
9. Amend table C-2 to subpart C of part 98 by revising the entry 
``Natural Gas'' to read as follows:

 Table C-2 to Subpart C of Part 98--Default CH4 and N2O Emission Factors
                        for Various Types of Fuel
------------------------------------------------------------------------
                                      Default CH4         Default N2O
            Fuel type              emission  factor    emission  factor
                                    (kg CH4/mmBtu)      (kg N2O/mmBtu)
------------------------------------------------------------------------
 
                                * * * * *
Natural Gas 1...................  1.0 x 10-03.......  1.0 x 10-04.
 
                                * * * * *
------------------------------------------------------------------------
* * * * *
1 Reporters subject to subpart W of this part may only use the default
  CH4 emission factor for natural gas-fired combustion units that are
  not reciprocating internal combustion engines or gas turbines. For
  natural gas-fired reciprocating internal combustion engines or gas
  turbines, at facilities subject to subpart W of this part, reporters
  must use a CH4 emission factor determined in accordance with Sec.
  98.233(z)(4).

Subpart W--Petroleum and Natural Gas Systems

0
10. Amend Sec.  98.230 by revising paragraphs (a)(2), (3) and (9) to 
read as follows:


Sec.  98.230  Definition of the source category.

    (a) * * *
    (2) Onshore petroleum and natural gas production. Onshore petroleum 
and natural gas production means all equipment on a single well-pad or 
associated with a single well-pad (including but not limited to 
compressors, generators, dehydrators, storage vessels, engines, 
boilers, heaters, flares, separation and processing equipment, and 
portable non-self-propelled equipment, which includes well drilling and 
completion equipment, workover equipment, and leased, rented or 
contracted equipment) used in the production, extraction, recovery, 
lifting, stabilization, separation or treating of petroleum and/or 
natural gas (including condensate). This equipment also includes 
associated storage or measurement vessels, all petroleum and natural 
gas production equipment located on islands, artificial islands, or 
structures connected by a causeway to land, an island, or an artificial 
island. Onshore petroleum and natural gas production also means all 
equipment on or associated with a single enhanced oil recovery (EOR) 
well-pad using CO2 or natural gas injection.
    (3) Onshore natural gas processing. Onshore natural gas processing 
means the forced extraction of natural gas

[[Page 50378]]

liquids (NGLs) from field gas, fractionation of mixed NGLs to natural 
gas products, or both. Natural gas processing does not include a Joule-
Thomson valve, a dew point depression valve, or an isolated or 
standalone Joule-Thomson skid. This segment also includes all residue 
gas compression equipment owned or operated by the natural gas 
processing plant.
* * * * *
    (9) Onshore petroleum and natural gas gathering and boosting. 
Onshore petroleum and natural gas gathering and boosting means 
gathering pipelines and other equipment used to collect petroleum and/
or natural gas from onshore production gas or oil wells and used to 
compress, dehydrate, sweeten, or transport the petroleum and/or natural 
gas to a natural gas processing facility, a natural gas transmission 
pipeline or to a natural gas distribution pipeline. Gathering and 
boosting equipment includes, but is not limited to gathering pipelines, 
separators, compressors, acid gas removal units, dehydrators, pneumatic 
devices/pumps, storage vessels, engines, boilers, heaters, and flares. 
Gathering and boosting equipment does not include equipment reported 
under any other industry segment defined in this section. Gathering 
pipelines operating on a vacuum and gathering pipelines with a GOR less 
than 300 standard cubic feet per stock tank barrel (scf/STB) are not 
included in this industry segment (oil here refers to hydrocarbon 
liquids of all API gravities).
* * * * *
0
11. Amend Sec.  98.232 by:
0
a. Revising paragraphs (a), (b) and (c)(2), (10), (17), and (21);
0
b. Adding paragraphs (c)(23) through (25);
0
c. Revising paragraphs (d)(5) and (7);
0
d. Adding paragraphs (d)(8) through (11);
0
e. Revising paragraphs (e)(3) and (8);
0
f. Adding paragraphs (e)(9) through (11);
0
g. Revising paragraphs (f)(6) and (8);
0
h. Adding paragraphs (f)(9) through (13);
0
i. Revising paragraphs (g)(6) and (7);
0
j. Adding paragraphs (g)(8) through (11);
0
k. Revising paragraphs (h)(7) and (8);
0
l. Adding paragraphs (h)(9) through (11) and (i)(8) through (11);
0
m. Revising paragraphs (j)(3), (6), and (10);
0
n. Adding paragraphs (j)(13) and (14);
0
o. Revising paragraph (m); and
0
p. Adding paragraph (n).
    The revisions and additions read as follows:


Sec.  98.232  GHGs to report.

    (a) You must report CO2, CH4, and 
N2O emissions from each industry segment specified in 
paragraphs (b) through (j) and (m) of this section, CO2, 
CH4, and N2O emissions from each flare as 
specified in paragraphs (b) through (j) of this section, and stationary 
and portable combustion emissions as applicable as specified in 
paragraph (k) of this section. You must also report the information 
specified in paragraphs (l) and (n) of this section, as applicable.
    (b) For offshore petroleum and natural gas production, report 
CO2, CH4, and N2O emissions from 
equipment leaks, vented emission, and flare emission source types as 
identified by Bureau of Ocean Energy Management (BOEM) in compliance 
with 30 CFR 550.302 through 304 and CO2 and CH4 
emissions from other large release events. Offshore platforms do not 
need to report portable emissions.
    (c) * * *
    (2) Blowdown vent stacks.
* * * * *
    (10) Hydrocarbon liquids and produced water storage tank emissions.
* * * * *
    (17) Acid gas removal unit vents and nitrogen removal unit vents.
* * * * *
    (21) Equipment leaks listed in paragraph (c)(21)(i) or (ii) of this 
section, as applicable:
    (i) Equipment leaks from components including valves, connectors, 
open ended lines, pressure relief valves, pumps, flanges, and other 
components (such as instruments, loading arms, stuffing boxes, 
compressor seals, dump lever arms, and breather caps, but does not 
include components listed in paragraph (c)(11) or (19) of this section, 
and it does not include thief hatches or other openings on a storage 
vessel).
    (ii) Equipment leaks from major equipment including wellheads, 
separators, meters/piping, compressors, dehydrators, heaters, and 
storage vessels.
* * * * *
    (23) Other large release events.
    (24) Drilling mud degassing.
    (25) Crankcase vents.
    (d) * * *
    (5) Acid gas removal unit vents and nitrogen removal unit vents.
* * * * *
    (7) Equipment leaks from valves, connectors, open ended lines, 
pressure relief valves, and meters, and equipment leaks from all other 
components in gas service (not including thief hatches or other 
openings on storage vessels) that either are subject to equipment leak 
standards for onshore natural gas processing plants in Sec.  60.5400b 
of this chapter, or an applicable approved state plan or applicable 
Federal plan in part 62 of this chapter or that you elect to survey 
using a leak detection method described in Sec.  98.234(a).
    (8) Natural gas pneumatic device venting.
    (9) Other large release events.
    (10) Hydrocarbon liquids and produced water storage tank emissions.
    (11) Crankcase vents.
    (e) * * *
    (3) Condensate storage tanks.
* * * * *
    (8) Equipment leaks from all other components that are not listed 
in paragraph (e)(1), (2), or (7) of this section and either are subject 
to the well site or compressor station fugitive emissions standards in 
Sec.  60.5397a of this chapter, the fugitive emissions standards for 
well sites, centralized production facilities, and compressor stations 
in Sec.  60.5397b of this chapter, or an applicable approved state plan 
or applicable Federal plan in part 62 of this chapter, or that you 
elect to survey using a leak detection method described in Sec.  
98.234(a). The other components subject to this paragraph (e)(8) also 
do not include thief hatches or other openings on a storage vessel.
    (9) Other large release events.
    (10) Dehydrator vents.
    (11) Crankcase vents.
    (f) * * *
    (6) Equipment leaks from all other components that are associated 
with storage stations, are not listed in paragraph (f)(1), (2), or (5) 
of this section, and either are subject to the well site or compressor 
station fugitive emissions standards in Sec.  60.5397a of this chapter, 
the fugitive emissions standards for well sites, centralized production 
facilities, and compressor stations in Sec.  60.5397b of this chapter, 
or an applicable approved state plan or applicable Federal plan in part 
62 of this chapter or that you elect to survey using a leak detection 
method described in Sec.  98.234(a). The other components subject to 
this paragraph (f)(6) do not include thief hatches or other openings on 
a storage vessel.
* * * * *
    (8) Equipment leaks from all other components that are associated 
with storage wellheads, are not listed in paragraph (f)(1), (2), or (7) 
of this section, and either are subject to the well site or compressor 
station fugitive emissions standards in Sec.  60.5397a of this chapter, 
the fugitive emissions standards for well sites, centralized production 
facilities, and compressor stations in Sec.  60.5397b of this chapter, 
or

[[Page 50379]]

an applicable approved state plan or applicable Federal plan in part 62 
of this chapter or that you elect to survey using a leak detection 
method described in Sec.  98.234(a).
    (9) Other large release events.
    (10) Dehydrator vents.
    (11) Blowdown vent stacks.
    (12) Condensate storage tanks.
    (13) Crankcase vents.
    (g) * * *
    (6) Equipment leaks from all components in gas service that are 
associated with a vapor recovery compressor, are not listed in 
paragraph (g)(1) or (2) of this section, and either are subject to the 
well site or compressor station fugitive emissions standards in Sec.  
60.5397a of this chapter, the fugitive emissions standards for well 
sites, centralized production facilities, and compressor stations in 
Sec.  60.5397b of this chapter, or an applicable approved state plan or 
applicable Federal plan in part 62 of this chapter or that you elect to 
survey using a leak detection method described in Sec.  98.234(a).
    (7) Equipment leaks from all components in gas service that are not 
associated with a vapor recovery compressor, are not listed in 
paragraph (g)(1) or (2) of this section, and either are subject to the 
well site or compressor station fugitive emissions standards in Sec.  
60.5397a of this chapter, the fugitive emissions standards for well 
sites, centralized production facilities, and compressor stations in 
Sec.  60.5397b of this chapter, or an applicable approved state plan or 
applicable Federal plan in part 62 of this chapter or that you elect to 
survey using a leak detection method described in Sec.  98.234(a).
    (8) Other large release events.
    (9) Blowdown vent stacks.
    (10) Acid gas removal unit vents and nitrogen removal unit vents.
    (11) Crankcase vents.
    (h) * * *
    (7) Equipment leaks from all components in gas service that are 
associated with a vapor recovery compressor, are not listed in 
paragraph (h)(1) or (2) of this section, and either are subject to the 
well site or compressor station fugitive emissions standards in Sec.  
60.5397a of this chapter, the fugitive emissions standards for well 
sites, centralized production facilities, and compressor stations in 
Sec.  60.5397b of this chapter, or an applicable approved state plan or 
applicable Federal plan in part 62 of this chapter or that you elect to 
survey using a leak detection method described in Sec.  98.234(a).
    (8) Equipment leaks from all components in gas service that are not 
associated with a vapor recovery compressor, are not listed in 
paragraph (h)(1) or (2) of this section, and either are subject to the 
well site or compressor station fugitive emissions standards in Sec.  
60.5397a of this chapter, the fugitive emissions standards for well 
sites, centralized production facilities, and compressor stations in 
Sec.  60.5397b of this chapter, or an applicable approved state plan or 
applicable Federal plan in part 62 of this chapter or that you elect to 
survey using a leak detection method described in Sec.  98.234(a).
    (9) Acid gas removal unit vents and nitrogen removal unit vents.
    (10) Other large release events.
    (11) Crankcase vents.
    (i) * * *
    (8) Other large release events.
    (9) Blowdown vent stacks.
    (10) Natural gas pneumatic device venting.
    (11) Crankcase vents.
    (j) * * *
    (3) Acid gas removal unit vents and nitrogen removal unit vents.
* * * * *
    (6) Hydrocarbon liquids and produced water storage tank emissions.
* * * * *
    (10) Equipment leaks listed in paragraph (j)(10)(i) or (ii) of this 
section, as applicable:
    (i) Equipment leaks from components including valves, connectors, 
open ended lines, pressure relief valves, pumps, flanges, and other 
components (such as instruments, loading arms, stuffing boxes, 
compressor seals, dump lever arms, and breather caps, but does not 
include components in paragraph (j)(8) or (9) of this section, and it 
does not include thief hatches or other openings on a storage vessel).
    (ii) Equipment leaks from major equipment including wellheads, 
separators, meters/piping, compressors, dehydrators, heaters, and 
storage vessels.
* * * * *
    (13) Other large release events.
    (14) Crankcase vents.
* * * * *
    (m) For onshore natural gas transmission pipeline, report 
CO2, CH4, and N2O emissions from the 
following source types:
    (1) Blowdown vent stacks.
    (2) Other large release events.
    (3) Equipment leaks at transmission company interconnect metering-
regulating stations.
    (4) Equipment leaks at farm tap and/or direct sale metering-
regulating stations.
    (5) Transmission pipeline equipment leaks.
    (n) For all facilities meeting the applicability provisions under 
Sec.  98.2 and, if applicable, Sec.  98.231, report the information 
required under subpart B of this part (Metered, Non-fuel, Purchased 
Energy Consumption by Stationary Sources).
0
12. Amend Sec.  98.233 by:
0
a. Revising paragraphs (a), (c), (d), (e) introductory text, (e)(1) 
introductory text, (e)(1)(i), (ii), (x), and (xi), and (e)(2) 
introductory text;
0
b. Revising parameter ``Count'' of Equation W-5 in paragraph (e)(2);
0
c. Revising paragraph (e)(3) introductory text;
0
d. Removing paragraph (e)(4);
0
e. Redesignating paragraphs (e)(5) and (6) as (e)(4) and (5), 
respectively;
0
f. Revising newly redesignated paragraphs (e)(4) and (5) and paragraphs 
(f), (g) introductory text, and (g)(1) introductory text;
0
g. Removing and reserving paragraph (g)(1)(ii);
0
h. Revising parameter ``FRs,p'' and ``N'' of Equation W-12A 
in paragraph (g)(1)(iii);
0
i. Revising parameters ``FRi,p'' and ``N'' of Equation W-12B 
in paragraph (g)(1)(iv);
0
j. Removing paragraph (g)(4);
0
k. Revising paragraph (h) introductory text;
0
l. Removing and reserving paragraph (h)(2);
0
m. Revising paragraph (i)(2) introductory text;
0
n. Revising parameters ``Ta'' and ``Pa'' of 
Equation W-14A in paragraph (i)(2)(i);
0
o. Revising parameters ``Ta,p'', ``Pa,b,p'', and 
``Pa,e,p'' of Equation W-14B in paragraph (i)(2)(i);
0
p. Adding paragraph (i)(2)(iv);
0
q. Revising paragraphs (j) and (k) introductory text,
0
r. Removing paragraph (k)(5);
0
s. Revising paragraphs (l) introductory text and (l)(3);
0
t. Removing paragraph (l)(6);
0
u. Revising paragraphs (m) introductory text and (m)(3);
0
v. Removing paragraph (m)(5);
0
w. Revising paragraphs (n), (o) introductory text, (o)(1)(i) 
introductory text, (o)(1)(i)(A) through (C), (o)(2) introductory text, 
(o)(2)(i) introductory text, and (o)(2)(ii);
0
x. Adding paragraph (o)(2)(iii);
0
y. Removing and reserving paragraph (o)(4)(ii)(D);
0
z. Revising paragraphs (o)(4)(ii)(E) and (o)(6)(i) introductory text;
0
aa. Revising parameter ``m'' of Equation W-21 in paragraph (o)(6)(i);
0
bb. Revising paragraph (o)(6)(ii) introductory text;
0
cc. Revising parameter ``m'' of Equation W-22 in paragraph (o)(6)(ii);
0
dd. Revising paragraph (o)(6)(iii) introductory text;

[[Page 50380]]

0
ee. Revising parameter ``m'' of Equation W-23 in paragraph (o)(6)(iii);
0
ff. Revising parameter ``Tg'' of Equation W-24B in paragraph 
(o)(8);
0
gg. Revising paragraph (o)(10);
0
hh. Removing paragraph (o)(12);
0
ii. Revising paragraphs (p) introductory text, (p)(1)(i), (p)(2) 
introductory text, (p)(2)(ii) introductory text, (p)(2)(ii)(C), 
(p)(2)(iii)(A), and (p)(4)(ii)(C);
0
jj. Removing and reserving paragraph (p)(4)(ii)(D);
0
kk. Revising paragraphs (p)(4)(ii)(E), (p)(6)(ii) introductory text, 
and (p)(6)(iii) introductory text,
0
ll. Revising parameter ``Tg'' of Equation W-29B in paragraph 
(p)(8);
0
mm. Revising paragraph (p)(10);
0
nn. Removing paragraph (p)(12);
0
oo. Revising paragraphs (q) introductory text, (q)(1), (q)(2) 
introductory text, (q)(2)(i), and (q)(2)(iii) through (xi);
0
pp. Adding paragraphs (q)(3) and (4);
0
qq. Revising paragraphs (r) and (s);
0
rr. In paragraph (t)(2), revising parameter ``Za'' of 
Equation W-34, and removing the undesignated paragraph following the 
parameters of Equation W-34;
0
ss. Revising paragraphs (u)(2)(ii), (y), and (z);
0
tt. Adding and reserving paragraphs (aa) through (cc); and
0
uu. Adding paragraphs (dd) and (ee).
    The revisions and additions read as follows:


Sec.  98.233  Calculating GHG emissions.

* * * * *
    (a) Natural gas pneumatic device venting. For all natural gas 
pneumatic devices at onshore petroleum and natural gas production 
facilities, onshore petroleum and natural gas gathering and boosting 
facilities, onshore natural gas processing facilities, onshore natural 
gas transmission compression facilities, underground natural gas 
storage facilities, and natural gas distribution facilities, use the 
applicable provisions as specified in this paragraph (a) of this 
section to calculate CH4 and CO2 emissions from 
natural gas pneumatic device venting. If you have a flow meter on the 
natural gas supply line dedicated to any one or combination of natural 
gas pneumatic devices or natural gas driven pneumatic pumps vented 
directly to the atmosphere for any portion of the year, you must use 
the method specified in paragraph (a)(1) of this section to calculate 
CH4 and CO2 emissions from those devices. For 
natural gas pneumatic devices vented directly to the atmosphere for 
which the natural gas supply rate is not measured, use the applicable 
methods specified in paragraphs (a)(2) through (6) of this section to 
calculate CH4 and CO2 emissions. For natural gas 
pneumatic devices that are routed to flares, combustion, or vapor 
recovery systems, use the applicable provisions specified in paragraphs 
(a)(7) of this section.
    (1) Calculation Method 1. If you have or elect to install a flow 
meter on the natural gas supply line dedicated to any one or 
combination of natural gas pneumatic devices and natural gas driven 
pneumatic pumps that are vented directly to the atmosphere, you must 
use the applicable methods specified in paragraph (a)(1)(i) through 
(iv) of this section to calculate CH4 and CO2 
emissions from those devices.
    (i) For volumetric flow monitors:
    (A) Determine the cumulative annual volumetric flow, in standard 
cubic feet, as measured by the flow monitor in the reporting year. If 
all natural gas pneumatic devices supplied by the measured natural gas 
supply line are routed to the atmosphere for only a portion of the year 
and are routed to a flare, combustion, or vapor recovery system for the 
remaining portion of the year, determine the cumulative annual 
volumetric flow considering only those times when one or more of the 
natural gas pneumatic devices were vented directly to the atmosphere. 
If the flow meter was installed during the year, escalate the measured 
volumetric flow by the ratio of the total hours for which natural gas 
was supplied to the devices to the number of hours the natural gas 
supplied to the devices was measured.
    (B) Convert the natural gas volumetric flow from paragraph 
(a)(1)(i)(A) of this section to CH4 and CO2 
volumetric emissions following the provisions in paragraph (u) of this 
section.
    (C) Convert the CH4 and CO2 volumetric 
emissions from paragraph (a)(1)(i)(B) of this section to CH4 
and CO2 mass emissions using calculations in paragraph (v) 
of this section.
    (ii) For mass flow monitors:
    (A) Determine the cumulative annual mass flow, in metric tons, as 
measured by the flow monitor in the reporting year. If all natural gas 
pneumatic devices supplied by the measured natural gas supply line are 
vented directly to the atmosphere for only a portion of the year and 
are routed to a flare, combustion, or vapor recovery system for the 
remaining portion of the year, determine the cumulative annual mass 
flow considering only those times when one or more of the natural gas 
pneumatic devices were vented directly to the atmosphere. If the flow 
meter was installed during the year, escalate the measured mass flow by 
the ratio of the total hours for which natural gas was supplied to the 
devices to the number of hours the natural gas supplied to the devices 
was measured.
    (B) Convert the cumulative mass flow from paragraph (a)(1)(ii)(A) 
of this section to CH4 and CO2 mass emissions by 
multiplying by the mass fraction of CH4 and CO2 
in the supplied natural gas. You must follow the provisions in 
paragraph (u) of this section for determining the mole fraction of 
CH4 and CO2 and use molecular weights of 16 kg/
kg-mol and 44 kg/kg-mol for CH4 and CO2, 
respectively. You may assume unspecified components have an average 
molecular weight of 28 kg/kg-mol.
    (iii) If the flow meter on the natural gas supply line serves both 
natural gas pneumatic devices and natural gas driven pneumatic pumps, 
disaggregate the total measured amount of natural gas to pneumatic 
devices and natural gas driven pneumatic pumps based on engineering 
calculations and best available data.
    (iv) The flow meter must be operated and calibrated according to 
the methods set forth in Sec.  98.234(b).
    (2) Calculation Method 2. Except as provided in paragraphs (a)(1) 
and (3) of this section, you must measure the volumetric flow rate of 
each natural gas pneumatic device vent that vents directly to the 
atmosphere at your facility as specified in paragraphs (a)(2)(i) 
through (ix) of this section. You must exclude the counts of devices 
measured according to paragraph (a)(1) of this section from the counts 
of devices to be measured or for which emissions are calculated 
according to the requirements in this paragraph (a)(2).
    (i) For facilities in the onshore petroleum and natural gas 
production and onshore petroleum and natural gas gathering and boosting 
industry segments, you must measure all natural gas pneumatic devices 
at your facility at least once every 5 years. If you elect to measure 
your pneumatic devices over multiple years, you must measure 
approximately the same number of devices each year. When you measure 
the emissions from natural gas pneumatic devices at a well-pad or 
gathering and boosting site, you must measure all natural gas pneumatic 
devices that are vented directly to the atmosphere at the well-pad or 
gathering and boosting site during the same calendar year.
    (ii) For facilities in the onshore natural gas processing, onshore 
natural gas transmission compression, underground natural gas storage, 
or natural gas distribution industry

[[Page 50381]]

segments, you must either measure all natural gas pneumatic devices 
vented directly to the atmosphere at your facility each year if your 
facility has less than 26 pneumatic devices or over multiple years not 
to exceed the number of years as specified in paragraphs (a)(2)(ii)(A) 
through (D) of this section. If you elect to measure your pneumatic 
devices over multiple years, you must measure approximately the same 
number of devices each year.
    (A) If your facility has at least 26 but not more than 50 natural 
gas pneumatic devices vented directly to the atmosphere, the maximum 
number of years to measure all devices at your facility is 2 years.
    (B) If your facility has at least 51 but not more than 75 natural 
gas pneumatic devices vented directly to the atmosphere, the maximum 
number of years to measure all devices at your facility is 3 years.
    (C) If your facility has at least 76 but not more than 100 natural 
gas pneumatic devices vented directly to the atmosphere, the maximum 
number of years to measure all devices at your facility is 4 years.
    (D) If your facility has 101 or more natural gas pneumatic devices 
vented directly to the atmosphere, the maximum number of years to 
measure all devices at your facility is 5 years.
    (iii) For all industry segments, determine the volumetric flow rate 
of each natural gas pneumatic device vent (in standard cubic feet per 
hour) using one of the methods specified in Sec.  98.234(b) through 
(d), as appropriate, according to the requirements specified in 
paragraphs (a)(2)(iii)(A) through (D) of this section.
    (A) If you use a temporary meter, such as a vane anemometer, 
according to the methods set forth in Sec.  98.234(b) or a high volume 
sampler according to methods set forth Sec.  98.234(d), you must 
measure the emissions from each device for a minimum of 15 minutes 
while the device is in service (i.e., supplied with natural gas), 
except for natural gas pneumatic isolation valve actuators. For natural 
gas pneumatic isolation valve actuators, you must measure the emissions 
from each device for a minimum of 5 minutes while the device is in 
service (i.e., supplied with natural gas). If there is no measurable 
flow from the natural gas pneumatic device after the minimum sampling 
period, you can discontinue monitoring and follow the applicable 
methods in paragraph (a)(2)(v) of this section.
    (B) If you use calibrated bagging, follow the methods set forth in 
Sec.  98.234(c) except you need only fill one bag to have a valid 
measurement. You must collect sample for a minimum of 5 minutes for 
natural gas pneumatic isolation valve actuators or 15 minutes for other 
natural gas pneumatic devices. If no gas is collected in the calibrated 
bag during the minimum sampling period, you can discontinue monitoring 
and follow the applicable methods in paragraph (a)(2)(v) of this 
section. If gas is collected in the bag during the minimum sampling 
period, you must either continue sampling until you fill the calibrated 
bag or you may elect to remeasure the vent according to paragraph 
(a)(2)(iii)(A) of this section.
    (C) You do not need to use the same measurement method for each 
natural gas pneumatic device vent.
    (D) If the measurement method selected measures the volumetric flow 
rate in actual cubic feet, convert the measured flow to standard cubic 
feet following the methods specified in paragraph (t)(1) of this 
section.
    (iv) For all industry segments, if there is measurable flow from 
the device vent, calculate the volume of natural gas emitted from each 
natural gas pneumatic device vent as the product of the natural gas 
flow rate measured in paragraph (a)(2)(iii) of this section and the 
number of hours the pneumatic device was in service (i.e., supplied 
with natural gas) in the calendar year.
    (v) For all industry segments, if there is no measurable flow from 
the device vent, estimate the emissions from the device according to 
the methods in paragraphs (a)(2)(v)(A) through (C) of this section, as 
applicable.
    (A) For continuous high bleed pneumatic devices:
    (1) Confirm that the device is in-service. If not, remeasure the 
device according to paragraph (a)(2)(iii) of this section at a time the 
device is in-service.
    (2) Confirm that the device is correctly characterized as a 
continuous high bleed pneumatic device according to the provisions in 
paragraph (a)(6) of this section. If the device type was 
mischaracterized, recharacterize the device type and use the 
appropriate methods in paragraphs (a)(2)(v)(B) or (C) of this section, 
as applicable.
    (3) Upon confirmation of the items in paragraphs (a)(2)(v)(A)(1) 
and (2) of this section, remeasure the device vent using a different 
measurement method or longer monitoring duration until the volumetric 
venting rate can be accurately quantified.
    (B) For continuous low bleed pneumatic devices:
    (1) Confirm that the device is in-service. If not, remeasure the 
device according to paragraph (a)(2)(iii) of this section at a time the 
device is in-service.
    (2) Determine natural gas bleed rate (in standard cubic feet per 
hour) at the supply pressure used for the pneumatic device based on the 
manufacturer's steady state natural gas bleed rate reported for the 
device. If the steady state bleed rate is reported in terms of air 
consumption, multiply the air consumption rate by 1.29 to calculate the 
steady state natural gas bleed rate. If a steady state bleed rate is 
not reported, you need to reassess whether the device is correctly 
characterized as a continuous low bleed pneumatic device according to 
the provisions in paragraph (a)(6) of this section.
    (3) Calculate the volume of natural gas emitted from the natural 
gas pneumatic device vent as the product of the natural gas steady 
state bleed rate determined in paragraph (a)(2)(v)(B)(2) of this 
section and number of hours the pneumatic device was in service (i.e., 
supplied with natural gas) in the calendar year.
    (C) For intermittent bleed pneumatic devices:
    (1) Confirm that the device is in-service. If not, remeasure the 
device according to paragraph (a)(2)(iii) of this section at a time the 
device is in-service and calculate natural gas emissions according to 
paragraph (a)(2)(iv) of this section. For devices confirmed to be in-
service during the measurement period, calculate natural gas emissions 
according to paragraph (a)(2)(v)(C)(2) through (5) of this section.
    (2) Calculate the volume of the controller, tubing and actuator (in 
actual cubic feet) based on the device and tubing size.
    (3) Sum the volumes in paragraph (a)(2)(v)(C)(2) of this section 
and convert the volume to standard cubic feet following the methods 
specified in paragraph (t)(1) of this section based on the natural gas 
supply pressure.
    (4) Estimate the number of actuations during the year based on 
company records, if available, or best engineering estimates. For 
isolation valve actuators, you may multiply the number of valve 
closures during the year by 2 (one actuation to close the valve; one 
actuation to open the valve).
    (5) Calculate the volume of natural gas emitted from the natural 
gas pneumatic device vent as the product of the per actuation volume in 
standard cubic feet determined in paragraph (a)(2)(v)(C)(3) of this 
section, the number of actuations during the year as determined in 
paragraph (a)(2)(v)(C)(4) of this section, and the relay correction 
factor. Use 1 for the relay correction factor if there is no relay; use 
3 for the relay correction factor if there is a relay.
    (6) Calculate the hourly average volume of natural gas emitted from 
the

[[Page 50382]]

natural gas pneumatic device vent by dividing the volume of natural gas 
emitted as determined in paragraph (a)(2)(v)(C)(5) of this section by 
the number of hours the pneumatic device was in service (i.e., supplied 
with natural gas) in the calendar year.
    (vi) For each pneumatic device, convert the volumetric emissions of 
natural gas at standard conditions determined in paragraph (a)(2)(iv) 
or (v) of this section, as applicable, to CO2 and 
CH4 volumetric emissions at standard conditions using the 
methods specified in paragraph (u) of this section.
    (vii) For each pneumatic device, convert the GHG volumetric 
emissions at standard conditions determined in paragraph (a)(2)(vi) of 
this section to GHG mass emissions using the methods specified in 
paragraph (v) of this section.
    (viii) Sum the CO2 and CH4 mass emissions 
determined in paragraph (a)(2)(vii) of this section separately for each 
type of natural gas pneumatic device (continuous high bleed, continuous 
low bleed, and intermittent bleed).
    (ix) If you chose to conduct natural gas pneumatic device 
measurements over multiple years, ``n,'' according to paragraph 
(a)(2)(i) or (ii) of this section, then you must calculate the 
emissions from all pneumatic devices at your facility as specified in 
paragraph (a)(2)(ix)(A) through (D) of this section.
    (A) Use the emissions calculated in (a)(2)(viii) of this section 
for the devices measured during the reporting year.
    (B) Calculate the whole gas emission factor for each type of 
pneumatic device at the facility using Equation W-1A and all available 
data from the current year and the previous years in your monitoring 
cycle (n-1 years) for which natural gas pneumatic device vent 
measurements were made according to Calculation Method 2 in paragraph 
(a)(2) of this section (e.g., if your monitoring cycle is 3 years, then 
use measured data from the current year and the two previous years). 
This emission factor must be updated annually.
[GRAPHIC] [TIFF OMITTED] TP01AU23.000


Where:

EFt = Whole gas population emission factor for natural 
gas pneumatic device vents of type ``t'' (continuous high bleed, 
continuous low bleed, intermittent bleed), in standard cubic feet 
per hour per device.
MTs,t,y = Volumetric whole gas emissions rate measurement 
at standard (``s'') conditions from component type ``t'' during year 
``y'' in standard cubic feet per hour, as calculated in paragraph 
(a)(2)(iii) [if there was measurable flow from the device vent], 
(a)(2)(v)(B)(2), or (a)(2)(v)(C)(6) of this section, as applicable.
Countt,y = Count of natural gas pneumatic device vents of 
type ``t'' measured according to Calculation Method 2 in year ``y.''
n = Number of years of data to include in the emission factor 
calculation according to the number of years used to monitor all 
natural gas pneumatic device vents at the facility.

    (C) Calculate CH4 and CO2 volumetric 
emissions from continuous high bleed, continuous low bleed, and 
intermittent bleed natural gas pneumatic devices that were not measured 
during the reporting year using Equation W-1B of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.001

Where:

Es,i = Annual total volumetric GHG emissions at standard 
conditions in standard cubic feet per year from natural gas 
pneumatic device vents, of types ``t'' (continuous high bleed, 
continuous low bleed, intermittent bleed), for GHGi.
Countt = Total number of natural gas pneumatic devices of 
type ``t'' (continuous high bleed, continuous low bleed, 
intermittent bleed) as determined in paragraphs (a)(4) through (6) 
of this section that vent directly to the atmosphere and that were 
not directly measured according to the requirements in paragraph 
(a)(1) or (a)(2)(iii) of this section.
EFt = Population emission factors for natural gas 
pneumatic device vents (in standard cubic feet per hour per device) 
of each type ``t'' (continuous high bleed, continuous low bleed, 
intermittent bleed) as calculated using Equation W-1A of this 
section.
GHGi = For onshore petroleum and natural gas production 
facilities, onshore petroleum and natural gas gathering and boosting 
facilities, onshore natural gas processing, onshore natural gas 
transmission compression facilities, underground natural gas storage 
facilities, and natural gas distribution facilities, concentration 
of GHGi, CH4 or CO2, in produced 
natural gas or processed natural gas for each facility as specified 
in paragraph (u)(2) of this section.
Tt = Average estimated number of hours in the operating 
year the devices, of each type ``t'', were in service (i.e., 
supplied with natural gas) using engineering estimates based on best 
available data. Default is 8,760 hours.

    (D) Convert the volumetric emissions calculated using Equation W-1B 
to CH4 and CO2 mass emissions using the methods 
specified in paragraph (v) of this section.
    (E) Sum the CH4 and CO2 mass emissions 
calculated in paragraphs (a)(2)(ix)(A) and (D) of this section 
separately for each type of pneumatic device (continuous high bleed, 
continuous low bleed, intermittent bleed) to calculate the total 
CH4 and CO2 mass emissions by device type for 
Calculation Method 2.
    (3) Calculation Method 3. As an alternative to Calculation Method 
2, you may elect to use the applicable methods specified in paragraphs 
(a)(3)(i) through (v) of this section, as applicable, to calculate 
CH4 and CO2 emissions from your natural gas 
pneumatic devices that are vented directly to the atmosphere at your 
facility except those that are measured according to paragraph (a)(1) 
of this section. You must exclude the counts of devices measured 
according to paragraph (a)(1) of this section from the counts of 
devices to be monitored or for which emissions are calculated according 
to the requirements in this paragraph (a)(3).
    (i) For continuous high bleed and continuous low bleed natural gas 
pneumatic devices vented directly to the atmosphere, you must calculate 
CH4 and CO2 volumetric emissions using either the 
methods in paragraph (a)(3)(i)(A) or (B) of this section.

[[Page 50383]]

    (A) Measure all continuous high bleed and continuous low bleed 
pneumatic devices at your well-pad, gathering and boosting site, or 
facility, as applicable, according to the provisions in paragraphs 
(a)(2) of this section.
    (B) Use Equation W-1B, except use the appropriate default whole gas 
population emission factors for natural gas pneumatic device vents (in 
standard cubic feet per hour per device) of each type ``t'' (continuous 
high bleed and continuous low bleed) as listed in table W-1 to this 
subpart.
    (ii) For intermittent bleed pneumatic devices, you must monitor 
each intermittent bleed pneumatic device at your facility using the 
methods specified in paragraph (a)(3)(ii)(A) of this section at the 
frequency specified in paragraph (a)(3)(ii)(B) or (C) of this section, 
as applicable.
    (A) You must use one of the monitoring methods specified in Sec.  
98.234(a)(1) through (3) except that the monitoring dwell time for each 
device vent must be at least 2 minutes or until a malfunction is 
identified, whichever is shorter. A device is considered malfunctioning 
if any leak is observed when the device is not actuating or if a leak 
is observed for more than 5 seconds during a device actuation. If you 
cannot tell when a device is actuating, any observed leak from the 
device indicates a malfunctioning device.
    (B) For facilities in the onshore petroleum and natural gas 
production and onshore petroleum and natural gas gathering and boosting 
industry segments, you must monitor all natural gas intermittent bleed 
pneumatic devices at your facility at least once every 5 years. If you 
elect to monitor your pneumatic devices over multiple years, you must 
monitor approximately the same number of devices each year. When you 
monitor the emissions from natural gas pneumatic devices at a well-pad 
or gathering and boosting site, you must monitor all natural gas 
intermittent bleed pneumatic devices that are vented directly to the 
atmosphere at the well-pad or gathering and boosting site during the 
same calendar year.
    (C) For facilities in the onshore natural gas processing, onshore 
natural gas transmission compression, underground natural gas storage, 
or natural gas distribution industry segments you must either monitor 
all natural gas intermittent bleed pneumatic devices vented directly to 
the atmosphere at your facility each year if your facility has less 
than 101 intermittent bleed pneumatic devices or over multiple years 
not to exceed the number of years as specified in paragraphs 
(a)(3)(ii)(C)(1) through (4) of this section. If you elect to monitor 
your intermittent bleed pneumatic devices over multiple years, you must 
monitor approximately the same number of devices each year.
    (1) If your facility has at least 101 but not more than 200 natural 
gas intermittent bleed pneumatic devices vented directly to the 
atmosphere, the maximum number of years to monitor all devices at your 
facility is 2 years.
    (2) If your facility has at least 201 but not more than 300 natural 
gas intermittent bleed pneumatic devices vented directly to the 
atmosphere, the maximum number of years to monitor all devices at your 
facility is 3 years.
    (3) If your facility has at least 301 but not more than 400 natural 
gas intermittent bleed pneumatic devices vented directly to the 
atmosphere, the maximum number of years to monitor all devices at your 
facility is 4 years.
    (4) If your facility has 401 or more natural gas intermittent bleed 
pneumatic devices vented directly to the atmosphere, the maximum number 
of years to monitor all devices at your facility is 5 years.
    (iii) For intermittent bleed pneumatic devices that are monitored 
according to paragraph (a)(3)(ii)(A) of this section during the 
reporting year, you must calculate CH4 and CO2 
volumetric emissions from intermittent bleed natural gas pneumatic 
devices vented directly to the atmosphere using Equation W-1C of this 
section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.002

Where:
Ei = Annual total volumetric emissions of GHGi 
from intermittent bleed natural gas pneumatic devices in standard 
cubic feet.
GHGi = Concentration of GHGi, CH4, or 
CO2, in natural gas supplied to the intermittent bleed 
natural gas pneumatic device as defined in paragraph (u)(2) of this 
section.
x = Total number of intermittent bleed natural gas pneumatic devices 
detected as malfunctioning in any pneumatic device monitoring survey 
during the year. A component found as malfunctioning in two or more 
surveys during the year is counted as one malfunctioning component.
16.1 = Whole gas emission factor for malfunctioning intermittent 
bleed natural gas pneumatic devices, in standard cubic feet per hour 
per device.
Tmal,z = The total time the surveyed pneumatic device 
``z'' was in service (i.e., supplied with natural gas) and assumed 
to be malfunctioning, in hours. If one pneumatic device monitoring 
survey is conducted in the calendar year, assume the device found 
malfunctioning was malfunctioning for the entire calendar year. If 
multiple pneumatic device monitoring surveys are conducted in the 
calendar year, assume a device found malfunctioning in the first 
survey was malfunctioning since the beginning of the year until the 
date of the survey; assume a device found malfunctioning in the last 
survey of the year was malfunctioning from the preceding survey 
through the end of the year; assume a device found malfunctioning in 
a survey between the first and last surveys of the year was 
malfunctioning since the preceding survey until the date of the 
survey; and sum times for all malfunctioning periods.
Tt,z = The total time the surveyed natural gas pneumatic 
device ``z'' was in service (i.e., supplied with natural gas) during 
the year. Default is 8,760 hours for non-leap years and 8,784 hours 
for leap years.
2.82 = Whole gas emission factor for properly operating intermittent 
bleed natural gas pneumatic devices, in standard cubic feet per hour 
per device.
Count = Total number of intermittent bleed natural gas pneumatic 
devices that were never observed to be malfunctioning during any 
monitoring survey during the year.
Tavg = The average time the intermittent bleed natural 
gas pneumatic devices that were never observed to be malfunctioning 
during any monitoring survey were in service (i.e., supplied with 
natural gas) using engineering estimates based on best available 
data. Default is 8,760 hours for non-leap years and 8,784 hours for 
leap years.

    (A) You must conduct at least one complete pneumatic device 
monitoring survey in a calendar year. If you conduct multiple complete 
pneumatic device monitoring surveys in a calendar year, you must use 
the results from each complete pneumatic device monitoring survey when 
calculating emissions using Equation W-1C.
    (B) For the purposes of paragraph (a)(3)(iii)(A) of this section, a 
complete monitoring survey is a survey of all

[[Page 50384]]

intermittent bleed natural gas pneumatic devices vented directly to the 
atmosphere at a well-pad for onshore petroleum and natural gas 
production facilities, all intermittent bleed pneumatic devices vented 
directly to the atmosphere at a gathering and boosting site for onshore 
petroleum and natural gas gathering and boosting facilities, or all 
intermittent bleed natural gas pneumatic devices vented directly to the 
atmosphere at a facility required to be monitored during a given year 
for other applicable industry segments.
    (iv) For intermittent bleed natural gas pneumatic devices that are 
not monitored according to paragraph (a)(3)(ii)(A) of this section 
during the reporting you, you must calculate CH4 and 
CO2 volumetric emissions from intermittent bleed natural gas 
pneumatic devices vented directly to the atmosphere as specified in 
paragraphs (a)(3)(iv)(A) through (D) of this section.
    (A) Count the number of unique intermittent bleed natural gas 
pneumatic devices vented directly to the atmosphere that were monitored 
during the reporting year. If you conducted multiple monitoring 
surveys, count each device only once; do not count the same device 
twice if it was monitored two times during the reporting year.
    (B) Count the number of unique intermittent bleed natural gas 
pneumatic devices vented directly to the atmosphere that were monitored 
during the reporting year that were identified as malfunctioning during 
the reporting year. If you conducted multiple monitoring surveys, count 
each device only once; do not count the same device twice if it was 
monitored and identified as malfunctioning two separate times during 
the reporting. If a device was malfunctioning during one monitoring 
survey and not during a second, count that device as a device that was 
identified as malfunctioning during the reporting year.
    (C) Determine the number of intermittent bleed natural gas 
pneumatic devices vented directly to the atmosphere at your facility 
that were not monitored during the reporting year as the difference 
between the total count of devices at your facility as determined 
according to paragraphs (a)(4) through (6) of this section and the 
count of unique devices monitored during the reporting year as 
determined in paragraph (a)(3)(vi)(A) of this section.
    (D) Calculate CH4 and CO2 volumetric 
emissions from intermittent bleed natural gas pneumatic devices vented 
directly to the atmosphere that were not monitored during the reporting 
year using Equation W-1D of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.003

Where:

Ei = Annual total volumetric emissions of GHGi 
from intermittent bleed natural gas pneumatic devices in standard 
cubic feet.
GHGi = Concentration of GHGi, CH4 or CO2, in 
natural gas supplied to the intermittent bleed device as defined in 
paragraph (u)(2) of this section.
Tavg = The average time the intermittent bleed natural 
gas pneumatic devices that were not surveyed during the year were in 
service (i.e., supplied with natural gas) using engineering 
estimates based on best available data. Default is 8,760 hours.
CountC = Total number of intermittent bleed pneumatic 
devices that were not surveyed during the year as determined 
according to paragraph (a)(3)(iv)(C) of this section.
16.1 = Whole gas emission factor for malfunctioning intermittent 
bleed natural gas pneumatic devices, in standard cubic feet per hour 
per device.
CountB = Total number of unique intermittent bleed 
natural gas pneumatic devices vented directly to the atmosphere that 
were monitored during the reporting year that were identified as 
malfunctioning during the reporting year as determined according to 
paragraph (a)(3)(iv)(B) of this section.
CountA = Total number the number of unique intermittent 
bleed natural gas pneumatic devices vented directly to the 
atmosphere that were monitored during the reporting year as 
determined according to paragraph (a)(3)(iv)(A) of this section.
2.82 = Whole gas emission factor for properly operating intermittent 
bleed natural gas pneumatic devices, in standard cubic feet per hour 
per device.

    (v) You must convert the CH4 and CO2 
volumetric emissions as determined according to paragraphs (a)(3)(i), 
(iii) and (iv) of this section and calculate both CO2 and 
CH4 mass emissions using calculations in paragraph (v) of 
this section for each type of natural gas pneumatic device (continuous 
high bleed, continuous low bleed, and intermittent bleed).
    (4) Counts of natural gas pneumatic devices. For all industry 
segments, determine ``Countt'' for Equation W-1A, W-1B, or W-1C of this 
subpart for each type of natural gas pneumatic device (continuous high 
bleed, continuous low bleed, and intermittent bleed) by counting the 
total number of devices at the facility, the number of devices that are 
vented directly to the atmosphere and the number of those devices that 
were measured or monitored during the reporting year, as applicable, 
except as specified in paragraph (a)(5) of this section.
    (5) Counts of onshore petroleum and natural gas production industry 
segment or the onshore petroleum and natural gas gathering and boosting 
natural gas pneumatic devices. For facilities in the onshore petroleum 
and natural gas production industry segment or the onshore petroleum 
and natural gas gathering and boosting industry segment, you have the 
option in the first two consecutive calendar years to determine the 
total number of natural gas pneumatic devices at the facility and the 
number of devices that are vented directly to the atmosphere for each 
type of natural gas pneumatic device (continuous high bleed, continuous 
low bleed, and intermittent bleed), as applicable, using engineering 
estimates based on best available data. Counts of natural gas pneumatic 
devices measured or monitored during the reporting year must be made 
based on actual counts.
    (6) Type of natural gas pneumatic devices. For all industry 
segments, determine the type of natural gas pneumatic device using 
engineering estimates based on best available information.
    (7) Routing to flares, combustion, or vapor recovery systems. 
Calculate emissions from natural gas pneumatic devices routed to 
flares, combustion, or vapor recovery systems as specified in paragraph 
(a)(7)(i) or (ii) of this section, as applicable. If a device was 
vented directly to the atmosphere for part of the year and routed to a 
flare, combustion unit, or vapor recovery system during another part of 
the year, then calculate emissions from the time the device vents 
directly to the atmosphere as specified in paragraph (a)(1), (2) or (3) 
of this section, as applicable, and calculate emissions from the time 
the device was routed to a flare or combustion as specified in 
paragraph (a)(7)(i) or (ii) of this section, as applicable. During 
periods when natural

[[Page 50385]]

gas pneumatic device emissions are collected in a vapor recovery system 
that is not routed to combustion, paragraphs (a)(1) through (3) and 
(a)(7)(i) and (ii) of this section do not apply and no emissions 
calculations are required.
    (i) If any natural gas pneumatic devices were routed to a flare, 
you must calculate CH4, CO2, and N2O 
emissions for the flare stack as specified in paragraph (n) of this 
section and report emissions from the flare as specified in Sec.  
98.236(n).
    (ii) If emissions from any natural gas pneumatic devices were 
routed to combustion units, you must calculate and report emissions as 
specified in subpart C of this part or calculate emissions as specified 
in paragraph (z) of this section and report emissions from the 
combustion equipment as specified in Sec.  98.236(z), as applicable.
* * * * *
    (c) Natural gas driven pneumatic pump venting. Calculate emissions 
from natural gas driven pneumatic pumps venting directly to the 
atmosphere as specified in paragraph (c)(1), (2), or (3) of this 
section, as applicable. If you have a flow meter on the natural gas 
supply line that is dedicated to any one or more natural gas driven 
pneumatic pumps, each of which only vents directly to the atmosphere, 
you must use Calculation Method 1 as specified in paragraph (c)(1) of 
this section to calculate vented CH4 and CO2 
emissions from those pumps. Use Calculation Method 1 for any portion of 
a year when all of the pumps on the measured natural gas supply line 
were vented directly to atmosphere. For natural gas driven pneumatic 
pumps vented directly to the atmosphere for which the natural gas 
supply rate is not measured, use either the method specified in 
paragraph (c)(2) or (3) of this section to calculate vented 
CH4 and CO2 emissions for all of the natural gas 
driven pneumatic pumps at your facility that are not subject to 
Calculation Method 1; you may not use Calculation Method 2 for some 
vented natural gas driven pneumatic pumps and Calculation Method 3 for 
other natural gas driven pneumatic pumps. Similarly, if a flow meter is 
on a natural gas supply line that supplies some pumps that vent 
directly to the atmosphere and others that route emissions to flares, 
combustion, or vapor recovery systems, then use either the method 
specified in paragraph (c)(2) or (3) of this section to calculate 
vented CH4 and CO2 emissions because Calculation 
Method 1 may not be used for this natural gas supply line. Calculate 
emissions from natural gas driven pneumatic pumps routed to flares or 
combustion as specified in paragraph (c)(4) of this section. If a pump 
vents directly to the atmosphere for part of the year and to a flare or 
combustion unit for another part of the year, then calculate vented 
emissions for the portion of the year when venting occurs using the 
applicable method in paragraph (c)(1), (2), or (3) of this section for 
the period when venting occurs, and calculate emissions for the portion 
of the year when the emissions are routed to a flare or combustion unit 
using the method in paragraph (c)(4) of this section. No emissions 
calculation is required during periods when emissions from a pump are 
routed to a vapor recovery system without subsequently being routed to 
combustion. All references to natural gas driven pneumatic pumps for 
Calculation Method 1 in this paragraph (c) also apply to combinations 
of pneumatic devices and natural gas driven pneumatic pumps that are 
served by a common natural gas supply line; when the supply line serves 
both pneumatic devices and natural gas driven pneumatic pumps, 
disaggregate the total measured amount of natural gas to pneumatic 
devices and natural gas driven pneumatic pumps based on engineering 
calculations and best available data. You do not have to calculate 
emissions from natural gas driven pneumatic pumps covered in paragraph 
(e) of this section under this paragraph (c).
    (1) Calculation Method 1. If you have or elect to install a flow 
meter on a supply line to natural gas driven pneumatic pumps, then for 
the period of the year when the natural gas supply line is dedicated to 
any one or more natural gas driven pneumatic pumps, and the pumps are 
vented directly to the atmosphere, you must use the applicable methods 
specified in paragraphs (c)(1)(i) or (ii) of this section to calculate 
vented CH4 and CO2 emissions from those pumps.
    (i) For volumetric flow monitors:
    (A) Determine the cumulative annual volumetric flow, in standard 
cubic feet, as measured by the flow monitor in the reporting year. If 
the flow meter was installed during the year, calculate the total 
annual volume of natural gas used in the pumps that are connected to 
the measured supply line by escalating the measured volumetric flow by 
the ratio of the total hours for which natural gas was supplied to the 
pumps to the number of hours the natural gas supplied to the pumps was 
measured as specified in Equation W-2A of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.004

Where:

Es = Annual natural gas emissions for pumps connected to 
natural gas supply line that had a natural gas flow meter installed 
during the year, in standard cubic feet.
Es,M = Measured volume of natural gas in the supply line, 
from the time that the natural gas flow meter began measuring to the 
end of the year, in standard cubic feet.
T = Total hours during the year in which at least one of the pumps 
connected to the supply line was operating, hr/yr.
TM = Total hours during the year when the natural gas 
supply flow meter was measuring flow.

    (B) Convert the natural gas volumetric flow from paragraph 
(c)(1)(i)(A) of this section to CH4 and CO2 
volumetric emissions following the provisions in paragraph (u) of this 
section.
    (C) Convert the CH4 and CO2 volumetric 
emissions from paragraph (c)(1)(i)(B) of this section to CH4 
and CO2 mass emissions using calculations in paragraph (v) 
of this section.
    (ii) For mass flow monitors:
    (A) Determine the cumulative annual mass flow, in metric tons, as 
measured by the flow monitor in the reporting year. If the flow meter 
was installed during the year, calculate the total annual mass of 
natural gas used in the pumps that are connected to the measured supply 
line by escalating the measured mass flow by the ratio of the total 
hours for which natural gas was supplied to the pumps to the number of 
hours the natural gas supplied to the pumps was measured as specified 
in Equation W-2A of paragraph (c)(1)(i)(A) of this section, except that 
Es and Es,M are in metric tons per year instead 
of standard cubic feet per year.
    (B) Convert the cumulative mass flow from paragraph (c)(1)(ii)(A) 
of this section to CH4 and CO2 mass emissions

[[Page 50386]]

by multiplying by the mass fraction of CH4 and 
CO2 in the supplied natural gas. You must follow the 
provisions in paragraph (u) of this section for determining the mole 
fraction of CH4 and CO2 and use molecular weights 
of 16 kg/kg-mol and 44 kg/kg-mol for CH4 and CO2, 
respectively. You may assume unspecified components have an average 
molecular weight of 28 kg/kg-mol.
    (2) Calculation Method 2. Except as provided in paragraph (c)(1) of 
this section, you may elect to measure the volumetric flow rate of each 
natural gas driven pneumatic pump at your facility that vents directly 
to the atmosphere as specified in paragraphs (c)(2)(i) through (vii) of 
this section. You must exclude the counts of pumps measured according 
to paragraph (c)(1) of this section from the counts of pumps to be 
measured and for which emissions are calculated according to the 
requirements in this paragraph (c)(2).
    (i) Measure all natural gas driven pneumatic pumps at your facility 
at least once every 5 years. If you elect to measure your pneumatic 
pumps over multiple years, you must measure approximately the same 
number of pumps each year. When you measure the emissions from natural 
gas driven pneumatic pumps at a well-pad or gathering and boosting 
site, you must measure all pneumatic pumps that are vented directly to 
the atmosphere at the well-pad or gathering and boosting site during 
the same calendar year.
    (ii) Determine the volumetric flow rate of each natural gas driven 
pneumatic pump (in standard cubic feet per hour) using one of the 
methods specified in Sec.  98.234(b) through (d), as appropriate, 
according to the requirements specified in paragraphs (c)(2)(ii)(A) 
through (D) of this section.
    (A) If you use a temporary meter, such as a vane anemometer, 
according to the methods set forth in Sec.  98.234(b) or a high volume 
sampler according to methods set forth Sec.  98.234(d), you must 
measure the emissions from each pump for a minimum of 5 minutes, during 
a period when the pump is continuously pumping liquid.
    (B) If you use calibrated bagging, follow the methods set forth in 
Sec.  98.234(c), except under Sec.  98.234(c)(2), only one bag must be 
filled to have a valid measurement. You must collect sample for a 
minimum of 5 minutes, or until the bag is full, whichever is shorter, 
during a period when the pump is continuously pumping liquid. If the 
bag is not full after 5 minutes, you must either continue sampling 
until you fill the calibrated bag or you may elect to remeasure the 
vent according to paragraph (c)(2)(ii)(A) of this section.
    (C) You do not need to use the same measurement method for each 
natural gas driven pneumatic pump vent.
    (D) If the measurement method selected measures the volumetric flow 
rate in actual cubic feet, convert the measured flow to standard cubic 
feet following the methods specified in paragraph (t)(1) of this 
section. Convert the measured flow during the test period to standard 
cubic feet per hour, as appropriate.
    (iii) Calculate the volume of natural gas emitted from each natural 
gas driven pneumatic pump vent as the product of the natural gas 
emissions flow rate measured in paragraph (c)(2)(ii) of this section 
and the number of hours that liquid was pumped by the pneumatic pump in 
the calendar year.
    (iv) For each pneumatic pump, convert the volumetric emissions of 
natural gas at standard conditions determined in paragraph (c)(2)(iii) 
of this section to CO2 and CH4 volumetric 
emissions at standard conditions using the methods specified in 
paragraph (u) of this section.
    (v) For each pneumatic pump, convert the GHG volumetric emissions 
at standard conditions determined in paragraph (c)(2)(iv) of this 
section to GHG mass emissions using the methods specified in paragraph 
(v) of this section.
    (vi) Sum the CO2 and CH4 mass emissions 
determined in paragraph (c)(2)(v) of this section.
    (vii) If you chose to conduct natural gas pneumatic pump 
measurements over multiple years, ``n,'' according to paragraph 
(c)(2)(i) of this section, then you must calculate the emissions from 
all pneumatic pumps at your facility as specified in paragraph 
(c)(2)(vii)(A) through (D) of this section.
    (A) Use the emissions calculated in paragraph (c)(2)(vi) of this 
section for the pumps measured during the reporting year.
    (B) Calculate the whole gas emission factor for pneumatic pumps at 
the facility using Equation W-2B of this section and all available data 
from the current year and the previous years in your monitoring cycle 
(n-1 years) for which natural gas pneumatic pump vent measurements were 
made according to Calculation Method 2 in paragraph (c)(2) of this 
section (e.g., if your monitoring cycle is 3 years, then use measured 
data from the current year and the two previous years). This emission 
factor must be updated annually.
[GRAPHIC] [TIFF OMITTED] TP01AU23.005

Where:

EFs = Whole gas population emission factor for natural 
gas pneumatic pump vents, in standard cubic feet per hour per pump.
MTs,y = Volumetric whole gas emissions rate measurement 
at standard (``s'') conditions during year ``y'' in standard cubic 
feet per hour, as calculated in paragraph (c)(2)(iii) of this 
section.
County = Count of natural gas driven pneumatic pump vents measured 
according to Calculation Method 2 in year ``y.''
n = Number of years of data to include in the emission factor 
calculation according to the number of years used to monitor all 
natural gas pneumatic pump vents at the facility.

    (C) Calculate CH4 and CO2 volumetric 
emissions from natural gas driven pneumatic pumps that were not 
measured during the reporting year using Equation W-2C of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.006

Where:

Es,i = Annual total volumetric GHG emissions at standard 
conditions in standard cubic feet per year from natural gas driven 
pneumatic pump vents, for GHGi.
Count = Total number of natural gas driven pneumatic pumps that 
vented directly to the atmosphere and that were not directly 
measured according to the requirements in paragraphs (c)(1) or 
(c)(2)(ii) of this section.

[[Page 50387]]

EFs = Population emission factors for natural gas driven 
pneumatic pumps (in standard cubic feet per hour per pump) as 
calculated using Equation W-2B of this section.
GHGi = Concentration of GHGi, CH4 or 
CO2, in produced natural gas as defined in paragraph 
(u)(2)(i) of this section.
T = Average estimated number of hours in the operating year the 
pumps that vented directly to the atmosphere were pumping liquid 
using engineering estimates based on best available data. Default is 
8,760 hours for pumps that only vented directly to the atmosphere.

    (D) Calculate both CH4 and CO2 mass emissions 
from volumetric emissions calculated using Equation W-2C of this 
section using calculations in paragraph (v) of this section.
    (E) Sum the CH4 and CO2 mass emissions 
calculated in paragraphs (c)(2)(vii)(A) and (D) of this section to 
calculate the total CH4 and CO2 mass emissions 
for Calculation Method 2.
    (3) Calculation Method 3. If you elect not to measure emissions as 
specified in Calculation Method 2, then you must use the applicable 
method specified in paragraphs (c)(3)(i) and (ii) of this section to 
calculate CH4 and CO2 emissions from all natural 
gas driven pneumatic pumps that are vented directly to the atmosphere 
at your facility and that are not measured according to paragraph 
(c)(1) of this section. You must exclude the counts of devices measured 
according to paragraph (c)(1) of this section from the counts of pumps 
for which emissions are calculated according to the requirements in 
this paragraph (c)(3).
    (i) Calculate CH4 and CO2 volumetric 
emissions from natural gas driven pneumatic pumps using Equation W-2C 
of this section, except use the appropriate default whole gas 
population emission factor for natural gas pneumatic pump vents (in 
standard cubic feet per hour per device) as provided in table W-1 to 
this subpart.
    (ii) Convert the CH4 and CO2 volumetric 
emissions determined according to paragraph (c)(3)(i) of this section 
to CO2 and CH4 mass emissions using calculations 
in paragraph (v) of this section.
    (4) Routing to flares, combustion, or vapor recovery systems. 
Calculate emissions from natural gas driven pneumatic pumps for periods 
when they are routed to flares or combustion as specified in paragraph 
(c)(4)(i) or (ii) of this section, as applicable. If a pump was vented 
directly to the atmosphere for part of the year and routed to a flare 
or combustion during another part of the year, then calculate emissions 
from the time the pump vents directly to the atmosphere as specified in 
paragraphs (c)(2) or (3) of this section and calculate emissions from 
the time the pump was routed to a flare or combustion as specified in 
paragraphs (c)(4)(i) and (ii) of this section, as applicable. For 
emissions that are collected in a vapor recovery system that is never 
routed to combustion during the reporting year, paragraphs (c)(2) and 
(3) and paragraphs (c)(4)(i) and (ii) of this section do not apply and 
no emissions calculations are required.
    (i) If any natural gas driven pneumatic pumps were routed to a 
flare, you must calculate CH4, CO2, and 
N2O emissions for the flare stack as specified in paragraph 
(n) of this section and report emissions from the flare as specified in 
Sec.  98.236(n).
    (ii) If emissions from any natural gas driven pneumatic pumps were 
routed to combustion, you must calculate emissions for the combustion 
equipment as specified in paragraph (z) of this section and report 
emissions from the combustion equipment as specified in Sec.  
98.236(z).
    (d) Acid gas removal unit (AGR) vents and Nitrogen removal unit 
(NRU) vents. For AGR vents (including processes such as amine, 
membrane, molecular sieve or other absorbents and adsorbents), 
calculate emissions for CH4 and CO2 vented 
directly to the atmosphere or emitted through a sulfur recovery plant, 
using any of the calculation methods described in paragraphs (d)(1) 
through (4) of this section, and also comply with paragraphs (d)(5) 
through (11) of this section, as applicable. For NRU vents, calculate 
emissions for CH4 vented directly to the atmosphere using 
any of the calculation methods described in paragraphs (d)(1) through 
(4) of this section, and also comply with paragraphs (d)(5) through 
(11) of this section, as applicable. If any AGR vents or NRU vents are 
routed to a flare, you must calculate CH4, CO2, 
and N2O emissions for the flare stack as specified in 
paragraph (n) of this section and report emissions from the flare as 
specified in Sec.  98.236(n). If any AGR vents or NRU vents are routed 
through an engine (e.g., permeate from a membrane or de-adsorbed gas 
from a pressure swing adsorber used as fuel supplement) (i.e., routed 
to combustion, you must calculate CH4, CO2, and 
N2O emissions as specified in subpart C of this part or as 
specified in paragraph (z) of this section, as applicable.
    (1) Calculation Method 1. If you operate and maintain a continuous 
emissions monitoring system (CEMS) that has both a CO2 
concentration monitor and volumetric flow rate monitor, you must 
calculate CO2 emissions under this subpart by following the 
Tier 4 Calculation Method and all associated calculation, quality 
assurance, reporting, and recordkeeping requirements for Tier 4 in 
subpart C of this part (General Stationary Fuel Combustion Sources). 
Alternatively, you may follow the manufacturer's instructions or 
industry standard practice. If a CO2 concentration monitor 
and volumetric flow rate monitor are not available, you may elect to 
install a CO2 concentration monitor and a volumetric flow 
rate monitor that comply with all of the requirements specified for the 
Tier 4 Calculation Method in subpart C of this part (General Stationary 
Fuel Combustion Sources).
    (2) Calculation Method 2. For CO2 emissions, if a CEMS 
is not available but a vent meter is installed, use the CO2 
composition and annual volume of vent gas to calculate emissions using 
Equation W-3 of this section. For CH4 emissions, if a vent 
meter is installed, including the volumetric flow rate monitor on a 
CEMS for CO2, use the CH4 composition and annual 
volume of vent gas to calculate emissions using Equation W-3 of this 
section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.007

Where:

Ea,i = Annual total volumetric GHGi (either 
CO2 or CH4) emissions at actual conditions, in 
cubic feet per year.
Va = Total annual volume of vent gas flowing out of the 
AGR or NRU in cubic feet per year at actual conditions as determined 
by flow meter using methods set forth in Sec.  98.234(b). 
Alternatively, you may follow the manufacturer's instructions or 
industry standard practice for calibration of the vent meter.
Voli = Annual average volumetric fraction of GHGi (either 
CO2 or CH4) content in vent gas flowing out of 
the AGR or NRU as determined in paragraph (d)(7) of this section.

    (3) Calculation Method 3. If a CEMS for CO2 or a vent 
meter is not installed, you may use the inlet and/or outlet gas

[[Page 50388]]

flow rate of the AGR or NRU to calculate emissions for CH4 
and CO2 using Equations W-4A, W-4B, or W-4C of this section. 
If inlet gas flow rate and CH4 and CO2 content of 
the vent gas are known, use Equation W-4A. If outlet gas flow rate and 
CH4 and CO2 content of the vent gas are known, 
use Equation W-4B. If inlet gas flow rate and outlet gas flow rate are 
known, use Equation W-4C.
[GRAPHIC] [TIFF OMITTED] TP01AU23.008

[GRAPHIC] [TIFF OMITTED] TP01AU23.009

[GRAPHIC] [TIFF OMITTED] TP01AU23.010

Where:

Ea,i = Annual total volumetric GHGi (either 
CH4 or CO2) emissions at actual conditions, in 
cubic feet per year.
Vin = Total annual volume of natural gas flow into the 
AGR or NRU in cubic feet per year at actual conditions as determined 
using methods specified in paragraph (d)(5) of this section.
Vout = Total annual volume of natural gas flow out of the 
AGR or NRU in cubic feet per year at actual conditions as determined 
using methods specified in paragraph (d)(5) of this section.
VolI,i = Annual average volumetric fraction of GHGi 
(either CH4 or CO2) content in natural gas 
flowing into the AGR or NRU as determined in paragraph (d)(7) of 
this section.
VolO,i = Annual average volumetric fraction of GHGi 
(either CH4 or CO2) content in natural gas 
flowing out of the AGR or NRU as determined in paragraph (d)(8) of 
this section.
VolEM,i = Annual average volumetric fraction of GHGi 
(either CH4 or CO2) content in the vent gas 
flowing out of the AGR or NRU as determined in paragraph (d)(6) of 
this section.

    (4) Calculation Method 4. If CEMS for CO2 or a vent 
meter is not installed, you may calculate CH4 and 
CO2 emissions from an AGR or NRU using any standard 
simulation software package, such as AspenTech HYSYS[supreg], or API 
4679 AMINECalc, that uses the Peng-Robinson equation of state and 
speciates CH4 and CO2 emissions. A minimum of the 
parameters listed in paragraph (d)(4)(i) through (x) of this section, 
as applicable, must be used to characterize emissions. If paragraph 
(d)(4)(i) through (x) of this section indicates that an applicable 
parameter must be measured, collect measurements reflective of 
representative operating conditions over the time period covered by the 
simulation. Determine all other applicable parameters in paragraph 
(d)(4)(i) through (x) of this section by engineering estimate and 
process knowledge based on best available data and, if necessary, 
adjust parameters to represent the operating conditions over the time 
period covered by the simulation. Determine the number of simulations 
and associated time periods such that the simulations cover the entire 
reporting year (i.e., if you calculate emissions using one simulation, 
use representative parameters for the operating conditions over the 
calendar year; if you use periodic simulations to cover the calendar 
year, use parameters for the operating conditions over each 
corresponding appropriate portion of the calendar year).
    (i) Natural gas feed temperature, pressure, and flow rate (must be 
measured).
    (ii) Acid gas content of feed natural gas (must be measured).
    (iii) Acid gas content of outlet natural gas.
    (iv) CH4 content of feed natural gas (must be measured).
    (v) CH4 content of outlet natural gas.
    (vi) For NRU, nitrogen content of feed natural gas (must be 
measured).
    (vii) For NRU, nitrogen content of outlet natural gas.
    (viii) Unit operating hours, excluding downtime for maintenance or 
standby.
    (ix) Exit temperature of natural gas.
    (x) For AGR, solvent type, pressure, temperature, circulation rate, 
and composition.
    (5) Flow rate of inlet. For Calculation Method 3, determine the gas 
flow rate of the inlet when using Equation W-4A or W-4C of this section 
or the gas flow rate of the outlet when using Equation W-4B or W-4C of 
this section for the natural gas stream of an AGR or NRU using a meter 
according to methods set forth in Sec.  98.234(b). If you do not have a 
continuous flow meter, either install a continuous flow meter or use an 
engineering calculation to determine the flow rate.
    (6) Composition of vent gas. For Calculation Method 2 or 
Calculation Method 3 when using Equation W-4A or W-4B of this section, 
if a continuous gas analyzer is not available on the vent stack, either 
install a continuous gas analyzer or take quarterly gas samples from 
the vent gas stream for each quarter that the AGR or NRU is operating 
to determine Voli in Equation W-3 of this section or Equation W-4A or 
W-4B of this section, according to the methods set forth in Sec.  
98.234(b).
    (7) Composition of inlet gas stream. For Calculation Method 3, if a 
continuous gas analyzer is installed on the inlet gas stream, then the 
continuous gas analyzer results must be used. If a continuous gas 
analyzer is not available, either install a continuous gas analyzer or 
take quarterly gas samples from the inlet gas stream for each quarter 
that the AGR or NRU is operating to determine VolI,i in Equation W-4A, 
W-4B, or W-4C of this section, according to the methods set forth in 
Sec.  98.234(b).
    (8) Composition of outlet gas stream. For Calculation Method 3, 
determine annual average volumetric fraction of GHGi (either 
CH4 or CO2) content in natural gas flowing out of 
the AGR or NRU using one of the methods specified in paragraphs 
(d)(8)(i) through (iii) of this section.
    (i) If a continuous gas analyzer is installed on the outlet natural 
gas stream, then the continuous gas analyzer results must be used. If a 
continuous gas analyzer is not available, you may install a continuous 
gas analyzer.
    (ii) If a continuous gas analyzer is not available or installed, 
quarterly gas samples may be taken from the outlet natural gas stream 
for each quarter that the AGR or NRU is operating to

[[Page 50389]]

determine VolO,i in Equation W-4A, W-4B, or W-4C of this 
section, according to the methods set forth in Sec.  98.234(b).
    (iii) If a continuous gas analyzer is not available or installed, 
you may use the outlet pipeline quality specification for 
CO2 in natural gas and the outlet quality specification for 
CH4 in natural gas.
    (9) Volumetric emissions. Calculate annual volumetric 
CH4 and CO2 emissions at standard conditions 
using calculations in paragraph (t) of this section.
    (10) Mass emissions. Calculate annual mass CH4 and 
CO2 emissions using calculations in paragraph (v) of this 
section.
    (11) Emissions recovered and transferred outside the facility. 
Determine if CO2 emissions from the AGR are recovered and 
transferred outside the facility. Adjust the CO2 emissions 
estimated in paragraphs (d)(1) through (d)(10) of this section downward 
by the magnitude of CO2 emissions recovered and transferred 
outside the facility.
    (e) Dehydrator vents. For dehydrator vents, calculate annual 
CH4 and CO2 emissions using the applicable 
calculation methods described in paragraphs (e)(1) through (5) of this 
section. For glycol dehydrators that have an annual average daily 
natural gas throughput that is greater than or equal to 0.4 million 
standard cubic feet per day, use Calculation Method 1 in paragraph 
(e)(1) of this section. For glycol dehydrators that have an annual 
average of daily natural gas throughput that is greater than 0 million 
standard cubic feet per day and less than 0.4 million standard cubic 
feet per day, use either Calculation Method 1 in paragraph (e)(1) of 
this section or Calculation Method 2 in paragraph (e)(2) of this 
section. If you are required to or elect to use the method in paragraph 
(e)(1) of this section, you must use the results of the model to 
determine annual mass emissions. If emissions from dehydrator vents are 
routed to a vapor recovery system, you must adjust the emissions 
downward according to paragraph (e)(4) of this section. If emissions 
from dehydrator vents are routed to a regenerator firebox/fire tubes, 
you must calculate CH4, CO2, and N2O 
annual emissions as specified in paragraph (e)(5) of this section. If 
any dehydrator vents are routed to a flare, you must calculate 
CH4, CO2, and N2O emissions for the 
flare stack as specified in paragraph (n) of this section and report 
emissions from the flare as specified in Sec.  98.236(n).
    (1) Calculation Method 1. Calculate annual mass emissions from 
glycol dehydrators by using a software program, such as AspenTech 
HYSYS[supreg], Bryan Research & Engineering ProMax[supreg], or GRI-
GLYCalcTM, that uses the Peng-Robinson equation of state to calculate 
the equilibrium coefficient, speciates CH4 and 
CO2 emissions from dehydrators, and has provisions to 
include regenerator control devices, a separator flash tank, stripping 
gas, and a gas injection pump or gas assist pump. If you elect to use 
ProMax[supreg], you must use version 5.0 or above. Emissions must be 
modeled from both the still vent and, if applicable, the flash tank 
vent. A minimum of the parameters listed in paragraph (e)(1)(i) through 
(xi) of this section, as applicable, must be used to characterize 
emissions. If paragraph (e)(1)(i) through (xi) of this section 
indicates that an applicable parameter must be measured, collect 
measurements reflective of representative operating conditions for the 
time period covered by the simulation. Determine all other applicable 
parameters in paragraph (e)(1)(i) through (xi) of this section by 
engineering estimate and process knowledge based on best available data 
and, if necessary, adjust parameters to represent the operating 
conditions over the time period covered by the simulation. Determine 
the number of simulations and associated time periods such that the 
simulations cover the entire reporting year (i.e., if you calculate 
emissions using one simulation, use representative parameters for the 
operating conditions over the calendar year; if you use periodic 
simulations to cover the calendar year, use parameters for the 
operating conditions over each corresponding appropriate portion of the 
calendar year).
    (i) Feed natural gas flow rate (must be measured).
    (ii) Feed natural gas water content (must be measured).
* * * * *
    (x) Wet natural gas temperature and pressure at the absorber inlet 
(must be measured).
    (xi) Wet natural gas composition. Measure this parameter using one 
of the methods described in paragraphs (e)(1)(xi)(A) and (B) of this 
section.
    (A) Use an appropriate standard method published by a consensus-
based standards organization if such a method exists or you may use an 
industry standard practice as specified in Sec.  98.234(b) to sample 
and analyze wet natural gas composition.
    (B) If only composition data for dry natural gas is available, 
assume the wet natural gas is saturated.
    (2) Calculation Method 2. Calculate annual volumetric emissions 
from glycol dehydrators using Equation W-5 of this section, and then 
calculate the collective CH4 and CO2 mass 
emissions from the volumetric emissions using the procedures in 
paragraph (v) of this section:
* * * * *
Count = Total number of glycol dehydrators that have an annual average 
daily natural gas throughput that is greater than 0 million standard 
cubic feet per day and less than 0.4 million standard cubic feet per 
day for which you elect to use this Calculation Method 2.
* * * * *
    (3) Calculation Method 3. For dehydrators of any size that use 
desiccant, you must calculate emissions from the amount of gas vented 
from the vessel when it is depressurized for the desiccant refilling 
process using Equation W-6 of this section. From volumetric natural gas 
emissions, calculate both CH4 and CO2 volumetric 
and mass emissions using the procedures in paragraphs (u) and (v) of 
this section. Desiccant dehydrator emissions covered in this paragraph 
do not have to be calculated separately using the method specified in 
paragraph (i) of this section for blowdown vent stacks.
* * * * *
    (4) Emissions vented directly to atmosphere from dehydrators routed 
to a vapor recovery system, flare, or regenerator firebox/fire tubes. 
If the dehydrator(s) has a vapor recovery system, routes emissions to a 
flare, or routes emissions to a regenerator firebox/fire tubes and you 
use Calculation Method 1 or Calculation Method 2 in paragraph (e)(1) or 
(2) of this section, calculate annual emissions vented directly to 
atmosphere from the dehydrator(s) during periods of time when emissions 
were not routed to the vapor recovery system, flare, or regenerator 
firebox/fire tubes as specified in paragraphs (e)(4)(i) and (ii) of 
this section. If the dehydrator(s) has a vapor recovery system or 
routes emissions to a flare and you use Calculation Method 3 in 
paragraph (e)(3) of this section, calculate annual emissions vented 
directly to atmosphere from the dehydrator(s) during periods of time 
when emissions were not routed to the vapor recovery system or flare as 
specified in paragraph (e)(4)(iii) of this section.
    (i) When emissions from dehydrator(s) are calculated using 
Calculation Method 1 or 2, calculate maximum potential annual vented 
emissions as specified in paragraph

[[Page 50390]]

(e)(1) or (2) of this section, and calculate an average hourly vented 
emissions rate by dividing the maximum potential annual vented 
emissions by the number of hours that the dehydrator was in operation.
    (ii) To calculate total emissions vented directly to atmosphere 
during periods when the dehydrator was not routing emissions to a vapor 
recovery system, flare, or regenerator firebox/fire tubes for 
dehydrator(s) with emissions calculated using Calculation Method 1 or 
2, multiply the average hourly vented emissions rate determined in 
paragraph (e)(4)(i) of this section by the number of hours that the 
dehydrator vented directly to the atmosphere. Determine the number of 
hours that the dehydrator vented directly to atmosphere by subtracting 
the hours that the dehydrator was connected to a vapor recovery system, 
flare, or regenerator firebox/fire tubes (based on engineering estimate 
and best available data) from the total operating hours for the 
dehydrator in the calendar year. You must take into account periods 
with reduced capture efficiency of the vapor recovery system, flare, or 
regenerator firebox/fire tubes. If emissions are routed to a flare but 
the flare is unlit, calculate emissions in accordance with the 
methodology specified in paragraph (n) of this section and report 
emissions from the flare as specified in Sec.  98.236(n).
    (iii) When emissions from dehydrator(s) are calculated using 
Calculation Method 3, calculate total annual emissions vented directly 
to atmosphere from the dehydrator(s) during periods of time when 
emissions were not routed to the vapor recovery system, flare, or 
regenerator firebox/fire tubes by determining of the number of 
depressurization events (including portions of an event) that vented to 
atmosphere based on engineering estimate and best available data. You 
must take into account periods with reduced capture efficiency of the 
vapor recovery system or flare. If emissions are routed to a flare but 
the flare is unlit, calculate emissions in accordance with the 
methodology specified in paragraph (n) of this section and report 
emissions from the flare as specified in Sec.  98.236(n).
    (5) Combustion emissions from routing to regenerator firebox/fire 
tubes. If any dehydrator emissions are routed to a regenerator firebox/
fire tubes, calculate emissions from these devices attributable to 
dehydrator flash tank vents or still vents as specified in paragraphs 
(e)(5)(i) through (iii) of this section. If you operate a CEMS to 
monitor the emissions from the regenerator firebox/fire tubes, 
calculate emissions as specified in paragraph (e)(5)(iv) of this 
section.
    (i) Determine the volume of the total emissions that is routed to a 
regenerator firebox/fire tubes as specified in paragraph (e)(5)(i)(A) 
or (B) of this section.
    (A) Measure the flow from the dehydrator(s) to the regenerator 
firebox/fire tubes using a continuous flow measurement device. If you 
continuously measure flow to the regenerator firebox/fire tubes, you 
must use the measured volumes to calculate emissions from the 
regenerator firebox/fire tubes.
    (B) Using engineering estimates based on best available data, 
determine the volume of the total emissions estimated in paragraph 
(e)(1), (2), or (3) of this section, as applicable, that is routed to 
the regenerator firebox/fire tubes.
    (ii) Determine composition of the gas routed to a regenerator 
firebox/fire tubes as specified in paragraph (e)(5)(ii)(A) or (B) of 
this section.
    (A) Use the appropriate vent emissions as determined in paragraph 
(e)(1) or (2) of this section.
    (B) Measure the composition of the gas from the dehydrator(s) to 
the regenerator firebox/fire tubes using a continuous composition 
analyzer. If you continuously measure gas composition, then those 
measured data must be used to calculate dehydrator emissions from the 
regenerator firebox/fire tubes.
    (iii) Determine GHG volumetric emissions at actual conditions from 
the regenerator firebox/fire tubes using Equations W-39A, W-39B, and W-
40 in paragraph (z)(3) of this section. Calculate GHG volumetric 
emissions at standard conditions using calculations in paragraph (t) of 
this section. Calculate both GHG mass emissions from volumetric 
emissions using calculations in paragraph (v) of this section.
    (iv) If you operate and maintain a CEMS that has both a 
CO2 concentration monitor and volumetric flow rate monitor 
for the combustion gases from the regenerator firebox/fire tubes, you 
must calculate only CO2 emissions for the regenerator 
firebox/fire tubes. You must follow the Tier 4 Calculation Method and 
all associated calculation, quality assurance, reporting, and 
recordkeeping requirements for Tier 4 in subpart C of this part 
(General Stationary Fuel Combustion Sources). If a CEMS is used to 
calculate emissions from a regenerator firebox/fire tubes, the 
requirements specified in paragraphs (e)(5)(ii) and (iii) of this 
section are not required.
    (f) Well venting for liquids unloadings. Calculate annual 
volumetric natural gas emissions from well venting for liquids 
unloading when the well is unloaded to the atmosphere or a control 
device using one of the calculation methods described in paragraph 
(f)(1), (2), or (3) of this section. Once every 3 consecutive calendar 
years or on a more frequent basis, you must use Calculation Method 1 to 
calculate emissions from well venting for liquids unloading for each 
well. Calculate annual CH4 and CO2 volumetric and 
mass emissions using the method described in paragraph (f)(4) of this 
section.
    (1) Calculation Method 1. Calculate emissions from manual and 
automated unloadings at wells with plunger lifts and wells without 
plunger lifts separately. For at least one well of each unique well 
tubing diameter group and pressure group combination in each sub-basin 
category (see Sec.  98.238 for the definitions of tubing diameter 
group, pressure group, and sub-basin category), where gas wells are 
vented to the atmosphere to expel liquids accumulated in the tubing, 
install a recording flow meter on the vent line used to vent gas from 
the well (e.g., on the vent line off the wellhead separator or 
atmospheric storage tank) according to methods set forth in Sec.  
98.234(b). Calculate the total emissions from well venting to the 
atmosphere for liquids unloading using Equation W-7A of this section. 
Equation W-7A must be used for each unloading type combination 
(automated plunger lift unloadings, manual plunger lift unloadings, 
automated unloadings without plunger lifts and manual unloadings 
without plunger lifts) for any tubing diameter group and pressure group 
combination in each sub-basin.
[GRAPHIC] [TIFF OMITTED] TP01AU23.011

Where:

Ea = Annual natural gas emissions for each well of the 
same tubing diameter group and pressure group combination in the 
sub-basin at actual conditions, a, in

[[Page 50391]]

cubic feet. Calculate emissions from wells with automated plunger 
lift unloadings, wells with manual plunger lift unloadings, wells 
with automated unloadings without plunger lifts and wells with 
manual unloadings without plunger lifts separately.
FR = Average flow rate in cubic feet per hour for all measured wells 
of the same tubing diameter group and pressure group combination in 
a sub-basin, over the duration of the liquids unloading, under 
actual conditions as determined in paragraph (f)(1)(i) of this 
section.
Tp = Cumulative amount of time in hours of venting for 
each well, p, of the same tubing diameter group and pressure group 
combination in a sub-basin during the year. If the available venting 
data do not contain a record of the date of the venting events and 
data are not available to provide the venting hours for the specific 
time period of January 1 to December 31, you may calculate an 
annualized vent time, Tp, using Equation W-7B of this section.

[GRAPHIC] [TIFF OMITTED] TP01AU23.012

Where:

HRp = Cumulative amount of time in hours of venting for 
each well, p, during the monitoring period.
MPp = Time period, in days, of the monitoring period for 
each well, p. A minimum of 300 days in a calendar year are required. 
The next period of data collection must start immediately following 
the end of data collection for the previous reporting year.
Dp = Time period, in days during which the well, p, was 
in production (365 if the well was in production for the entire 
year).

    (i) Determine the well vent average flow rate (``FR'' in Equation 
W-7A of this section) as specified in paragraphs (f)(1)(i)(A) through 
(C) of this section for at least one well in a unique well tubing 
diameter group and pressure group combination in each sub-basin 
category. Calculate emissions from wells with automated plunger lift 
unloadings, wells with manual plunger lift unloadings, wells with 
automated unloadings without plunger lifts and wells with manual 
unloadings without plunger lifts separately.
    (A) Calculate the average flow rate per hour of venting for each 
unique tubing diameter group and pressure group combination in each 
sub-basin category by dividing the recorded total annual flow by the 
recorded time (in hours) for all measured liquid unloading events with 
venting to the atmosphere or a control device.
    (B) Apply the average hourly flow rate calculated under paragraph 
(f)(1)(i)(A) of this section to each well in the same pressure group 
that have the same tubing diameter group, for the number of hours of 
each well is vented.
    (C) If using Calculation Method 1 more frequently than once every 3 
years, you must calculate a new average flow rate each calendar year 
that you use Calculation Method 1. For a new producing sub-basin 
category, calculate an average flow rate beginning in the first year of 
production.
    (ii) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (2) Calculation Method 2. Calculate the total emissions for each 
well from manual and automated well venting to the atmosphere for 
liquids unloading without plunger lift assist using Equation W-8 of 
this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.013

Where:

Es = Annual natural gas emissions for each well at 
standard conditions, s, in cubic feet per year
Np = Total number of unloading events in the monitoring 
period per well, p.
0.37 x 10-\3\ = {3.14 (pi)/4{time} /{14.7*144{time}  
(psia converted to pounds per square feet).
CDp = Casing internal diameter for well, p, in inches.
WDp = Well depth from either the top of the well or the 
lowest packer to the bottom of the well, for well, p, in feet.
    SPp = For well, p, shut-in pressure or surface 
pressure for wells with tubing production, or casing pressure for 
each well with no packers, in pounds per square inch absolute 
(psia). If casing pressure is not available for the well, you may 
determine the casing pressure by multiplying the tubing pressure of 
the well with a ratio of casing pressure to tubing pressure from a 
well in the same sub-basin for which the casing pressure is known. 
The tubing pressure must be measured during gas flow to a flow-line. 
The shut-in pressure, surface pressure, or casing pressure must be 
determined just prior to liquids unloading when the well production 
is impeded by liquids loading or closed to the flow-line by surface 
valves.
SFRp = Average flow-line rate of gas for well, p, at 
standard conditions in cubic feet per hour. Use Equation W-33 of 
this section to calculate the average flow-line rate at standard 
conditions.
HRp,q = Hours that well, p, was left open to the 
atmosphere during each unloading event, q.
1.0 = Hours for average well to blowdown casing volume at shut-in 
pressure.
q = Unloading event.
Zp,q = If HRp,q is less than 1.0 then 
Zp,q is equal to 0. If HRp,q is greater than 
or equal to 1.0 then Zp,q is equal to 1.

    (3) Calculation Method 3. Calculate the total emissions for each 
sub-basin from well venting to the atmosphere for liquids unloading 
with plunger lift assist using Equation W-9 of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.014


[[Page 50392]]


Where:

Es = Annual natural gas emissions for each well at 
standard conditions, s, in cubic feet per year.
Np = Total number of unloading events in the monitoring 
period per well, p.
0.37 x 10-\3\ = {3.14 (pi)/4{time} /{14.7*144{time}  
(psia converted to pounds per square feet).
TDp = Tubing internal diameter for well, p, in inches.
WDp = Tubing depth to plunger bumper for well, p, in 
feet.
SPp = Flow-line pressure for well p in pounds per square 
inch absolute (psia), using engineering estimate based on best 
available data.
SFRp = Average flow-line rate of gas for well, p, at 
standard conditions in cubic feet per hour. Use Equation W-33 of 
this section to calculate the average flow-line rate at standard 
conditions.
HRp,q = Hours that well, p, was left open to the 
atmosphere during each unloading event, q.
0.5 = Hours for average well to blowdown tubing volume at flow-line 
pressure.
q = Unloading event.
Zp,q = If HRp,q is less than 0.5 then 
Zp,q is equal to 0. If HRp,q is greater than 
or equal to 0.5 then Zp,q is equal to 1.

    (4) Volumetric and mass emissions. Calculate CH4 and 
CO2 volumetric and mass emissions from volumetric natural 
gas emissions using calculations in paragraphs (u) and (v) of this 
section.
* * * * *
    (g) Well venting during completions and workovers with hydraulic 
fracturing. Calculate annual volumetric natural gas emissions from gas 
well and oil well venting during completions and workovers involving 
hydraulic fracturing using Equation W-10A or Equation W-10B of this 
section. Equation W-10A applies to well venting when the gas flowback 
rate is measured from a specified number of example completions or 
workovers in a sub-basin and well type combination and Equation W-10B 
applies when the gas flowback vent or flare volume is measured for each 
completion or workover in a sub-basin and well type combination. 
Completion and workover activities are separated into two periods, an 
initial period when flowback is routed to open pits or tanks and a 
subsequent period when gas content is sufficient to route the flowback 
to a separator or when the gas content is sufficient to allow 
measurement by the devices specified in paragraph (g)(1) of this 
section, regardless of whether a separator is actually utilized. If you 
elect to use Equation W-10A, you must follow the procedures specified 
in paragraph (g)(1) of this section. If you elect to use Equation W-
10B, you must use a recording flow meter installed on the vent line, 
downstream of a separator and ahead of a flare or vent, to measure the 
gas flowback. For either equation, emissions must be calculated 
separately for completions and workovers, for each sub-basin, and for 
each well type combination identified in paragraph (g)(2) of this 
section. You must calculate CH4 and CO2 
volumetric and mass emissions as specified in paragraph (g)(3) of this 
section. If emissions from well venting during completions and 
workovers with hydraulic fracturing are routed to a flare, you must 
calculate CH4, CO2, and N2O annual 
emissions as specified in paragraph (n) of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.015

[GRAPHIC] [TIFF OMITTED] TP01AU23.016

Where:

Es,n = Annual volumetric natural gas emissions in 
standard cubic feet from gas venting during well completions or 
workovers following hydraulic fracturing for each well.
CW = Total number of completions or workovers using hydraulic 
fracturing for each well, p.
Tp,s,cw = Cumulative amount of time of flowback, after 
sufficient quantities of gas are present to enable separation, where 
gas vented or flared for each completion or workover, in hours, for 
each well, p, during the reporting year. This may include non-
contiguous periods of venting or flaring.
Tp,i,cw = Cumulative amount of time of flowback to open 
tanks/pits, from when gas is first detected until sufficient 
quantities of gas are present to enable separation, for each 
completion or workover, in hours, for each well, p, during the 
reporting year. This may include non-contiguous periods of routing 
to open tanks/pits but does not include periods when the oil well 
ceases to produce fluids to the surface.
FRMs = Ratio of average gas flowback, during the period 
when sufficient quantities of gas are present to enable separation, 
of well completions and workovers from hydraulic fracturing to 30-
day production rate for the sub-basin and well type combination, 
calculated using procedures specified in paragraph (g)(1)(iii) of 
this section.
FRMi = Ratio of initial gas flowback rate during well 
completions and workovers from hydraulic fracturing to 30-day gas 
production rate for the sub-basin and well type combination, 
calculated using procedures specified in paragraph (g)(1)(iv) of 
this section, for the period of flow to open tanks/pits.
PRs,p,cw = Average gas production flow rate during the 
first 30 days of production after each completion of a newly drilled 
well or well workover using hydraulic fracturing in standard cubic 
feet per hour of each well p, that was measured in the sub-basin and 
well type combination. If applicable, PRs,p,cw may be 
calculated for oil wells using procedures specified in paragraph 
(g)(1)(vii) of this section.
EnFs,p,cw = Volume of N2 injected gas in cubic 
feet at standard conditions that was injected into the reservoir 
during an energized fracture job or during flowback during each 
completion or workover for each well, p, as determined by using an 
appropriate meter according to methods described in Sec.  98.234(b), 
or by using receipts of gas purchases that are used for the 
energized fracture job or injection during flowback. Convert to 
standard conditions using paragraph (t) of this section. If the 
fracture process did not inject gas into the reservoir or if the 
injected gas is CO2 then EnFs,p,cw is 0.
FVs,p,cw = Flow volume of vented or flared gas for each 
completion or workover at each well, p, in standard cubic feet 
measured using a recording flow meter (digital or analog) on the 
vent line to measure gas flowback during the separation period of 
the completion or workover according to methods set forth in Sec.  
98.234(b).
FRp,i,cw = Flow rate vented or flared of each completion 
or workover for each well, p, in standard cubic feet per hour 
measured using a recording flow meter (digital or analog) on the 
vent line to measure the flowback, at the beginning of the period of 
time when sufficient quantities of gas are present to enable 
separation, of the completion or workover according to methods set 
forth in Sec.  98.234(b).


[[Page 50393]]


    (1) If you elect to use Equation W-10A of this section on gas 
wells, you must use Calculation Method 1 as specified in paragraph 
(g)(1)(i) of this section to determine the value of FRMs and 
FRMi. These values must be based on the flow rate for 
flowback gases, once sufficient gas is present to enable separation. 
The number of measurements or calculations required to estimate 
FRMs and FRMi must be determined individually for 
completions and workovers per sub-basin and well type combination as 
follows: Complete measurements or calculations for at least one 
completion or workover for less than or equal to 25 completions or 
workovers for each well type combination within a sub-basin; complete 
measurements or calculations for at least two completions or workovers 
for 26 to 50 completions or workovers for each sub-basin and well type 
combination; complete measurements or calculations for at least three 
completions or workovers for 51 to 100 completions or workovers for 
each sub-basin and well type combination; complete measurements or 
calculations for at least four completions or workovers for 101 to 250 
completions or workovers for each sub-basin and well type combination; 
and complete measurements or calculations for at least five completions 
or workovers for greater than 250 completions or workovers for each 
sub-basin and well type combination.
* * * * *
    (iii) * * *

FRs,p = Measured average gas flowback rate from Calculation 
Method 1 described in paragraph (g)(1)(i) of this section, during the 
separation period in standard cubic feet per hour for well(s) p for 
each sub-basin and well type combination. Convert measured 
FRa values from actual conditions upstream of the 
restriction orifice (FRa) to standard conditions 
(FRs,p) for each well p using Equation W-33 in paragraph (t) 
of this section. You may not use flow volume as used in Equation W-10B 
of this section converted to a flow rate for this parameter.
* * * * *
N = Number of measured well completions or workovers using hydraulic 
fracturing in a sub-basin and well type combination.

    (iv) * * *

FRi,p = Initial measured gas flowback rate from Calculation 
Method 1 described in paragraph (g)(1)(i) of this section in standard 
cubic feet per hour for well(s), p, for each sub-basin and well type 
combination. Measured FRi,p values must be based on flow 
conditions at the beginning of the separation period and must be 
expressed at standard conditions.
* * * * *
N = Number of measured well completions or workovers using hydraulic 
fracturing in a sub-basin and well type combination.
* * * * *
    (h) Gas well venting during completions and workovers without 
hydraulic fracturing. Calculate annual volumetric natural gas emissions 
from each gas well venting during workovers without hydraulic 
fracturing using Equation W-13A of this section. Calculate annual 
volumetric natural gas emissions from each gas well venting during 
completions without hydraulic fracturing using Equation W-13B of this 
section. You must convert annual volumetric natural gas emissions to 
CH4 and CO2 volumetric and mass emissions as 
specified in paragraph (h)(1) of this section. If emissions from gas 
well venting during completions and workovers without hydraulic 
fracturing are routed to a flare, you must calculate CH4, 
CO2, and N2O annual emissions as specified in 
paragraph (n) of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.017

[GRAPHIC] [TIFF OMITTED] TP01AU23.018

Where:

Es,wo = Annual volumetric natural gas emissions in 
standard cubic feet from gas well venting during well workovers 
without hydraulic fracturing.
Nwo = Number of workovers per well that do not involve 
hydraulic fracturing in the reporting year.
EFwo = Emission factor for non-hydraulic fracture well 
workover venting in standard cubic feet per workover. Use 3,114 
standard cubic feet natural gas per well workover without hydraulic 
fracturing.
Es,p = Annual volumetric natural gas emissions in 
standard cubic feet from gas well venting during well completions 
without hydraulic fracturing.
Vp = Average daily gas production rate in standard cubic 
feet per hour for each well, p, undergoing completion without 
hydraulic fracturing. This is the total annual gas production volume 
divided by total number of hours the well produced to the flow-line. 
For completed wells that have not established a production rate, you 
may use the average flow rate from the first 30 days of production. 
In the event that the well is completed less than 30 days from the 
end of the calendar year, the first 30 days of the production 
straddling the current and following calendar years shall be used.
Tp = Time that gas is vented to either the atmosphere or 
a flare for each well, p, undergoing completion without hydraulic 
fracturing, in hours during the year.
* * * * *
    (i) * * *
    (2) Method for determining emissions from blowdown vent stacks 
according to equipment or event type. If you elect to determine 
emissions according to each equipment or event type, using unique 
physical volumes as calculated in paragraph (i)(1) of this section, you 
must calculate emissions as specified in paragraph (i)(2)(i) of this 
section and either paragraph (i)(2)(ii) of this section or, if 
applicable, paragraph (i)(2)(iii) of this section for each equipment or 
event type. Categorize equipment and event types for each industry 
segment as specified in paragraph (i)(2)(iv) of this section.
    (i) * * *

Ta = Temperature at actual conditions in the unique physical 
volume ([deg]F). For emergency blowdowns at onshore petroleum and 
natural gas production, onshore petroleum and natural gas gathering and 
boosting facilities, onshore natural gas transmission pipeline 
facilities, and natural gas distribution facilities, engineering 
estimates based on best available information may be used to determine 
the temperature.
* * * * *
Pa = Absolute pressure at actual conditions in the unique 
physical volume (psia). For emergency blowdowns at onshore petroleum 
and natural gas production, onshore petroleum and natural gas gathering 
and boosting facilities, onshore natural gas transmission pipeline

[[Page 50394]]

facilities, and natural gas distribution facilities, engineering 
estimates based on best available information may be used to determine 
the pressure.
* * * * *
Ta,p = Temperature at actual conditions in the unique 
physical volume ([deg]F) for each blowdown ``p''. For emergency 
blowdowns at onshore petroleum and natural gas production, onshore 
petroleum and natural gas gathering and boosting facilities, onshore 
natural gas transmission pipeline facilities, and natural gas 
distribution facilities, engineering estimates based on best available 
information may be used to determine the temperature.
* * * * *
Pa,b,p = Absolute pressure at actual conditions in the 
unique physical volume (psia) at the beginning of the blowdown ``p''. 
For emergency blowdowns at onshore petroleum and natural gas 
production, onshore petroleum and natural gas gathering and boosting 
facilities, onshore natural gas transmission pipeline facilities, and 
natural gas distribution facilities, engineering estimates based on 
best available information may be used to determine the pressure at the 
beginning of the blowdown.
Pa,e,p = Absolute pressure at actual conditions in the 
unique physical volume (psia) at the end of the blowdown ``p''; 0 if 
blowdown volume is purged using non-GHG gases. For emergency blowdowns 
at onshore petroleum and natural gas production, onshore petroleum and 
natural gas gathering and boosting facilities, onshore natural gas 
transmission pipeline facilities, and natural gas distribution 
facilities, engineering estimates based on best available information 
may be used to determine the pressure at the end of the blowdown.
* * * * *
    (iv) Categorize blowdown vent stack emission events as specified in 
paragraphs (i)(2)(iv)(A) and (B) of this section, as applicable.
    (A) For the onshore petroleum and natural gas production, onshore 
natural gas processing, onshore natural gas transmission compression, 
underground natural gas storage, LNG storage, LNG import and export 
equipment, and onshore petroleum and natural gas gathering and boosting 
industry segments, equipment or event types must be grouped into the 
following seven categories: Facility piping (i.e., physical volumes 
associated with piping for which the entire physical volume is located 
within the facility boundary), pipeline venting (i.e., physical volumes 
associated with pipelines for which a portion of the physical volume is 
located outside the facility boundary and the remainder, including the 
blowdown vent stack, is located within the facility boundary), 
compressors, scrubbers/strainers, pig launchers and receivers, 
emergency shutdowns (this category includes emergency shutdown blowdown 
emissions regardless of equipment type), and all other equipment with a 
physical volume greater than or equal to 50 cubic feet. If a blowdown 
event resulted in emissions from multiple equipment types and the 
emissions cannot be apportioned to the different equipment types, then 
categorize the blowdown event as the equipment type that represented 
the largest portion of the emissions for the blowdown event.
    (B) For the onshore natural gas transmission pipeline and natural 
gas distribution industry segments, pipeline segments or event types 
must be grouped into the following eight categories: Pipeline integrity 
work (e.g., the preparation work of modifying facilities, ongoing 
assessments, maintenance or mitigation), traditional operations or 
pipeline maintenance, equipment replacement or repair (e.g., valves), 
pipe abandonment, new construction or modification of pipelines 
including commissioning and change of service, operational precaution 
during activities (e.g. excavation near pipelines), emergency shutdowns 
including pipeline incidents as defined in 49 CFR 191.3, and all other 
pipeline segments with a physical volume greater than or equal to 50 
cubic feet. If a blowdown event resulted in emissions from multiple 
categories and the emissions cannot be apportioned to the different 
categories, then categorize the blowdown event in the category that 
represented the largest portion of the emissions for the blowdown 
event.
* * * * *
    (j) Hydrocarbon liquids and produced water storage tanks. Calculate 
CH4, CO2, and N2O (when flared) 
emissions from atmospheric pressure storage tanks receiving hydrocarbon 
liquids or produced water from onshore petroleum and natural gas 
production facilities, onshore petroleum and natural gas gathering and 
boosting facilities (including stationary liquid storage not owned or 
operated by the reporter), and onshore natural gas processing 
facilities as specified in this paragraph (j). For wells, gas-liquid 
separators, or onshore petroleum and natural gas gathering and boosting 
or onshore natural gas processing non-separator equipment (e.g., 
stabilizers, slug catchers) with annual average daily throughput of 
hydrocarbon liquids greater than or equal to 10 barrels per day, 
calculate annual CH4 and CO2 using Calculation 
Method 1 or 2 as specified in paragraphs (j)(1) and (2) of this 
section. For wells, gas-liquid separators, or non-separator equipment 
with annual average daily throughput of hydrocarbon liquids greater 
than 0 barrels per day and less than 10 barrels per day, calculate 
annual CH4 and CO2 emissions using Calculation 
Method 1, 2, or 3 as specified in paragraphs (j)(1) through (3) of this 
section. Annual average daily throughput of hydrocarbon liquids should 
be calculated using the flow out of the separator, well, or non-
separator equipment determined over the actual days of operation. For 
atmospheric pressure storage tanks receiving produced water, calculate 
annual CH4 emissions using Calculation Method 1, 2, or 3 as 
specified in paragraphs (j)(1) through (3) of this section. If you are 
required to or elect to use the method in paragraph (j)(1) of this 
section, you must use the results of the model to determine annual 
CH4 and, if applicable, CO2 emissions. If you use 
Calculation Method 1 or Calculation Method 2 for gas-liquid separators, 
you must also calculate emissions that may have occurred due to dump 
valves not closing properly using the method specified in paragraph 
(j)(5) of this section. If emissions from atmospheric pressure storage 
tanks are routed to a vapor recovery system, you must calculate 
CH4 and CO2 annual emissions as specified in 
paragraph (j)(4) of this section. If emissions from atmospheric 
pressure storage tanks are routed to a flare, determine flared 
emissions in accordance with the methodology specified in paragraph (n) 
of this section and report emissions from the flare as specified in 
Sec.  98.236(n). For atmospheric pressure storage tanks routing 
emissions to a vapor recovery system or a flare, calculate annual 
emissions vented directly to atmosphere as specified in paragraph 
(j)(4) of this section.
    (1) Calculation Method 1. For atmospheric pressure storage tanks 
receiving hydrocarbon liquids, calculate annual CH4 and 
CO2 emissions using operating conditions in the well, last 
gas-liquid separator, or last non-separator equipment before liquid 
transfer to storage tanks. For atmospheric pressure storage tanks 
receiving produced water, calculate annual CH4 emissions 
using operating

[[Page 50395]]

conditions in the well, last gas-liquid separator, or last non-
separator equipment before liquid transfer to storage tanks. Calculate 
flashing emissions with a software program, such as AspenTech 
HYSYS[supreg], Bryan Research & Engineering ProMax[supreg], or, for 
atmospheric pressure storage tanks receiving hydrocarbon liquids from 
gas-liquid separator or non-separator equipment, API 4697 E&P Tank, 
that uses the Peng-Robinson equation of state, models flashing 
emissions, and speciates CH4 and CO2 emissions 
that will result when the hydrocarbon liquids or produced water from 
the well, separator, or non-separator equipment enter an atmospheric 
pressure storage tank. If you elect to use ProMax[supreg], you must use 
version 5.0 or above. A minimum of the parameters listed in paragraphs 
(j)(1)(i) through (vii) of this section, as applicable, must be used to 
characterize emissions. If paragraphs (j)(1)(i) through (vii) of this 
section indicates that an applicable parameter must be measured, 
collect measurements reflective of representative operating conditions 
for the time period covered by the simulation. Determine all other 
applicable parameters in paragraphs (j)(1)(i) through (vii) of this 
section by engineering estimate and process knowledge based on best 
available data and, if necessary, adjust parameters to represent the 
operating conditions over the time period covered by the simulation. 
Determine the number of simulations and associated time periods such 
that the simulations cover the entire reporting year (i.e., if you 
calculate emissions using one simulation, use representative parameters 
for the operating conditions over the calendar year; if you use 
periodic simulations to cover the calendar year, use parameters for the 
operating conditions over each corresponding appropriate portion of the 
calendar year).
    (i) Well, separator, or non-separator equipment temperature (must 
be measured).
    (ii) Well, separator, or non-separator equipment pressure (must be 
measured).
    (iii) For atmospheric pressure storage tanks receiving hydrocarbon 
liquids, sales or stabilized hydrocarbon liquids API gravity (must be 
measured).
    (iv) Sales or stabilized hydrocarbon liquids or produced water 
production rate (must be measured).
    (v) Ambient air temperature.
    (vi) Ambient air pressure.
    (vii) Well, separator, or non-separator equipment hydrocarbon 
liquids or produced water composition and Reid vapor pressure (must be 
measured). Use an appropriate standard method published by a consensus-
based standards organization if such a method exists or you may use an 
industry standard practice as specified in Sec.  98.234(b) to sample 
and analyze hydrocarbon liquids or produced water composition and Reid 
vapor pressure.
    (2) Calculation Method 2. For atmospheric pressure storage tanks 
receiving hydrocarbon liquids, calculate annual CH4 and 
CO2 emissions using the methods in paragraph (j)(2)(i) of 
this section. For atmospheric pressure storage tanks receiving produced 
water, calculate annual CH4 emissions using the methods in 
paragraph (j)(2)(i) of this section.
    (i) Assume that all of the CH4 and, if applicable, 
CO2 in solution at well, separator, or non-separator 
equipment temperature and pressure is emitted from hydrocarbon liquids 
or produced water sent to atmosphere pressure storage tanks. You may 
use an appropriate standard method published by a consensus-based 
standards organization if such a method exists or you may use an 
industry standard practice as described in Sec.  98.234(b) to sample 
and analyze hydrocarbon liquids or produced water composition at well, 
separator, or non-separator pressure and temperature.
    (ii) [Reserved]
    (3) Calculation Method 3. Calculate CH4 and 
CO2 emissions from atmospheric pressure storage tanks 
receiving hydrocarbon liquids as specified in paragraph (j)(3)(i) of 
this section. Calculate CH4 emissions from atmospheric 
pressure storage tanks receiving produced water as specified in 
paragraph (j)(3)(ii) of this section.
    (i) Calculate CH4 and CO2 emissions from 
atmospheric pressure storage tanks receiving hydrocarbon liquids using 
Equation W-15A of this section:
[GRAPHIC] [TIFF OMITTED] TP01AU23.019

Where:

Es,i = Annual total volumetric GHG emissions (either 
CO2 or CH4) at standard conditions in cubic 
feet.
EFi = Population emission factor for separators, wells, 
or non-separator equipment in thousand standard cubic feet per 
separator, well, or non-separator equipment per year, for crude oil 
use 4.2 for CH4 and 2.8 for CO2 at 60 [deg]F 
and 14.7 psia, and for gas condensate use 17.6 for CH4 
and 2.8 for CO2 at 60 [deg]F and 14.7 psia.
Count = Total number of separators, wells, or non-separator 
equipment with annual average daily throughput greater than 0 
barrels per day and less than 10 barrels per day. Count only 
separators, wells, or non-separator equipment that feed hydrocarbon 
liquids directly to the atmospheric pressure storage tank for which 
you elect to use this Calculation Method 3.
1,000 = Conversion from thousand standard cubic feet to standard 
cubic feet.

    (ii) Calculate CH4 emissions from atmospheric pressure storage 
tanks receiving produced water using Equation W-15B of this section:
[GRAPHIC] [TIFF OMITTED] TP01AU23.020

Where:

MassCH4 = Annual total CH4 emissions in metric 
tons.
EFCH4 = Population emission factor for produced water in 
metric tons CH4 per thousand barrels produced water per 
year. For produced water streams from separators, wells, or non-
separator equipment with pressure less than or equal to 50 psi, use 
0.0015. For produced water streams from separators, wells, or non-
separator equipment with pressure greater than 50 but less than or 
equal to 250 psi, use 0.0142. For produced water streams from 
separators, wells, or non-separator equipment with pressure greater 
than 250 psi, use 0.0508. Pressure should be representative of 
separators, wells, or non-separator equipment that feed produced 
water directly to the atmosphere pressure storage tank.
FR = Annual flow rate of produced water to atmospheric pressure 
storage tanks, in barrels.
0.001 = Conversion from barrels to thousand barrels.

    (4) Routing to vapor recovery systems or flares. If the atmospheric 
pressure storage tank receiving your hydrocarbon liquids or produced 
water has a vapor recovery system or routes emissions to

[[Page 50396]]

a flare, calculate annual emissions vented directly to atmosphere from 
the storage tank during periods of time when emissions were not routed 
to the vapor recovery system or flare as specified in paragraph 
(j)(4)(i) of this section. Determine recovered mass as specified in 
paragraph (j)(4)(ii) of this section.
    (i) For an atmospheric pressure storage tank that routes any 
emissions to a vapor recovery system or a flare, calculate vented 
emissions as specified in paragraphs (j)(4)(i)(A) through (E) of this 
section.
    (A) Calculate maximum potential vented emissions as specified in 
paragraph (j)(1), (2), or (3) of this section, and calculate an average 
hourly vented emissions rate by dividing the maximum potential vented 
emissions by the number of hours that the tank was in operation.
    (B) To calculate vented emissions during periods when the tank was 
not routing emissions to a vapor recovery system or a flare, multiply 
the average hourly vented emissions rate determined in paragraph 
(j)(4)(i)(A) of this section by the number of hours that the tank 
vented directly to the atmosphere. Determine the number of hours that 
the tank vented directly to atmosphere by subtracting the hours that 
the tank was connected to a vapor recovery system or flare (based on 
engineering estimate and best available data) from the total operating 
hours for the tank in the calendar year. If emissions are routed to a 
flare but the flare is unlit, calculate emissions in accordance with 
the methodology specified in paragraph (n) of this section and report 
emissions from the flare as specified in Sec.  98.236(n).
    (C) During periods when a thief hatch is open or not properly 
seated and emissions from the tank are routed to a vapor recovery 
system or a flare, assume the capture efficiency of the vapor recovery 
system or a flare is 0 percent. To calculate vented emissions during 
such periods, multiply the average hourly vented emissions rate 
determined in paragraph (j)(4)(i)(A) of this section by the number of 
hours that the thief hatch is open or not properly seated. Determine 
the number of hours that the thief hatch is open or not properly seated 
as specified in paragraph (j)(7) of this section.
    (D) Calculate vented emissions not captured by the vapor recovery 
system or a flare due to causes other than open or not properly seated 
thief hatches based on best available data.
    (E) Calculate total emissions vented directly to atmosphere as the 
sum of the emissions calculated as specified in paragraphs (j)(4)(i)(B) 
through (D) of this section.
    (ii) Using engineering estimates based on best available data, 
determine the portion of the total emissions estimated in paragraphs 
(j)(1) through (3) of this section that is recovered using a vapor 
recovery system. You must take into account periods with reduced 
capture efficiency of the vapor recovery system (e.g., when a thief 
hatch is open or not properly seated) when calculating mass recovered 
as specified in paragraphs (j)(4)(i)(C) and (D) of this section.
    (5) Gas-liquid separator dump valves. If you use Calculation Method 
1 or Calculation Method 2 in paragraph (j)(1) or (2) of this section, 
calculate emissions from occurrences of gas-liquid separator liquid 
dump valves that did not close properly during the calendar year by 
using Equation W-16 of this section. Determine the total time a dump 
valve did not close properly in the calendar year (Tdv) as 
specified in paragraph (j)(5)(i) of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.021

Where:

Es,i,dv = Annual volumetric GHG emissions (either 
CO2 or CH4) at standard conditions in cubic 
feet from atmospheric pressure storage tanks that resulted from the 
dump valve on an associated gas-liquid separator that did not close 
properly.
CFdv = Correction factor for tank emissions for time 
period Tdv is 2.87 for crude oil production. Correction 
factor for tank emissions for time period Tdv is 4.37 for 
gas condensate production.
Es,i = Annual volumetric GHG emissions (either 
CO2 or CH4) as determined in paragraphs (j)(1) 
and (2) and, if applicable, (j)(4) of this section, in standard 
cubic feet per year, from atmospheric pressure storage tanks with 
dump valves on an associated gas-liquid separator that did not close 
properly.
8,760 = Conversion to hourly emissions.
Tdv = Total time a dump valve did not close properly in 
the calendar year as determined in paragraph (j)(5)(i) of this 
section, in hours.

    (i) You must perform a visual inspection of each gas-liquid 
separator liquid dump valve to determine if the valve is stuck in an 
open or partially open position, in accordance with paragraph 
(j)(5)(i)(A) and (B) of this section.
    (A) Visual inspections must be conducted at least once in a 
calendar year.
    (B) If stuck gas-liquid separator liquid dump valve is identified, 
the dump valve must be counted as being open since the beginning of the 
calendar year, or from the previous visual inspection that did not 
identify the dump valve as being stuck in the open position in the same 
calendar year. If the dump valve is fixed following visual inspection, 
the time period for which the dump valve was stuck open will end upon 
being repaired. If a stuck dump valve is identified and not repaired, 
the time period for which the dump valve was stuck open must be counted 
as having occurred through the rest of the calendar year.
    (ii) [Reserved]
    (6) Mass emissions. Calculate both CH4 and 
CO2 mass emissions from natural gas volumetric emissions 
using calculations in paragraph (v) of this section.
    (7) Thief hatches. If a thief hatch sensor is operating on a 
controlled atmospheric pressure storage tank, you must use data 
obtained from the thief hatch sensor to determine periods when the 
thief hatch is open or not properly seated. An applicable operating 
thief hatch sensor must be capable of transmitting and logging data 
whenever a thief hatch is open or not properly seated, as well as when 
the thief hatch is subsequently closed. If a thief hatch sensor is not 
operating, you must perform a visual inspection of each thief hatch on 
a controlled atmospheric pressure storage tank in accordance with 
paragraph (j)(7)(i) through (iii) of this section.
    (i) For thief hatches on atmospheric pressure storage tanks subject 
to the fugitive emissions standards for well sites, centralized 
production facilities, and compressor stations in Sec.  60.5397b of 
this chapter, or an applicable approved state plan or applicable 
Federal plan in part 62 of this chapter, visual inspections must be 
conducted at least as frequent as the required visual, audible, or 
olfactory fugitive emissions components surveys described in Sec.  
60.5397b or the applicable approved state plan or applicable Federal 
plan in

[[Page 50397]]

part 62. If the time between required visual, audible, or olfactory 
fugitive emissions components surveys described in Sec.  60.5397b or 
the applicable approved state plan or applicable Federal plan in part 
62 is greater than one year, visual inspections must be conducted at 
least annually.
    (ii) For thief hatches on atmospheric pressure storage tanks not 
subject to the fugitive emissions standards for well sites, centralized 
production facilities, and compressor stations in Sec.  60.5397b of 
this chapter, or an applicable approved state plan or applicable 
Federal plan in part 62 of this chapter, visual inspections must be 
conducted at least once in a calendar year.
    (iii) If one visual inspection is conducted in the calendar year, 
assume the thief hatch was open for the entire calendar year. If 
multiple visual inspections are conducted in the calendar year, assume 
a thief hatch found open in the first visual inspection was open since 
the beginning of the year until the date of the visual inspection; 
assume a thief hatch found open in the last visual inspection of the 
year was open from the preceding visual inspection through the end of 
the year; assume a thief hatch found open in a visual inspection 
between the first and last visual inspections of the year was open 
since the preceding visual inspection until the date of the visual 
inspection.
    (k) Condensate storage tanks. For vent stacks connected to one or 
more condensate storage tanks, either water or hydrocarbon, without 
vapor recovery, flares, or other controls, in onshore natural gas 
transmission compression or underground natural gas storage, calculate 
CH4 and CO2 annual emissions from compressor 
scrubber dump valve leakage as specified in paragraphs (k)(1) through 
(4) of this section.
* * * * *
    (l) Well testing venting and flaring. Calculate CH4 and 
CO2 annual emissions from well testing venting as specified 
in paragraphs (l)(1) through (5) of this section. If emissions from 
well testing venting are routed to a flare, you must calculate 
CH4, CO2, and N2O annual emissions as 
specified in paragraph (n) of this section.
* * * * *
    (3) Estimate venting emissions using Equation W-17A (for oil wells) 
or Equation W-17B (for gas wells) of this section for each well tested 
during the reporting year.
[GRAPHIC] [TIFF OMITTED] TP01AU23.022

[GRAPHIC] [TIFF OMITTED] TP01AU23.023

Where:

Ea,n = Annual volumetric natural gas emissions from well 
testing for each well being tested in cubic feet under actual 
conditions.
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil for 
each well being tested; oil here refers to hydrocarbon liquids 
produced of all API gravities.
FR = Average annual flow rate in barrels of oil per day for the oil 
well being tested.
PR = Average annual production rate in actual cubic feet per day for 
the gas well being tested.
D = Number of days during the calendar year that the well is tested.
* * * * *
    (m) Associated gas venting and flaring. Calculate CH4 
and CO2 annual emissions from associated gas venting not in 
conjunction with well testing (refer to paragraph (l) of this section) 
as specified in paragraphs (m)(1) through (4) of this section. If 
emissions from associated gas venting are routed to a flare, you must 
calculate CH4, CO2, and N2O annual 
emissions as specified in paragraph (n) of this section.
* * * * *
    (3) Estimate venting emissions using Equation W-18 of this section. 
Alternatively, if you measure the flow to a vent using a continuous 
flow measurement device, you must use the measured flow volumes to 
calculate vented associated gas emissions.
[GRAPHIC] [TIFF OMITTED] TP01AU23.024

Where:

Es,n,p = Annual volumetric natural gas emissions at each 
well from associated gas venting at standard conditions, in cubic 
feet.
GORp = Gas to oil ratio, for well p, in standard cubic 
feet of gas per barrel of oil; oil here refers to hydrocarbon 
liquids produced of all API gravities.
Vp = Volume of oil produced, for well p, in barrels in 
the calendar year only during time periods in which associated gas 
was vented or flared.
SGp = Volume of associated gas sent to sales or volume of 
associated gas used for other purposes at the facility site, 
including powering engines, separators, safety systems and/or 
combustion equipment and not flared or vented, for well p, in 
standard cubic feet of gas in the calendar year only during time 
periods in which associated gas was vented or flared.
* * * * *
    (n) Flare stack emissions. Except as specified in paragraph (n)(9) 
of this section, calculate CO2, CH4, and 
N2O emissions from each flare stack as specified in 
paragraphs (n)(1) through (8) of this section. For each flare, 
disaggregate the total flared emissions to applicable source types as 
specified in paragraph (n)(10) of this section.
    (1) Flow measurement. Measure total flow to the flare as specified 
in either paragraph (n)(1)(i) or (ii) of this section.
    (i) Use a continuous parameter monitoring system for measuring the 
flow of gas to the flare downstream of any sweep, purge, or auxiliary 
gas addition. You may use direct flow meters or other parameter 
monitoring systems combined with engineering calculations, such as line 
pressure and burner nozzle dimensions, to satisfy this requirement. The 
continuous parameter monitoring system must measure data values at 
least once every hour.
    (ii) Use a continuous parameter monitoring system for measuring the 
flow of gas from each source that routes gas to the flare, including 
purge gas, sweep gas, and auxiliary fuel. You may use direct flow 
meters or other parameter monitoring systems combined with engineering

[[Page 50398]]

calculations, such as line pressure and burner nozzle dimensions, to 
satisfy this requirement. If the emission streams for multiple sources 
are routed to a manifold before being combined with other emission 
streams, you may conduct the measurement in the manifold instead of 
from each source that is routed to the manifold.
    (2) Pilot. Continuously monitor for the presence of a pilot flame 
or combustion flame as specified in paragraph (n)(2)(i) of this section 
or visually inspect for the presence of a pilot flame or combustion 
flame as specified in paragraph (n)(2)(ii) of this section. If you 
continuously monitor, then periods when the flare are unlit must be 
determined based on those data.
    (i) At least once every five minutes monitor for the presence of a 
pilot flame or combustion flame using a device (including, but not 
limited to, a thermocouple, ultraviolet beam sensor, or infrared 
sensor) capable of detecting that the pilot or combustion flame is 
present at all times. Continuous monitoring systems used for the 
presence of a pilot flame or combustion flame are not subject to a 
minimum accuracy requirement beyond being able to detect the presence 
or absence of a flame and are exempt from the calibration requirements 
of this part 98. Track the length of time over all periods when the 
flare is unlit. Use the measured flow during these time periods, as 
determined from measurements obtained under paragraph (n)(1) of this 
section, to calculate the fraction of the total annual volume that is 
routed to the flare when it is unlit. If the monitoring device is out 
of service for more than one week, then visually inspect for the 
presence of a pilot flame or combustion flame at least once per week 
for the first 4 weeks that a monitoring device is out of service or 
until a repaired or new device is operational, whichever period is 
shorter. If the continuous monitoring device is out of service for less 
than one week, then at least one visual inspection must be conducted 
during the outage. If a flame is not detected during a weekly visual 
inspection, assume the pilot has been unlit since the previous 
inspection or the last time the continuous monitoring device detected a 
flame, and assume that the pilot remains unlit until a subsequent 
inspection or continuous monitoring device detects a flame. If the 
monitoring device outage lasts more than 4 weeks, then you may switch 
to conducting inspections at least once per month in accordance with 
paragraph (n)(2)(ii) of this section.
    (ii) At least once per month visually inspect for the presence of a 
pilot flame or combustion flame. If a flame is not detected, assume the 
pilot has been unlit since the previous inspection and that it remains 
unlit until a subsequent inspection detects a flame. Use the sum of the 
measured flows, as determined from measurements obtained under 
paragraph (n)(1) of this section, during all time periods when the 
pilot was determined to be unlit, to calculate the fraction of the 
total annual volume that is routed to the flare when it is unlit.
    (3) Gas composition. Determine the composition of the inlet gas to 
the flare as specified in either paragraph (n)(3)(i), (ii), (iii), or 
(iv) of this section.
    (i) Use a continuous gas composition analyzer on the inlet gas to 
the flare burner downstream of any purge, sweep, or auxiliary fuel 
addition to determine the annual average mole fractions of methane, 
ethane, propane, butane, pentanes plus, and CO2.
    (ii) Take samples of the inlet gas to the flare burner downstream 
of any purge, sweep, or auxiliary fuel addition at least once every 
quarter in which gas is routed to the flare and analyze for methane, 
ethane, propane, butane, pentanes plus, and CO2 
constituents, Determine the annual average concentration of each 
constituent as the flow-weighted annual average of all measurements for 
that constituent during the year.
    (iii) Use a continuous gas composition analyzer on the emissions 
streams from each emission source that routes gas to the flare. Also 
take samples of purge gas, sweep gas, and auxiliary fuel at least 
annually, and analyze for methane ethane, propane, butane, pentanes 
plus, and CO2. If the emission streams for multiple sources 
are routed to a manifold before being combined with other emission 
streams, you may measure gas composition in the manifold instead of 
from each source that is routed to the manifold. Determine the flow-
weighted annual average concentration of each constituent.
    (iv) Take samples of the emission streams from each source that 
routes gas to the flare at least once every quarter in which gas is 
routed to the flare and analyze for methane, ethane, propane, butane, 
pentanes plus, and CO2. Also take samples of purge gas, 
sweep gas, and auxiliary fuel at least annually, and analyze for 
methane, ethane, propane, butane, pentanes plus, and CO2. If 
the emission streams for multiple sources are routed to a manifold 
before being combined with other emission streams, you may measure gas 
composition in the manifold instead of from each source that is routed 
to the manifold. Determine the annual average concentration of each 
constituent in each stream as the flow-weighted average of all 
measurements for that constituent during the year.
    (4) Combustion efficiency. Use the applicable default combustion 
efficiency specified in paragraphs (n)(4)(i) through (iii) of this 
section. If you change the Tier with which you comply during a year, 
then use the applicable default combustion efficiencies in paragraphs 
(n)(4)(i) through (iii) of this section for portions of the year during 
which the different monitoring methodologies were used, and calculate a 
time-weighted average combustion efficiency to report for the flare.
    (i) Tier 1. If you monitor the flare as specified in Sec.  63.670 
and Sec.  63.671 of this chapter, then use a default combustion 
efficiency of 98 percent. The alternative means of emissions limitation 
specified in Sec.  63.670(r) of this chapter do not apply for the 
purposes of this paragraph (n). References to deviations in Sec.  
63.670(b) of this chapter do not apply for the purposes of this 
paragraph (n). References to refineries or refinery process units in 
Sec.  63.670 of this chapter mean facilities in any of the industry 
segments specified in Sec.  98.230 for the purposes of this paragraph 
(n). Reporting requirements in Sec.  63.670(q) of this chapter mean 
recordkeeping requirements for the purposes of this paragraph (n).
    (ii) Tier 2. If you are required to monitor the flare as specified 
in Sec.  60.5417b(d)(1)(viii) of this chapter, or you elect to 
implement the flare monitoring requirements in Sec.  
60.5417b(d)(1)(viii) of this chapter, then use a default combustion 
efficiency of 95 percent. The exemptions from monitoring gas flow in 
Sec.  60.5417b(d)(1)(viii)(D)(1) through (4) of this chapter do not 
apply for the purposes of this paragraph (n).
    (iii) Tier 3. If you do not monitor the flare as specified in 
either paragraph (n)(4)(i) or (ii) of this section, then use a default 
combustion efficiency of 92 percent.
    (5) Calculate CH4 and CO2 emissions. 
Calculate GHG volumetric emissions from flaring at standard conditions 
using Equations W-19 and W-20 of this section and as specified in 
paragraphs (n)(5)(i) through (iv) of this section.

[[Page 50399]]

[GRAPHIC] [TIFF OMITTED] TP01AU23.025

[GRAPHIC] [TIFF OMITTED] TP01AU23.026

Where:

Es,CH4 = Annual CH4 emissions from 
flare stack in cubic feet, at standard conditions.
Es,CO2 = Annual CO2 emissions from 
flare stack in cubic feet, at standard conditions.
Vs = Volume of gas sent to flare in standard cubic feet, 
during the year as determined in paragraph (n)(1) of this section.
[eta] = Flare combustion efficiency, expressed as fraction of gas 
combusted by a burning flare.
XCH4 = Annual average mole fraction of CH4 in 
the feed gas to the flare or in each of the streams routed to the 
flare as determined in paragraph (n)(3) of this section.
XCO2 = Annual average mole fraction of CO2 in 
the feed gas to the flare or in each of the streams routed to the 
flare as determined in paragraph (n)(3) of this section.
ZU = Fraction of the feed gas sent to an un-lit flare 
determined from both the total time the flare was unlit as 
determined by monitoring the pilot flame or combustion flame as 
specified in paragraph (n)(2) of this section and the volume of gas 
routed to the flare during periods when the flare was unlit as 
determined by the flow measurement required by paragraph (n)(1) of 
this section.
ZL = Fraction of the feed gas sent to a burning flare 
(equal to 1-ZU).
Yj = Annual average mole fraction of hydrocarbon 
constituents j (such as methane, ethane, propane, butane, and 
pentanes-plus) in the feed gas to the flare or in each of the 
streams routed to the flare as determined in paragraph (n)(3) of 
this section.
Rj = Number of carbon atoms in the hydrocarbon 
constituent j in the feed gas to the flare: 1 for methane, 2 for 
ethane, 3 for propane, 4 for butane, and 5 for pentanes-plus).

    (i) If you measure the gas flow at the flare inlet as specified in 
paragraph (n)(1)(i) of this section and you measure gas composition for 
the inlet gas to the flare as specified in paragraph (n)(3)(i) or (ii) 
of this section, then use those data in Equations W-19 and W-20 to 
calculate total emissions from the flare.
    (ii) If you measure the flow from each source as specified in 
paragraph (n)(1)(ii) of this section and you measure gas composition 
for the inlet gas to the flare as specified in paragraph (n)(3)(i) or 
(ii) of this section, then sum the flows for each stream to calculate 
the total annual gas flow to the flare. Use that total annual flow with 
the annual average concentration of each constituent as calculated in 
paragraph (n)(3)(i) or (ii) of this section in Equations W-19 and W-20 
to calculate total emissions from the flare.
    (iii) If you measure the flow from each source as specified in 
paragraph (n)(1)(ii) of this section and you measure gas composition 
for the emission stream from each source as specified in paragraph 
(n)(3)(iii) or (iv) of this section, then calculate total emissions 
from the flare as specified in either paragraph (n)(5)(iii)(A) or (B) 
of this section.
    (A) Use each set of stream-specific flow and annual average 
concentration data in Equations W-19 and W-20 to calculate stream-
specific flared emissions for each stream, and then sum the results 
from each stream-specific calculation to calculate the total emissions 
from the flare.
    (B) Sum the flows from each source to calculate the total gas flow 
into the flare and use the source-specific flows and source-specific 
annual average concentrations to determine flow-weighted annual average 
concentrations of CO2 and hydrocarbon constituents in the 
combined gas stream into the flare. Use the calculated total gas flow 
and the calculated flow-weighted annual average concentrations for the 
inlet gas stream to the flare in Equations W-19 and W-20 to calculate 
the total emissions from the flare.
    (iv) You may not combine measurement of the inlet gas flow to the 
flare as specified in paragraph (n)(1)(i) of this section with 
measurement of the gas composition of the streams from each source as 
specified in paragraph (n)(3)(iii) or (iv) of this section.
    (6) Convert volume at actual conditions to volume at standard 
conditions. Convert GHG volumetric emissions to standard conditions 
using calculations in paragraph (t) of this section.
    (7) Convert volumetric emissions to mass emissions. Calculate both 
CH4 and CO2 mass emissions from volumetric 
emissions using calculation in paragraph (v) of this section.
    (8) Calculate N2O emissions. Calculate N2O emissions 
from flare stacks using Equation W-40 in paragraph (z) of this section. 
Determine higher heating values to use in Equation W-40 calculations as 
specified in paragraphs (n)(8)(i) through (iii) of this section, as 
applicable.
    (i) If you measure composition of the inlet gas to the flare as 
specified in either paragraph (n)(3)(i) or (ii) of this section, then 
calculate a flare-specific higher heating value to use in Equation W-40 
to calculate total N2O emissions from the flare.
    (ii) If you measure composition of the individual streams routed to 
the flare as specified in paragraph (n)(3)(iii) or (iv) of this 
section, and you calculate CH4 and CO2 emissions 
per stream as specified in paragraph (n)(5)(iii)(A) of this section, 
then calculate stream-specific higher heating values. Use the stream-
specific higher heating values in separate stream-specific calculations 
of N2O emissions and sum the resulting values to calculate 
the total N2O emissions from the flare.
    (iii) If you measure composition of the individual streams routed 
to the flare as specified in paragraph (n)(3)(iii) or (iv) of this 
section, and you calculate CH4 and CO2 emissions 
using flow-weighted annual average concentrations for the inlet gas to 
the flare as calculated according to paragraph (n)(5)(iii)(B) of this 
section, then either calculate higher heating values and N2O 
emissions as specified in paragraph (n)(8)(ii) of this section, or 
calculate a flare-specific higher heating value using the calculated 
flow-weighted composition of the inlet gas to the flare, and use this 
flare-specific higher heating value to calculate the total 
N2O emissions from the flare.
    (9) CEMS. If you operate and maintain a CEMS that has both a 
CO2 concentration monitor and volumetric flow rate monitor 
for the combustion gases from the flare, you must calculate 
CO2 emissions for the flare using the CEMS. You must follow 
the Tier 4 Calculation Method and all associated calculation, quality 
assurance, reporting, and recordkeeping requirements for Tier 4 in 
subpart C of this part (General Stationary Fuel Combustion Sources). If 
a CEMS is used to calculate flare stack CO2 emissions, you 
must also comply with all other requirements specified in paragraphs 
(n)(1) through (8) of this section, except that calculation of 
CO2 emissions using

[[Page 50400]]

Equation W-20 in paragraph (n)(5) of this section is not required.
    (10) Disaggregation. Using engineering calculations and best 
available data, disaggregate the total emissions from the flare as 
calculated in paragraphs (n)(7) and (8) of this section or paragraph 
(n)(9) of this section, as applicable, to each source type listed in 
paragraphs (n)(10)(i) through (viii) of this section, as applicable to 
the industry segment, that routed emissions to the flare.
    (i) Acid gas removal units.
    (ii) Dehydrators.
    (iii) Completions and workovers with hydraulic fracturing.
    (iv) Completions and workovers without hydraulic fracturing.
    (v) Hydrocarbon liquids and produced water storage tanks.
    (vi) Well testing.
    (vii) Associated gas.
    (viii) Other (collectively).
    (o) Centrifugal compressor venting. If you are required to report 
emissions from centrifugal compressor venting as specified in Sec.  
98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct 
volumetric emission measurements specified in paragraph (o)(1) of this 
section using methods specified in paragraphs (o)(2) through (5) of 
this section; perform calculations specified in paragraphs (o)(6) 
through (9) of this section; and calculate CH4 and 
CO2 mass emissions as specified in paragraph (o)(11) of this 
section. If you are required to report emissions from centrifugal 
compressor venting at an onshore petroleum and natural gas production 
facility as specified in Sec.  98.232(c)(19) or an onshore petroleum 
and natural gas gathering and boosting facility as specified in Sec.  
98.232(j)(8), you must calculate volumetric emissions as specified in 
paragraph (o)(10) of this section and calculate CH4 and 
CO2 mass emissions as specified in paragraph (o)(11) of this 
section. If emissions from a compressor source are routed to a flare, 
paragraphs (o)(1) through (11) of this section do not apply and instead 
you must calculate CH4, CO2, and N2O 
emissions as specified in paragraph (n) of this section. If emissions 
from a compressor source are routed to combustion, paragraphs (o)(1) 
through (11) of this section do not apply and instead you must 
calculate and report emissions as specified in subpart C of this part 
or paragraph (z) of this section, as applicable. If emissions from a 
compressor source are routed to a vapor recovery system, paragraphs 
(o)(1) through (11) of this section do not apply.
    (1) * * *
    (i) Centrifugal compressor source as found measurements. Measure 
venting from each compressor according to either paragraph 
(o)(1)(i)(A), (B), or (C) of this section at least once annually, based 
on the compressor mode (as defined in Sec.  98.238) in which the 
compressor was found at the time of measurement, except as specified in 
paragraph (o)(1)(i)(D) of this section. If additional measurements 
beyond the required annual testing are performed (including duplicate 
measurements or measurement of additional operating modes), then all 
measurements satisfying the applicable monitoring and QA/QC that is 
required by this paragraph (o) must be used in the calculations 
specified in this section.
    (A) For a compressor measured in operating-mode, you must measure 
volumetric emissions from blowdown valve leakage through the blowdown 
vent as specified in paragraph (o)(2)(i) of this section, measure 
volumetric emissions from wet seal oil degassing vents as specified in 
paragraph (o)(2)(ii) of this section if the compressor has wet seal oil 
degassing vents, and measure volumetric emissions from dry seal vents 
as specified in paragraph (o)(2)(iii) of this section if the compressor 
has dry seals.
    (B) For a compressor measured in not-operating-depressurized-mode, 
you must measure volumetric emissions from isolation valve leakage as 
specified in paragraph (o)(2)(i) of this section. If a compressor is 
not operated and has blind flanges in place throughout the reporting 
period, measurement is not required in this compressor mode.
    (C) For a compressor measured in standby-pressurized-mode, you must 
measure volumetric emissions from blowdown valve leakage through the 
blowdown vent as specified in paragraph (o)(2)(i) of this section, 
measure volumetric emissions from wet seal oil degassing vents as 
specified in paragraph (o)(2)(ii) of this section if the compressor has 
wet seal oil degassing vents, and measure volumetric emissions from dry 
seal vents as specified in paragraph (o)(2)(iii) of this section if the 
compressor has dry seals.
* * * * *
    (2) Methods for performing as found measurements from individual 
centrifugal compressor sources. If conducting measurements for each 
compressor source, you must determine the volumetric emissions from 
blowdown valves and isolation valves as specified in paragraph 
(o)(2)(i) of this section, the volumetric emissions from wet seal oil 
degassing vents as specified in paragraph (o)(2)(ii) of this section, 
and the volumetric emissions from dry seal vents as specified in 
paragraph (o)(2)(iii) of this section.
    (i) For blowdown valves on compressors in operating-mode or in 
standby-pressurized-mode and for isolation valves on compressors in 
not-operating-depressurized-mode, determine the volumetric emissions 
using one of the methods specified in paragraphs (o)(2)(i)(A) through 
(D) of this section.
* * * * *
    (ii) For wet seal oil degassing vents in operating-mode or in 
standby-pressurized-mode, determine volumetric flow at standard 
conditions, using one of the methods specified in paragraphs 
(o)(2)(ii)(A) through (C) of this section. You must quantitatively 
measure the volumetric flow for wet seal oil degassing vent; you may 
not use screening methods set forth in Sec.  98.234(a) to screen for 
emissions for the wet seal oil degassing vent.
    (A) Use a temporary meter such as a vane anemometer or permanent 
flow meter according to methods set forth in Sec.  98.234(b).
    (B) Use calibrated bags according to methods set forth in Sec.  
98.234(c).
    (C) Use a high volume sampler according to methods set forth in 
Sec.  98.234(d).
    (iii) For dry seal vents in operating-mode or in standby-
pressurized-mode, determine volumetric flow at standard conditions from 
each dry seal vent using one of the methods specified in paragraphs 
(o)(2)(iii)(A) through (D) of this section. If a compressor has more 
than one dry seal vent, determine the aggregate dry seal vent 
volumetric flow for the compressor as the sum of the volumetric flows 
determined for each dry seal vent on the compressor.
    (A) Use a temporary meter such as a vane anemometer or permanent 
flow meter according to methods set forth in Sec.  98.234(b).
    (B) Use calibrated bags according to methods set forth in Sec.  
98.234(c).
    (C) Use a high volume sampler according to methods set forth in 
Sec.  98.234(d).
    (D) You may choose to use any of the methods set forth in Sec.  
98.234(a)(1) through (3) to screen for emissions. If emissions are 
detected using one of these specified methods, then you must use one of 
the methods specified in paragraph (o)(2)(iii)(A) through (C) of this 
section. If emissions are not detected using the methods in Sec.  
98.234(a)(1) through (3), then you may assume that the volumetric 
emissions are zero. For the purposes of this paragraph, when using any 
of the

[[Page 50401]]

methods in Sec.  98.234(a), emissions are detected whenever a leak is 
detected according to the methods. Acoustic leak detection is only 
applicable for through-valve leakage and is not applicable for 
screening dry seal vents.
    (4) * * *
    (ii) * * *
    (E) You may choose to use any of the methods set forth in Sec.  
98.234(a)(1) through (3) to screen for emissions. If emissions are 
detected using one of these methods, then you must use one of the 
methods specified in paragraph (o)(4)(ii)(A) through (D) of this 
section. If emissions are not detected using the methods in Sec.  
98.234(a)(1) through (3), then you may assume that the volumetric 
emissions are zero. For the purposes of this paragraph, when using any 
of the methods in Sec.  98.234(a), emissions are detected whenever a 
leak is detected according to the method. Acoustic leak detection is 
only applicable for through-valve leakage and is not applicable for 
screening a manifolded group of compressor sources.
* * * * *
    (6) * * *
    (i) Using Equation W-21 of this section, calculate the annual 
volumetric GHG emissions for each centrifugal compressor mode-source 
combination specified in paragraphs (o)(1)(i)(A) through (C) of this 
section that was measured during the reporting year.
* * * * *
m = Compressor mode-source combination specified in paragraph 
(o)(1)(i)(A), (B), or (C) of this section that was measured for the 
reporting year.

    (ii) Using Equation W-22 of this section, calculate the annual 
volumetric GHG emissions from each centrifugal compressor mode-source 
combination specified in paragraphs (o)(1)(i)(A) through (C) of this 
section that was not measured during the reporting year.
* * * * *
m = Compressor mode-source combination specified in paragraph 
(o)(1)(i)(A), (B), or (C) of this section that was not measured in the 
reporting year.

    (iii) Using Equation W-23 of this section, develop an emission 
factor for each compressor mode-source combination specified in 
paragraphs (o)(1)(i)(A) through (C) of this section. These emission 
factors must be calculated annually and used in Equation W-22 of this 
section to determine volumetric emissions from a centrifugal compressor 
in the mode-source combinations that were not measured in the reporting 
year.
* * * * *
m = Compressor mode-source combination specified in paragraph 
(o)(1)(i)(A), (B), or (C) of this section.
* * * * *
    (8) * * *

Tg = Total time the manifolded group of compressor sources g 
had potential for emissions in the reporting year, in hours. Include 
all time during which at least one compressor source in the manifolded 
group of compressor sources g was in a mode-source combination 
specified in either paragraph (o)(1)(i)(A), (o)(1)(i)(B), (o)(1)(i)(C), 
(p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section. Default of 
8760 hours may be used.
* * * * *
    (10) Method for calculating volumetric GHG emissions from wet seal 
oil degassing vents at an onshore petroleum and natural gas production 
facility or an onshore petroleum and natural gas gathering and boosting 
facility. You must calculate volumetric emissions from centrifugal 
compressors at an onshore petroleum and natural gas production facility 
or an onshore petroleum and natural gas gathering and boosting facility 
as specified in paragraphs (o)(10)(i) through (iii), as applicable.
    (i) For centrifugal compressors at an onshore petroleum and natural 
gas production facility or an onshore petroleum and natural gas 
gathering and boosting facility that are subject to the centrifugal 
compressor standards in Sec.  60.5380b of this chapter or an applicable 
approved state plan or applicable Federal plan in part 62 of this 
chapter for dry seals and self-contained wet seals, you must conduct 
measurements according to paragraphs (o)(10)(i)(A) and (B) of this 
section.
    (A) You must conduct the volumetric emission measurements as 
required by Sec.  60.5380b(a)(5) of this chapter or an applicable 
approved state plan or applicable Federal plan in part 62 of this 
chapter, conduct any additional volumetric emission measurements 
specified in paragraph (o)(1) of this section using methods specified 
in paragraphs (o)(2) through (5) of this section, and calculate 
emissions as specified in paragraphs (o)(6) through (9) of this 
section. Conduct all measurements required by this paragraph 
(o)(10)(i)(A) at the frequency specified by Sec.  60.5380b(a)(4) of 
this chapter or an applicable approved state plan or applicable Federal 
plan in part 62 of this chapter. For any reporting year in which 
measuring at the frequency specified by Sec.  60.5380b(a)(4) of this 
chapter results in measurement not being required for a subject 
compressor, calculate emissions for all mode-source combinations as 
specified in paragraph (o)(6)(ii) of this section.
    (B) You must conduct measurements of compressors as specified in 
paragraph (o)(1)(i)(B) of this section such that at the end of each 
calendar year, you have taken measurements in not-operating-
depressurized-mode over the last 3 consecutive calendar years for at 
least one-third of the compressors at your facility that are subject to 
the centrifugal compressor standards in Sec.  60.5380b of this chapter 
or an applicable approved state plan or applicable Federal plan in part 
62 of this chapter for dry seals and self-contained wet seals.
    (ii) For centrifugal compressors at an onshore petroleum and 
natural gas production facility or an onshore petroleum and natural gas 
gathering and boosting facility that are not subject to the centrifugal 
compressor standards in Sec.  60.5380b of this chapter or an applicable 
approved state plan or applicable Federal plan in part 62 of this 
chapter for dry seals and self-contained wet seals, you may elect to 
conduct the volumetric emission measurements specified in paragraph 
(o)(1) of this section using methods specified in paragraphs (o)(2) 
through (5) of this section and perform calculations specified in 
paragraphs (o)(6) through (9) of this section.
    (iii) For any centrifugal compressors at an onshore petroleum and 
natural gas production facility or an onshore petroleum and natural gas 
gathering and boosting facility for which paragraphs (o)(10)(i) and 
(ii) of this section do not apply, you must calculate atmospheric 
centrifugal compressor wet seal oil degassing vents at an onshore 
petroleum and natural gas production facility or an onshore petroleum 
and natural gas gathering and boosting facility using Equation W-25 of 
this section. Emissions from centrifugal compressor wet seal oil 
degassing vents that are routed to a flare, combustion, or vapor 
recovery system are not required to be determined under this paragraph 
(o).
[GRAPHIC] [TIFF OMITTED] TP01AU23.027

Where:

Es,i = Annual volumetric GHGi (either 
CH4 or CO2) emissions from centrifugal 
compressor wet seals, at standard conditions, in cubic feet.
Count = Total number of centrifugal compressors that have wet seal 
oil

[[Page 50402]]

degassing vents that are vented directly to the atmosphere.
EFi,s = Emission factor for GHGi. Use 1.2 x 
107 standard cubic feet per year per compressor for 
CH4 and 5.30 x 105 standard cubic feet per 
year per compressor for CO2 at 60 [deg]F and 14.7 psia.
* * * * *
    (p) Reciprocating compressor venting. If you are required to report 
emissions from reciprocating compressor venting as specified in Sec.  
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct 
volumetric emission measurements specified in paragraph (p)(1) of this 
section using methods specified in paragraphs (p)(2) through (5) of 
this section; perform calculations specified in paragraphs (p)(6) 
through (9) of this section; and calculate CH4 and 
CO2 mass emissions as specified in paragraph (p)(11) of this 
section. If you are required to report emissions from reciprocating 
compressor venting at an onshore petroleum and natural gas production 
facility as specified in Sec.  98.232(c)(11) or an onshore petroleum 
and natural gas gathering and boosting facility as specified in Sec.  
98.232(j)(9), you must calculate volumetric emissions as specified in 
paragraph (p)(10) of this section and calculate CH4 and 
CO2 mass emissions as specified in paragraph (p)(11) of this 
section. If emissions from a compressor source are routed to a flare, 
paragraphs (p)(1) through (11) of this section do not apply and instead 
you must calculate CH4, CO2, and N2O 
emissions as specified in paragraph (n) of this section. If emissions 
from a compressor source are routed to combustion, paragraphs (p)(1) 
through (11) of this section do not apply and instead you must 
calculate and report emissions as specified in subpart C of this part 
or paragraph (z) of this section, as applicable. If emissions from a 
compressor source are routed to a vapor recovery system, paragraphs 
(p)(1) through (11) of this section do not apply.
    (1) * * *
    (i) Reciprocating compressor source as found measurements. Measure 
venting from each compressor according to either paragraph 
(p)(1)(i)(A), (B), or (C) of this section at least once annually, based 
on the compressor mode (as defined in Sec.  98.238) in which the 
compressor was found at the time of measurement, except as specified in 
paragraph (p)(1)(i)(D) of this section. If additional measurements 
beyond the required annual testing are performed (including duplicate 
measurements or measurement of additional operating modes), then all 
measurements satisfying the applicable monitoring and QA/QC that is 
required by this paragraph (p) must be used in the calculations 
specified in this section.
    (A) For a compressor measured in operating-mode, you must measure 
volumetric emissions from blowdown valve leakage through the blowdown 
vent as specified in paragraph (p)(2)(i) of this section, and measure 
volumetric emissions from reciprocating rod packing as specified in 
paragraph (p)(2)(ii) or (iii) of this section, as applicable.
    (B) For a compressor measured in not-operating-depressurized-mode, 
you must measure volumetric emissions from isolation valve leakage as 
specified in paragraph (p)(2)(i) of this section. If a compressor is 
not operated and has blind flanges in place throughout the reporting 
period, measurement is not required in this compressor mode.
    (C) For a compressor measured in standby-pressurized-mode, you must 
measure volumetric emissions from blowdown valve leakage through the 
blowdown vent as specified in paragraph (p)(2)(i) of this section and 
measure volumetric emissions from reciprocating rod packing as 
specified in paragraph (p)(2)(ii) or (iii) of this section, as 
applicable.
    (D) An annual as found measurement is not required in the first 
year of operation for any new compressor that begins operation after as 
found measurements have been conducted for all existing compressors. 
For only the first year of operation of new compressors, calculate 
emissions according to paragraph (p)(6)(ii) of this section.
* * * * *
    (2) Methods for performing as found measurements from individual 
reciprocating compressor sources. If conducting measurements for each 
compressor source, you must determine the volumetric emissions from 
blowdown valves and isolation valves as specified in paragraph 
(p)(2)(i) of this section. You must determine the volumetric emissions 
from reciprocating rod packing as specified in paragraph (p)(2)(ii) or 
(iii) of this section, as applicable.
* * * * *
    (ii) For reciprocating rod packing equipped with an open-ended vent 
line on compressors in operating-mode or standby-pressurized-mode, 
determine the volumetric emissions using one of the methods specified 
in paragraphs (p)(2)(ii)(A) through (C) of this section.
* * * * *
    (C) You may choose to use any of the methods set forth in Sec.  
98.234(a)(1) through (3) to screen for emissions. If emissions are 
detected using one of these specified methods, then you must use one of 
the methods specified in paragraphs (p)(2)(ii)(A) and (B) of this 
section. If emissions are not detected using the methods in Sec.  
98.234(a)(1) through (3), then you may assume that the volumetric 
emissions are zero. For the purposes of this paragraph (p)(2)(ii)(C), 
when using any of the methods in Sec.  98.234(a), emissions are 
detected whenever a leak is detected according to the method. Acoustic 
leak detection is only applicable for through-valve leakage and is not 
applicable for screening or measuring rod packing emissions.
    (iii) * * *
    (A) You must use the methods described in Sec.  98.234(a)(1) 
through (3) to conduct annual leak detection of equipment leaks from 
the packing case into an open distance piece, or for compressors with a 
closed distance piece, conduct annual detection of gas emissions from 
the rod packing vent, distance piece vent, compressor crank case 
breather cap, or other vent emitting gas from the rod packing. Acoustic 
leak detection is only applicable for through-valve leakage and is not 
applicable for screening rod packing emissions.
* * * * *
    (4) * * *
    (ii) * * *
    (C) A high volume sampler according to methods set forth in Sec.  
98.234(d).
* * * * *
    (E) You may choose to use any of the methods set forth in Sec.  
98.234(a)(1) through (3) to screen for emissions. If emissions are 
detected using one of these specified methods, then you must use one of 
the methods specified in paragraphs (p)(4)(ii)(A) through (D) of this 
section. If emissions are not detected using the methods in Sec.  
98.234(a)(1) through (3), then you may assume that the volumetric 
emissions are zero. For the purposes of this paragraph, when using any 
of the methods in Sec.  98.234(a), emissions are detected whenever a 
leak is detected according to the method. Acoustic leak detection is 
only applicable for through-valve leakage and is not applicable for 
screening a manifolded group of compressor sources.
* * * * *
    (6) * * *
    (ii) Using Equation W-27 of this section, calculate the annual 
volumetric GHG emissions from each reciprocating compressor mode-source 
combination specified in paragraphs (p)(1)(i)(A) through (C) of this 
section that was not measured during the reporting year.
* * * * *

[[Page 50403]]

    (iii) Using Equation W-28 of this section, develop an emission 
factor for each compressor mode-source combination specified in 
paragraphs (p)(1)(i)(A) through (C) of this section. These emission 
factors must be calculated annually and used in Equation W-27 of this 
section to determine volumetric emissions from a reciprocating 
compressor in the mode-source combinations that were not measured in 
the reporting year.
* * * * *
    (8) * * *

Tg = Total time the manifolded group of compressor sources g 
had potential for emissions in the reporting year, in hours. Include 
all time during which at least one compressor source in the manifolded 
group of compressor sources g was in a mode-source combination 
specified in either paragraph (o)(1)(i)(A), (o)(1)(i)(B), (o)(1)(i)(C), 
(p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section. Default of 
8760 hours may be used.
* * * * *
    (10) Method for calculating volumetric GHG emissions from 
reciprocating compressor venting at an onshore petroleum and natural 
gas production facility or an onshore petroleum and natural gas 
gathering and boosting facility. You must calculate volumetric 
emissions from reciprocating compressors at an onshore petroleum and 
natural gas production facility or an onshore petroleum and natural gas 
gathering and boosting facility as specified in paragraphs (p)(10)(i) 
through (iii) of this section, as applicable.
    (i) For reciprocating compressors at an onshore petroleum and 
natural gas production facility or an onshore petroleum and natural gas 
gathering and boosting facility that are subject to the reciprocating 
compressor standards in Sec.  60.5385b of this chapter or an applicable 
approved state plan or applicable Federal plan in part 62 of this 
chapter, you must conduct measurements according to paragraphs 
(p)(10)(i)(A) and (B) of this section.
    (A) You must conduct the volumetric emission measurements as 
required by Sec.  60.5385b(b) and (c) of this chapter or an applicable 
approved state plan or applicable Federal plan in part 62 of this 
chapter, conduct any additional volumetric emission measurements 
specified in paragraph (p)(1) of this section using methods specified 
in paragraphs (p)(2) through (5) of this section, and calculate 
emissions as specified in paragraphs (p)(6) through (9) of this 
section. Conduct all measurements required by this paragraph 
(p)(10)(i)(A) at the frequency specified by Sec.  60.5385b(a) of this 
chapter or an applicable approved state plan or applicable Federal plan 
in part 62 of this chapter. For any reporting year in which measuring 
at the frequency specified by Sec.  60.5385b(a) of this chapter results 
in measurement not being required for a subject compressor, calculate 
emissions for all mode-source combinations as specified in paragraph 
(p)(6)(ii) of this section.
    (B) You must conduct measurements of compressors as specified in 
paragraph (p)(1)(i)(B) of this section such that at the end of each 
calendar year, you have taken measurements in not-operating-
depressurized-mode over the last 3 consecutive calendar years for at 
least one-third of the compressors at your facility that are subject to 
the reciprocating compressor standards in Sec.  60.5385b of this 
chapter or an applicable approved state plan or applicable Federal plan 
in part 62 of this chapter.
    (ii) For reciprocating compressors at an onshore petroleum and 
natural gas production facility or an onshore petroleum and natural gas 
gathering and boosting facility that are not subject to the 
reciprocating compressor standards in Sec.  60.5385b of this chapter or 
an applicable approved state plan or applicable Federal plan in part 62 
of this chapter, you may elect to conduct volumetric emission 
measurements specified in paragraph (p)(1) of this section using 
methods specified in paragraphs (p)(2) through (5) of this section and 
perform calculations specified in paragraphs (p)(6) through (9) of this 
section.
    (iii) For any reciprocating compressors at an onshore petroleum and 
natural gas production facility or an onshore petroleum and natural gas 
gathering and boosting facility for which paragraphs (p)(10)(i) and 
(ii) of this section do not apply, you must calculate reciprocating 
compressor atmospheric venting of rod packing emissions using Equation 
W-29D of this section. Reciprocating compressor rod packing emissions 
that are routed to a flare, combustion, or vapor recovery system are 
not required to be determined under this paragraph (p).
[GRAPHIC] [TIFF OMITTED] TP01AU23.028

Where:

Es,i = Annual volumetric GHGi (either 
CH4 or CO2) emissions from reciprocating 
compressors, at standard conditions, in cubic feet.
Count = Total number of reciprocating compressors with rod packing 
emissions vented directly to the atmosphere.
EFi,s = Emission factor for GHGi. Use 2.13 x 
105 standard cubic feet per year per compressor for 
CH4 and 1.18 x 104 standard cubic feet per 
year per compressor for CO2 at 60 [deg]F and 14.7 psia.
* * * * *
    (q) Equipment leak surveys. For the components identified in 
paragraphs (q)(1)(i) through (iii) of this section, you must conduct 
equipment leak surveys using the leak detection methods specified in 
paragraphs (q)(1)(i) through (iii) and (v) of this section. For the 
components identified in paragraph (q)(1)(iv) of this section, you may 
elect to conduct equipment leak surveys, and if you elect to conduct 
surveys, you must use a leak detection method specified in paragraph 
(q)(1)(iv) of this section. This paragraph (q) applies to components in 
streams with gas content greater than 10 percent CH4 plus 
CO2 by weight. Components in streams with gas content less 
than or equal to 10 percent CH4 plus CO2 by 
weight are exempt from the requirements of this paragraph (q) and do 
not need to be reported. Tubing systems equal to or less than one half 
inch diameter are exempt from the requirements of this paragraph (q) 
and do not need to be reported. Equipment leak components in vacuum 
service are exempt from the survey and emission estimation requirements 
of this paragraph (q) and only the count of these equipment must be 
reported.
    (1) Survey requirements--(i) For the components listed in Sec.  
98.232(e)(7), (f)(5), (g)(4), and (h)(5), that are not subject to the 
well site or compressor station fugitive emissions standards in Sec.  
60.5397a of this chapter, the fugitive emissions standards for well 
sites, centralized production facilities, and compressor stations in 
Sec.  60.5397b of this chapter, or an applicable approved state plan or 
applicable Federal plan in part 62 of this chapter, you must conduct 
surveys using any of the leak detection methods listed in Sec.  
98.234(a) and calculate equipment leak emissions using the procedures 
specified in either paragraph (q)(2) or (3) of this section.
    (ii) For the components listed in Sec.  98.232(i)(1), you must 
conduct surveys using any of the leak detection methods listed in Sec.  
98.234(a) except Sec.  98.234(a)(2)(ii) and calculate equipment leak 
emissions using the procedures specified in either paragraph (q)(2) or 
(3) of this section.
    (iii) For the components listed in Sec.  98.232(c)(21)(i), (e)(7) 
and (8), (f)(5) through (8), (g)(4), (g)(6) and (7), (h)(5), (h)(7) and 
(8), and (j)(10)(i) that are

[[Page 50404]]

subject to the well site or compressor station fugitive emissions 
standards in Sec.  60.5397a of this chapter, the fugitive emissions 
standards for well sites, centralized production facilities, and 
compressor stations in Sec.  60.5397b of this chapter, or an applicable 
approved state plan or applicable Federal plan in part 62 of this 
chapter, you must conduct surveys using any of the leak detection 
methods in Sec.  98.234(a)(1)(ii) or (iii) or (a)(2)(ii), as 
applicable, and calculate equipment leak emissions using the procedures 
specified in either paragraph (q)(2) or (3) of this section.
    (iv) For the components listed in Sec.  98.232(c)(21)(i), (e)(8), 
(f)(6) through (8), (g)(6) or (7), (h)(7) or (8), or (j)(10)(i), that 
are not subject to fugitive emissions standards in Sec.  60.5397a of 
this chapter, the fugitive emissions standards for well sites, 
centralized production facilities, and compressor stations in Sec.  
60.5397b of this chapter, or an applicable approved state plan or 
applicable Federal plan in part 62 of this chapter, you may elect to 
conduct surveys according to this paragraph (q), and, if you elect to 
do so, then you must use one of the leak detection methods in Sec.  
98.234(a).
    (A) If you elect to use a leak detection method in Sec.  98.234(a) 
for the surveyed component types in Sec.  98.232(c)(21)(i), (f)(7), 
(g)(6), (h)(7), or (j)(10)(i) in lieu of the population count 
methodology specified in paragraph (r) of this section, then you must 
calculate emissions for the surveyed component types in Sec.  
98.232(c)(21)(i), (f)(7), (g)(6), (h)(7), or (j)(10)(i) using the 
procedures in either paragraph (q)(2) or (3) of this section.
    (B) If you elect to use a leak detection method in Sec.  98.234(a) 
for the surveyed component types in Sec.  98.232(e)(8), (f)(6) and (8), 
(g)(7), and (h)(8), then you must use the procedures in either 
paragraph (q)(2) or (3) of this section to calculate those emissions.
    (C) If you elect to use a leak detection method in Sec.  
98.234(a)(1)(ii) or (iii) or (a)(2)(ii), as applicable, for any 
elective survey under paragraph (q)(1)(iv) of this section, then you 
must survey the component types in Sec.  98.232(c)(21)(i), (e)(8), 
(f)(6) through (8), (g)(6) and (7), (h)(7) and (8), and (j)(10)(i) that 
are not subject to fugitive emissions standards in Sec.  60.5397a of 
this chapter, the fugitive emissions standards for well sites, 
centralized production facilities, and compressor stations in Sec.  
60.5397b of this chapter, or an applicable approved state plan or 
applicable Federal plan in part 62 of this chapter, and you must 
calculate emissions from the surveyed component types in Sec.  
98.232(c)(21)(i), (e)(8), (f)(6) through (8), (g)(6) and (7), (h)(7) 
and (8), and (j)(10)(i) using the emission calculation requirements in 
either paragraph (q)(2) or (3) of this section.
    (v) For the components listed in Sec.  98.232(d)(7), you must 
conduct surveys as specified in paragraphs (q)(1)(v)(A) and (B) of this 
section and you must calculate equipment leak emissions using the 
procedures specified in either paragraph (q)(2) or (3) of this section.
    (A) For the components listed in Sec.  98.232(d)(7) that are not 
subject to the equipment leak standards for onshore natural gas 
processing plants in Sec.  60.5400b of this chapter, or an applicable 
approved state plan or applicable Federal plan in part 62 of this 
chapter, you may use any of the leak detection methods listed in Sec.  
98.234(a).
    (B) For the components listed in Sec.  98.232(d)(7) that are 
subject to the equipment leak standards for onshore natural gas 
processing plants in Sec.  60.5400b of this chapter, or an applicable 
approved state plan or applicable Federal plan in part 62 of this 
chapter, you must use either of the leak detection methods in Sec.  
98.234(a)(1)(iii) or (a)(2)(ii).
    (vi) Except as provided in paragraph (q)(1)(vii) of this section, 
you must conduct at least one complete leak detection survey in a 
calendar year. If you conduct multiple complete leak detection surveys 
in a calendar year, you must use the results from each complete leak 
detection survey when calculating emissions using the procedures 
specified in either paragraph (q)(2) or (3) of this section. Except as 
provided in paragraphs (q)(1)(vi)(A) through (G) of this section, a 
complete leak detection survey is a survey in which all equipment 
components required to be surveyed as specified in paragraphs (q)(1)(i) 
through (v) of this section are surveyed.
    (A) For components subject to the well site and compressor station 
fugitive emissions standards in Sec.  60.5397a of this chapter, each 
survey conducted in accordance with Sec.  60.5397a of this chapter 
using one of the methods in Sec.  98.234(a) will be considered a 
complete leak detection survey for purposes of this section.
    (B) For components subject to the well site, centralized production 
facility, and compressor station fugitive emissions standards in Sec.  
60.5397b of this chapter, each survey conducted in accordance with the 
fugitive emissions standards for well sites, centralized production 
facilities, and compressor stations in Sec.  60.5397b of this chapter 
using one of the methods in Sec.  98.234(a) will be considered a 
complete leak detection survey for purposes of this section.
    (C) For components subject to the well site, centralized production 
facility, and compressor station fugitive emissions standards in an 
applicable approved state plan or applicable Federal plan in part 62 of 
this chapter, each survey conducted in accordance with the applicable 
approved state plan or applicable Federal plan in part 62 of this 
chapter using one of the methods in Sec.  98.234(a) will be considered 
a complete leak detection survey for purposes of this section.
    (D) For an onshore petroleum and natural gas production facility 
electing to conduct leak detection surveys according to paragraph 
(q)(1)(iv) of this section, a survey of all required components at a 
single well-pad will be considered a complete leak detection survey for 
purposes of this section.
    (E) For an onshore petroleum and natural gas gathering and boosting 
facility electing to conduct leak detection surveys according to 
paragraph (q)(1)(iv) of this section, a survey of all required 
components at a gathering and boosting site, as defined in Sec.  
98.238, will be considered a complete leak detection survey for 
purposes of this section.
    (F) For an onshore natural gas processing facility subject to the 
equipment leak standards for onshore natural gas processing plants in 
Sec.  60.5400b of this chapter or an applicable approved state plan or 
applicable Federal plan in part 62 of this chapter, each survey 
conducted in accordance with the equipment leak standards for onshore 
natural gas processing plants in Sec.  60.5400b of this chapter or an 
applicable approved state plan or applicable Federal plan in part 62 of 
this chapter will be considered a complete leak detection survey for 
the purposes of calculating emissions using the procedures specified in 
either paragraph (q)(2) or (3) of this section. At least one complete 
leak detection survey conducted during the reporting year must include 
all components listed in Sec.  98.232(d)(7) and subject to this 
paragraph (q), including components which are considered inaccessible 
emission sources as defined in part 60 of this chapter.
    (G) For natural gas distribution facilities that choose to conduct 
equipment leak surveys at all above grade transmission-distribution 
transfer stations over multiple years as provided in paragraph 
(q)(1)(vii) of this section, a survey of all required components at the 
above grade transmission-distribution transfer stations monitored 
during the calendar year will be considered a

[[Page 50405]]

complete leak detection survey for purposes of this section.
    (vii) Natural gas distribution facilities are required to perform 
equipment leak surveys only at above grade stations that qualify as 
transmission-distribution transfer stations. Below grade transmission-
distribution transfer stations and all metering-regulating stations 
that do not meet the definition of transmission-distribution transfer 
stations are not required to perform equipment leak surveys under this 
section. Natural gas distribution facilities may choose to conduct 
equipment leak surveys at all above grade transmission-distribution 
transfer stations over multiple years ``n,'' not exceeding a five-year 
period to cover all above grade transmission-distribution transfer 
stations. If the facility chooses to use the multiple year option, then 
the number of transmission-distribution transfer stations that are 
monitored in each year should be approximately equal across all years 
in the cycle.
    (2) Calculation Method 1: Leaker emission factor calculation 
methodology. If you elect not to measure leaks according to Calculation 
Method 2 as specified in paragraph (q)(3) of this section, you must use 
this Calculation Method 1 for all components included in a complete 
leak survey. For industry segments listed in Sec.  98.230(a)(2) through 
(9), if equipment leaks are detected during surveys required or elected 
for components listed in paragraphs (q)(1)(i) through (v) of this 
section, then you must calculate equipment leak emissions per component 
type per reporting facility using Equation W-30 of this section and the 
requirements specified in paragraphs (q)(2)(i) through (ix) of this 
section. For the industry segment listed in Sec.  98.230(a)(8), the 
results from Equation W-30 are used to calculate population emission 
factors on a meter/regulator run basis using Equation W-31 of this 
section. If you chose to conduct equipment leak surveys at all above 
grade transmission-distribution transfer stations over multiple years, 
``n,'' according to paragraph (q)(1)(vii) of this section, then you 
must calculate the emissions from all above grade transmission-
distribution transfer stations as specified in paragraph (q)(2)(xi) of 
this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.029

Where:

Es,p,i = Annual total volumetric emissions of GHGi from 
specific component type ``p'' (in accordance with paragraphs 
(q)(1)(i) through (v) of this section) in standard (``s'') cubic 
feet, as specified in paragraphs (q)(2)(ii) through (x) of this 
section.
xp = Total number of specific component type ``p'' 
detected as leaking in any leak survey during the year. A component 
found leaking in two or more surveys during the year is counted as 
one leaking component.
EFs,p = Leaker emission factor as specified in paragraphs 
(q)(2)(iii) through (x) of this section.
k = Factor to adjust for undetected leaks by respective leak 
detection method, where k equals 1.25 for the methods in Sec.  
98.234(q)(1), (3) and (5); k equals 1.55 for the method in Sec.  
98.234(q)(2)(i); and k equals 1.27 for the method in Sec.  
98.234(q)(2)(ii).
GHGi = For onshore petroleum and natural gas production 
facilities and onshore petroleum and natural gas gathering and 
boosting facilities, concentration of GHGi, 
CH4, or CO2, in produced natural gas as 
defined in paragraph (u)(2) of this section; for onshore natural gas 
processing facilities, concentration of GHGi, 
CH4 or CO2, in the total hydrocarbon of the 
feed natural gas; for onshore natural gas transmission compression 
and underground natural gas storage, GHGi equals 0.975 
for CH4 and 1.1 x 10-\2\ for CO2; 
for LNG storage and LNG import and export equipment, GHGi 
equals 1 for CH4 and 0 for CO2; and for 
natural gas distribution, GHGi equals 1 for CH4 and 1.1 x 
10-\2\ CO2.
Tp,z = The total time the surveyed component ``z,'' 
component type ``p,'' was assumed to be leaking and operational, in 
hours. If one leak detection survey is conducted in the calendar 
year, assume the component was leaking for the entire calendar year. 
If multiple leak detection surveys are conducted in the calendar 
year, assume a component found leaking in the first survey was 
leaking since the beginning of the year until the date of the 
survey; assume a component found leaking in the last survey of the 
year was leaking from the preceding survey through the end of the 
year; assume a component found leaking in a survey between the first 
and last surveys of the year was leaking since the preceding survey 
until the date of the survey; and sum times for all leaking periods. 
For each leaking component, account for time the component was not 
operational (i.e., not operating under pressure) using an 
engineering estimate based on best available data.

    (i) The leak detection surveys selected for use in Equation W-30 
must be conducted during the calendar year as indicated in paragraph 
(q)(1)(vi) and (vii) of this section, as applicable.
* * * * *
    (iii) Onshore petroleum and natural gas production facilities must, 
if available, use the site-specific leaker emission factor calculated 
in accordance with paragraph (q)(4) of section or use the appropriate 
default whole gas leaker emission factors consistent with the well 
type, where components associated with gas wells are considered to be 
in gas service and components associated with oil wells are considered 
to be in oil service as listed in Table W-2 to this subpart.
    (iv) Onshore petroleum and natural gas gathering and boosting 
facilities must, if available, use the site-specific leaker emission 
factor calculated in accordance with paragraph (q)(4) of section or use 
the appropriate default whole gas leaker factors for components in gas 
service listed in Table W-2 to this subpart.
    (v) Onshore natural gas processing facilities must, if available, 
use the site-specific leaker emission factor calculated in accordance 
with paragraph (q)(4) of section or use the appropriate default total 
hydrocarbon leaker emission factors for compressor components in gas 
service and non-compressor components in gas service listed in table W-
4 to this subpart.
    (vi) Onshore natural gas transmission compression facilities must, 
if available, use the site-specific leaker emission factor calculated 
in accordance with paragraph (q)(4) of section or use the appropriate 
default total hydrocarbon leaker emission factors for compressor 
components in gas service and non-compressor components in gas service 
listed in table W-4 to this subpart.
    (vii) Underground natural gas storage facilities must, if 
available, use the site-specific leaker emission factor calculated in 
accordance with paragraph (q)(4) of section or use the appropriate 
default total hydrocarbon leaker emission factors for storage stations 
or storage wellheads in gas service listed in table W-4 to this 
subpart.
    (viii) LNG storage facilities must, if available, use the site-
specific leaker emission factor calculated in accordance with paragraph 
(q)(4) of section or use the appropriate default methane leaker

[[Page 50406]]

emission factors for LNG storage components in LNG service or gas 
service listed in table W-6 to this subpart.
    (ix) LNG import and export facilities must, if available, use the 
site-specific leaker emission factor calculated in accordance with 
paragraph (q)(4) of section or use the appropriate default methane 
leaker emission factors for LNG terminals components in LNG service or 
gas service listed in table W-6 to this subpart.
    (x) Natural gas distribution facilities must use Equation W-30 of 
this section and the default methane leaker emission factors for 
transmission-distribution transfer station components in gas service 
listed in table W-6 to this subpart to calculate component emissions 
from annual equipment leak surveys conducted at above grade 
transmission-distribution transfer stations.
    (A) Use Equation W-31 of this section to determine the meter/
regulator run population emission factors for each GHGi. As additional 
survey data become available, you must recalculate the meter/regulator 
run population emission factors for each GHGi annually according to 
paragraph (q)(2)(x)(B) of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.030

Where:

EFs,MR,i = Meter/regulator run population emission factor 
for GHGi based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic 
feet of GHGi per operational hour of all meter/regulator 
runs.
Es,p,i,y = Annual total volumetric emissions at standard 
conditions of GHGi from component type ``p'' during year 
``y'' in standard (``s'') cubic feet, as calculated using Equation 
W-30 of this section.
p = Seven component types listed in Table W-6 to this subpart for 
transmission-distribution transfer stations.
Tw,y = The total time the surveyed meter/regulator run 
``w'' was operational, in hours during survey year ``y'' using an 
engineering estimate based on best available data.
CountMR,y = Count of meter/regulator runs surveyed at 
above grade transmission-distribution transfer stations in year 
``y''.
y = Year of data included in emission factor ``EFs,MR,i'' 
according to paragraph (q)(2)(x)(B) of this section.
n = Number of years of data, according to paragraph (q)(1)(vii) of 
this section, whose results are used to calculate emission factor 
``EFs,MR,i'' according to paragraph (q)(2)(x)(B) of this 
section.

    (B) The emission factor ``eFs,MR,i,'' based on annual 
equipment leak surveys at above grade transmission-distribution 
transfer stations, must be calculated annually. If you chose to conduct 
equipment leak surveys at all above grade transmission-distribution 
transfer stations over multiple years, ``n,'' according to paragraph 
(q)(1)(vii) of this section and you have submitted a smaller number of 
annual reports than the duration of the selected cycle period of 5 
years or less, then all available data from the current year and 
previous years must be used in the calculation of the emission factor 
``EFs,MR,i'' from Equation W-31 of this section. After the 
first survey cycle of ``n'' years is completed and beginning in 
calendar year (n+1), the survey will continue on a rolling basis by 
including the survey results from the current calendar year ``y'' and 
survey results from all previous (n-1) calendar years, such that each 
annual calculation of the emission factor ``EFs,MR,i'' from 
Equation W-31 is based on survey results from ``n'' years. Upon 
completion of a cycle, you may elect to change the number of years in 
the next cycle period (to be 5 years or less). If the number of years 
in the new cycle is greater than the number of years in the previous 
cycle, calculate ``EFs,MR,i'' from Equation W-31 in each 
year of the new cycle using the survey results from the current 
calendar year and the survey results from the preceding number years 
that is equal to the number of years in the previous cycle period. If 
the number of years, ``nnew,'' in the new cycle is smaller 
than the number of years in the previous cycle, ``n,'' calculate 
``EFs,MR,i'' from Equation W-31 in each year of the new 
cycle using the survey results from the current calendar year and 
survey results from all previous (nnew-1) calendar years.
    (xi) If you chose to conduct equipment leak surveys at all above 
grade transmission-distribution transfer stations over multiple years, 
``n,'' according to paragraph (q)(1)(vii) of this section, you must use 
the meter/regulator run population emission factors calculated using 
Equation W-31 of this section and the total count of all meter/
regulator runs at above grade transmission-distribution transfer 
stations to calculate emissions from all above grade transmission-
distribution transfer stations using Equation W-32B in paragraph (r) of 
this section.
    (3) Calculation Method 2: Leaker measurement methodology. For 
industry segments listed in Sec.  98.230(a)(2) through (9), if 
equipment leaks are detected during surveys required or elected for 
components listed in paragraphs (q)(1)(i) through (v) of this section, 
you may elect to measure the volumetric flow rate of each natural gas 
leak identified during a complete leak survey. If you elect to use this 
method, you must use this method for all components included in a 
complete leak survey and you must determine the volumetric flow rate of 
each natural gas leak identified during the leak survey and aggregate 
the emissions by the method of leak detection and component type as 
specified in paragraphs (q)(3)(i) through (vii) of this section.
    (i) Determine the volumetric flow rate of each natural gas leak 
identified during the leak survey following the methods Sec.  98.234(b) 
through (d), as appropriate for each leak identified. You do not need 
to use the same measurement method for each leak measured.
    (ii) For each leak, calculate the volume of natural gas emitted as 
the product of the natural gas flow rate measured in paragraph 
(q)(3)(i) of this section and the duration of the leak. If one leak 
detection survey is conducted in the calendar year, assume the 
component was leaking for the entire calendar year. If multiple leak 
detection surveys are conducted in the calendar year, assume a 
component found leaking in the first survey was leaking since the 
beginning of the year until the date of the survey; assume a component 
found leaking in the last survey of the year was leaking from the 
preceding survey through the end of the year;

[[Page 50407]]

assume a component found leaking in a survey between the first and last 
surveys of the year was leaking since the preceding survey until the 
date of the survey. For each leaking component, account for time the 
component was not operational (i.e., not operating under pressure) 
using an engineering estimate based on best available data.
    (iii) For each leak, convert the volumetric emissions of natural 
gas determined in paragraph (q)(3)(ii) of this section to standard 
conditions using the method specified in paragraph (t)(1) of this 
section.
    (iv) For each leak, convert the volumetric emissions of natural gas 
at standard conditions determined in paragraph (q)(3)(iii) of this 
section to CO2 and CH4 volumetric emissions at 
standard conditions using the methods specified in paragraph (u) of 
this section.
    (v) For each leak, convert the GHG volumetric emissions at standard 
conditions determined in paragraph (q)(3)(iv) of this section to GHG 
mass emissions using the methods specified in paragraph (v) of this 
section.
    (vi) Sum the CO2 and CH4 mass emissions 
determined in paragraph (q)(3)(v) of this section separately for each 
type of component required to be surveyed by the method used for the 
survey for which a leak was detected.
    (vii) Multiply the total CO2 and CH4 mass 
emissions by survey method and component type determined in paragraph 
(q)(3)(vi) by the survey specific value for ``k'', the factor 
adjustment for undetected leaks, where k equals 1.25 for the methods in 
Sec.  98.234(q)(1), (3) and (5); k equals 1.55 for the method in Sec.  
98.234(q)(2)(i); and k equals 1.27 for the method in Sec.  
98.234(q)(2)(ii).
    (viii) For natural gas distribution facilities:
    (A) Use Equation W-31 of this section to determine the meter/
regulator run population emission factors for each GHGi 
using the methods as specified in paragraphs (q)(2)(x)(A) and (B) of 
this section, except use the GHG mass emissions calculated in paragraph 
(q)(3)(vi) of this section rather than the emissions calculated using 
Equation W-30.
    (B) If you chose to conduct equipment leak surveys at all above 
grade transmission-distribution transfer stations over multiple years, 
``n,'' according to paragraph (q)(1)(vii) of this section, you must use 
the meter/regulator run population emission factors calculated 
according to paragraph (q)(3)(vii)(A) of this section and the total 
count of all meter/regulator runs at above grade transmission-
distribution transfer stations to calculate emissions from all above 
grade transmission-distribution transfer stations using Equation W-32B 
in paragraph (r) of this section.
    (4) Development of site-specific component-level leaker emission 
factors by leak detection method. If you elect to measure leaks 
according to Calculation Method 2 as specified in paragraph (q)(3) of 
this section, you must use the measurement values determined in 
accordance with paragraph (q)(3) of this section to calculate a site-
specific component-level leaker emission factor by leak detection 
method as provided in paragraphs (q)(4)(i) through (iv) of this 
section.
    (i) You must track the leak measurements made separately for each 
of the applicable components listed in paragraphs (q)(1)(i) through (v) 
of this section and by the leak detection method according to the 
following three bins.
    (A) Method 21 as specified in Sec.  98.234(a)(2)(i).
    (B) Method 21 as specified in Sec.  98.234(a)(2)(ii).
    (C) Optical gas imaging (OGI) and other leak detection methods as 
specified in Sec.  98.234(a)(1), (3), or (5).
    (ii) You must accumulate a minimum of 50 leak measurements total 
for a given component type and leak detection method combination before 
you can develop and use a site-specific component-level leaker emission 
factor for use in calculating emissions according to paragraph (q)(2) 
of this section (Calculation Method 1: Leaker emission factor 
calculation methodology).
    (iii) Sum the volumetric flow rate of natural gas determined in 
accordance with paragraph (q)(3)(i) of this section for each leak by 
component type and leak detection method as specified in paragraph 
(q)(4)(i) of this section meeting the minimum number of measurement 
requirement in paragraph (q)(4)(ii) of this section.
    (iv) Convert the volumetric flow rate of natural gas determined in 
paragraph (q)(4)(iii) of this section to standard conditions using the 
method specified in paragraph (t)(1) of this section.
    (v) Determine the emission factor in units of standard cubic feet 
per hour component (scf/hr-component) by dividing the sum of the 
volumetric flow rate of natural gas determined in paragraph (q)(4)(iv) 
of this section by the total number of leak measurements for that 
component type and leak detection method combination.
    (vi) You must update the emission factor determined in (q)(4)(v) of 
this section annually to include the results from all complete leak 
surveys for which leak measurement was performed during the reporting 
year in accordance with paragraph (q)(3) of this section.
    (r) Equipment leaks by population count. This paragraph (r) applies 
to emissions sources listed in Sec.  98.232(c)(21)(ii), (f)(7), (g)(5), 
(h)(6), and (j)(10)(ii) if you are not required to comply with 
paragraph (q) of this section and if you do not elect to comply with 
paragraph (q) of this section for these components in lieu of this 
paragraph (r). This paragraph (r) also applies to emission sources 
listed in Sec.  98.232(i)(2) through (6), (j)(11), and (m)(3) through 
(5). To be subject to the requirements of this paragraph (r), the 
listed emissions sources also must contact streams with gas content 
greater than 10 percent CH4 plus CO2 by weight. 
Emissions sources that contact streams with gas content less than or 
equal to 10 percent CH4 plus CO2 by weight are 
exempt from the requirements of this paragraph (r) and do not need to 
be reported. Tubing systems equal to or less than one half inch 
diameter are exempt from the requirements of this paragraph (r) and do 
not need to be reported. Equipment leak components in vacuum service 
are exempt from the survey and emission estimation requirements of this 
paragraph (r) and only the count of these equipment must be reported. 
You must calculate emissions from all emission sources listed in this 
paragraph (r) using Equation W-32A of this section, except for natural 
gas distribution facility emission sources listed in Sec.  
98.232(i)(3). Natural gas distribution facility emission sources listed 
in Sec.  98.232(i)(3) must calculate emissions using Equation W-32B of 
this section and according to paragraph (r)(6)(ii) of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.031


[[Page 50408]]


[GRAPHIC] [TIFF OMITTED] TP01AU23.032

Where:

Es,e,i = Annual volumetric emissions of GHGi 
from the emission source type in standard cubic feet. The emission 
source type may be a major equipment (e.g., wellhead, separator), 
component (e.g., connector, open-ended line), below grade metering-
regulating station, below grade transmission-distribution transfer 
station, distribution main, distribution service, gathering 
pipeline, transmission company interconnect metering-regulating 
station, farm tap and/or direct sale metering-regulating station, or 
transmission pipeline.
Es,MR,i = Annual volumetric emissions of GHGi 
from all meter/regulator runs at above grade metering regulating 
stations that are not above grade transmission-distribution transfer 
stations or, when used to calculate emissions according to paragraph 
(q)(2)(xi) or (q)(3)(vii)(B) of this section, the annual volumetric 
emissions of GHGi from all meter/regulator runs at above 
grade transmission-distribution transfer stations.
Counte = Total number of the emission source type at the 
facility. Onshore petroleum and natural gas production facilities 
and onshore petroleum and natural gas gathering and boosting 
facilities must count each major equipment piece listed in Table W-1 
to this subpart. Onshore petroleum and natural gas gathering and 
boosting facilities must also count the miles of gathering pipelines 
by material type (protected steel, unprotected steel, plastic, or 
cast iron). Underground natural gas storage facilities must count 
each component listed in Table W-3 to this subpart. LNG storage 
facilities must count the number of vapor recovery compressors. LNG 
import and export facilities must count the number of vapor recovery 
compressors. Natural gas distribution facilities must count the: (1) 
Number of distribution services by material type; (2) miles of 
distribution mains by material type; (3) number of below grade 
transmission-distribution transfer stations; and (4) number of below 
grade metering-regulating stations; as listed in Table W-5 to this 
subpart. Onshore natural gas transmission pipeline facilities must 
count the following, as listed in Table W-5 to this subpart: (1) 
Miles of transmission pipelines by material type; (2) number of 
transmission company interconnect metering-regulating stations; and 
(3) number of farm tap and/or direct sale metering-regulating 
stations.
CountMR = Total number of meter/regulator runs at above 
grade metering-regulating stations that are not above grade 
transmission-distribution transfer stations or, when used to 
calculate emissions according to paragraph (q)(2)(xi) or 
(q)(3)(vii)(B) of this section, the total number of meter/regulator 
runs at above grade transmission-distribution transfer stations.
EFs,e = Population emission factor for the specific 
emission source type, as listed in tables W-1, W-3, and W-5 to this 
subpart.
EFs,MR,i = Meter/regulator run population emission factor 
for GHGi based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic 
feet of GHGi per operational hour of all meter/regulator 
runs, as determined in Equation W-31 of this section.
GHGi = For onshore petroleum and natural gas production 
facilities and onshore petroleum and natural gas gathering and 
boosting facilities, concentration of GHGi, 
CH4, or CO2, in produced natural gas as 
defined in paragraph (u)(2) of this section; for onshore natural gas 
transmission compression, underground natural gas storage, and 
onshore natural gas transmission pipeline, GHGi equals 
0.975 for CH4 and 1.1 x 10-\2\ for 
CO2; for LNG storage and LNG import and export equipment, 
GHGi equals 1 for CH4 and 0 for 
CO2; and for natural gas distribution, GHGi 
equals 1 for CH4 and 1.1 x 10-\2\ 
CO2.
Te = Average estimated time that each emission source 
type associated with the equipment leak emission was operational in 
the calendar year, in hours, using engineering estimate based on 
best available data.
Tw,avg = Average estimated time that each meter/regulator 
run was operational in the calendar year, in hours per meter/
regulator run, using engineering estimate based on best available 
data.

    (1) Calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (2) Onshore petroleum and natural gas production facilities and 
onshore petroleum and natural gas gathering and boosting facilities 
must use the appropriate default whole gas population emission factors 
listed in table W-1 of this subpart. Major equipment associated with 
gas wells are considered gas service equipment in table W-1 of this 
subpart. Onshore petroleum and natural gas gathering and boosting 
facilities shall use the gas service equipment emission factors in 
table W-1 of this subpart. Major equipment associated with crude oil 
wells are considered crude service equipment in table W-1 of this 
subpart. Where facilities conduct EOR operations, the emission factor 
listed in table W-1 of this subpart shall be used to estimate all 
streams of gases, including recycle CO2 stream. For meters/
piping, use one meters/piping per well-pad for onshore petroleum and 
natural gas production operations and the number of meters in the 
facility for onshore petroleum and natural gas gathering and boosting 
operations.
    (3) Underground natural gas storage facilities must use the 
appropriate default total hydrocarbon population emission factors for 
storage wellheads in gas service listed in table W-3 to this subpart.
    (4) LNG storage facilities must use the appropriate default methane 
population emission factors for LNG storage compressors in gas service 
listed in table W-5 to this subpart.
    (5) LNG import and export facilities must use the appropriate 
default methane population emission factors for LNG terminal 
compressors in gas service listed in table W-5 to this subpart.
    (6) Natural gas distribution facilities must use the appropriate 
methane emission factors as described in paragraphs (r)(6)(i) and (ii) 
of this section.
    (i) Below grade transmission-distribution transfer stations, below 
grade metering-regulating stations, distribution mains, and 
distribution services must use the appropriate default methane 
population emission factors listed in table W-5 of this subpart to 
estimate emissions from components listed in Sec.  98.232(i)(2), (4), 
(5), and (6), respectively.
    (ii) Above grade metering-regulating stations that are not above 
grade transmission-distribution transfer stations must use the meter/
regulator run population emission factor calculated in Equation W-31 
for the components listed in Sec.  98.232(i)(3). Natural gas 
distribution facilities that do not have above grade transmission-
distribution transfer stations are not required to calculate emissions 
for above grade metering-regulating stations and are not required to 
report GHG emissions in Sec.  98.236(r)(2)(v).
    (7) Natural gas transmission pipeline facilities must use the 
appropriate default methane population emission factors listed in table 
W-5 of this subpart to estimate emissions from components listed in 
Sec.  98.232(m)(3) through (5).
    (s) Offshore petroleum and natural gas production facilities. 
Report CO2, CH4, and N2O emissions for 
offshore petroleum and natural gas production from all equipment leaks, 
vented emission, and flare emission source types as identified by BOEM 
in compliance with 30 CFR 550.302 through 304.

[[Page 50409]]

    (1) Offshore production facilities that report to BOEM's emissions 
inventory shall report the same annual emissions as calculated and 
reported to BOEM as referenced in 30 CFR 550.302 through 304.
    (i) For any reporting year that does not coincide with a BOEM 
emissions inventory data collection year, report the most recent 
published BOEM emissions inventory data referenced in 30 CFR 550.302 
through 550.304. Adjust emissions based on the operating time for the 
facility relative to the operating time in the most recent published 
BOEM emissions inventory data.
    (ii) As an alternative to the adjustment provisions in paragraph 
(s)(1)(i) of this section, you may use the most recent monitoring and 
calculation methods published by BOEM referenced in 30 CFR 550.302 
through 550.304 to calculate and report annual emissions.
    (2) Offshore production facilities that do not report to BOEM's 
emissions inventory must use the most recent monitoring and calculation 
methods published by BOEM referenced in 30 CFR 550.302 through 550.304 
to calculate and report annual emissions.
    (i) For any reporting year that does not coincide with a BOEM 
emissions inventory data collection year, you may report the most 
recent emissions data submitted to demonstrate compliance with this 
subpart of part 98, with emissions adjusted based on the operating time 
for the facility relative to operating time in the previous reporting 
period.
    (ii) As an alternative to the adjustment provisions in paragraph 
(s)(2)(i) of this section, you may use the most recent monitoring and 
calculation methods published by BOEM referenced in 30 CFR 550.302 
through 550.304 to calculate and report annual emissions.
    (3) If BOEM discontinues or delays their data collection effort by 
more than 3 years, then offshore reporters shall once in every 3 years 
use the most recent BOEM data collection and emissions estimation 
methods to estimate emissions. These emission estimates would be used 
to report emissions from the facility sources as required in paragraph 
(s)(1)(i) of this section.
    (4) For either first or subsequent year reporting, offshore 
facilities either within or outside of BOEM jurisdiction that were not 
covered in the previous BOEM data collection cycle must use the most 
recent BOEM data collection and emissions estimation methods published 
by BOEM referenced in 30 CFR 550.302 through 550.304 to calculate and 
report emissions.
    (t) * * *
    (2) * * *
* * * * *
Za = Compressibility factor at actual conditions for 
GHGi. You may use either a default compressibility factor of 
1, or a site-specific compressibility factor based on actual 
temperature and pressure conditions.
* * * * *
    (u) * * *
    (2) * * *
    (ii) GHG mole fraction in feed natural gas for all emissions 
sources upstream of the de-methanizer or dew point control and GHG mole 
fraction in facility specific residue gas to transmission pipeline 
systems for all emissions sources downstream of the de-methanizer 
overhead or dew point control for onshore natural gas processing 
facilities. For onshore natural gas processing plants that solely 
fractionate a liquid stream, use the GHG mole percent in feed natural 
gas liquid for all streams. If you have a continuous gas composition 
analyzer on feed natural gas, you must use these values for determining 
the mole fraction. If you do not have a continuous gas composition 
analyzer, then annual samples must be taken according to methods set 
forth in Sec.  98.234(b).
* * * * *
    (y) Other large release events. Calculate CO2 and 
CH4 emissions from other large release events as specified 
in paragraphs (y)(2) through (5) of this section for each release that 
meets or exceeds the applicable criteria in paragraph (y)(1) of this 
section. You are not required to measure every release from your 
facility, but if you have credible information that demonstrates the 
release meets or exceeds one of the thresholds or credible information 
that the release may reasonably be anticipated to meet or exceed (or to 
have met or exceeded) one of the thresholds in paragraph (y)(1) of this 
section, then you must calculate the event emissions and, if the 
thresholds are confirmed to be exceeded, report the emissions as an 
other large release event.
    (1) You must report emissions for other large release events that 
emit GHG at or above any applicable threshold listed in paragraphs 
(y)(1)(i) or (ii) of this section considering the entire event 
duration. The thresholds listed in paragraphs (y)(1)(i) or (ii) of this 
section are not limited to the emissions that occur within a given 
reporting year.
    (i) For sources not subject to reporting under paragraphs (a) 
through (s), (w), (x), (dd), or (ee) of this section (such as but not 
limited to a fire, explosion, well blowout, or pressure relief), a 
release that either:
    (A) Emits methane at any point in time at a rate of 100 kg/hr or 
greater; or
    (B) Emits combined GHG across the entire event duration of 250 
metric tons of CO2e or more.
    (ii) For sources subject to reporting under paragraphs (a) through 
(s), (w), (x), (dd), or (ee) of this section, a release that emits GHG 
at or above at least one of the thresholds listed in paragraphs 
(y)(1)(ii)(A) or (B) of this section. For a release meeting the 
criteria in either paragraph (y)(1)(ii)(A) or (B) of this section, you 
must report the emissions as an other large release event and exclude 
the emissions from this release in the source-specific emissions 
calculated under paragraphs (a) through (s), (w), (x), (dd), or (ee) of 
this section, as applicable.
    (A) Emits methane at any point in time at a rate of 100 kg/hr or 
greater in excess of the emissions calculated from the source using the 
applicable methods under paragraphs (a) through (s), (w), (x), (dd), or 
(ee) of this section; or
    (B) Emits combined GHG across the entire event duration of 250 
metric tons of CO2e or more in excess of the emissions 
calculated from the source using the applicable methods under 
paragraphs (a) through (s), (w), (x), (dd), or (ee) of this section.
    (2) Estimate the total volume of gas released during the event in 
standard cubic feet and the methane emission rate at any point in time 
during the event in kilograms per hour using measurement data according 
to Sec.  98.234(b), if available, or a combination of process 
knowledge, engineering estimates, and best available data when 
measurement data are not available according to paragraphs (y)(2)(i) 
through (v) of this section.
    (i) The total volume of gas released must be estimated as the 
product of the measured or estimated average flow or release rate and 
the estimated event duration. For events for which information is 
available showing variable or decaying flow rates, you must calculate 
the maximum natural gas flow or release rate during the event and 
either determine a representative average release rate across the 
entire event or determine representative release rates for specific 
time periods within the event duration. If you elect to determine 
representative release rates for specific time periods within the event 
duration, calculate the volume of gas released for each time period 
within the event duration as the product of the representative release 
rate and the length of the corresponding time period

[[Page 50410]]

and sum the volume of gas released across each of the time periods for 
the full duration of the event.
    (ii) The start time of the event must be determined based on 
monitored process parameters. If monitored process parameters cannot 
identify the start of the event, the event must be assumed to start on 
the date of the most recent monitoring or measurement survey that 
confirms the source was not emitting at or above the rates specified in 
paragraph (y)(1) of this section or assumed to have a duration of 182 
days, whichever duration is shorter.
    (iii) The end time of the event must be the date of the confirmed 
repair or confirmed cessation of emissions.
    (iv) For the purposes of paragraph (y)(2)(ii) of this section, 
``monitoring or measurement survey'' includes any monitoring or 
measurement method in Sec.  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 in paragraph (y)(1).
    (v) For events that span two different reporting years, calculate 
the portion of the event's volumetric emissions calculated according to 
paragraph (y)(2)(i) of this section that occurred in each reporting 
year considering only reporting year 2025 and later reporting years. 
For events with consistent flow or for which one average emissions rate 
is used, use the relative duration of the event within each reporting 
year to apportion the volume of gas released for each reporting year. 
For variable flow events for which the volume of gas released is 
estimated for separate time periods, sum the volume of gas released 
across each of the time periods within a given reporting year 
separately. If one of the time periods span two different reporting 
years, calculate the portion of the volumetric emissions calculated for 
that time period that applies to each reporting year based on the 
number of hours in that time period within each reporting year.
    (3) Determine the composition of the gas released to the atmosphere 
using measurement data, if available, or a combination of process 
knowledge, engineering estimates, and best available data when 
measurement data are not available. In the event of an explosion or 
fire, where a portion of the natural gas may be combusted, estimate the 
composition of the gas released to the atmosphere considering the 
fraction of natural gas released directly to the atmosphere and the 
fraction of natural gas that was combusted by the explosion or fire 
during the release event. Assume a maximum combustion efficiency of 92 
percent for natural gas that is combusted in an explosion or fire when 
estimating the CO2 composition of the release. You may use 
different compositions for different periods within the duration if 
available information suggests composition varied during the release 
(e.g., if a portion of the release occurred while fire was present and 
a portion of the release occurred when no fire was present).
    (4) Calculate the GHG volumetric emissions using Equation W-35 in 
paragraph (u)(1) of this section.
    (5) Calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (z) Onshore petroleum and natural gas production, onshore petroleum 
and natural gas gathering and boosting, and natural gas distribution 
combustion emissions. Except as specified in paragraphs (z)(6) and (7) 
of this section, calculate CO2, CH4, and 
N2O combustion-related emissions from stationary or portable 
equipment using the applicable method in paragraphs (z)(1) through (3) 
of this section according to the fuel combusted as specified in those 
paragraphs:
    (1) If a fuel combusted in the stationary or portable equipment 
meets the specifications of paragraph (z)(1)(i) of this section, then 
calculate emissions according to paragraph (z)(1)(ii) of this section.
    (i) The fuel combusted in the stationary or portable equipment is 
listed in table C-1 of subpart C of this part or is a blend in which 
all fuels are listed in table C-1. If the fuel is natural gas or the 
blend contains natural gas, the natural gas must also meet the criteria 
of paragraphs (z)(1)(i)(A) and (B) of this section.
    (A) The natural gas must be of pipeline quality specification.
    (B) The natural gas must have a minimum higher heating value of 950 
Btu per standard cubic foot.
    (ii) For fuels listed in paragraph (z)(1)(i) of this section, 
calculate CO2, CH4, and N2O emissions 
for each unit or group of units combusting the same fuel according to 
any Tier listed in subpart C of this part, except that each natural 
gas-fired reciprocating internal combustion engine or gas turbine must 
use one of the methods in paragraph (z)(4) of this section to quantify 
a CH4 emission factor instead of using the CH4 
emission factor in table C-2 of subpart C of this part. You must follow 
all applicable calculation requirements for that tier listed in Sec.  
98.33, any monitoring or QA/QC requirements listed for that tier in 
Sec.  98.34, any missing data procedures specified in Sec.  98.35, and 
any recordkeeping requirements specified in Sec.  98.37. You must 
report emissions according to paragraph (z)(5) of this section.
    (2) If a fuel combusted in the stationary or portable equipment 
meets the specifications of paragraph (z)(2)(i) of this section, then 
calculate emissions according to paragraph (z)(2)(ii) of this section.
    (i) The fuel combusted in the stationary or portable equipment is 
natural gas that is not pipeline quality or it is a blend containing 
natural gas that is not pipeline quality with only fuels that are 
listed in table C-1. The natural gas must meet the criteria of 
paragraphs (z)(2)(i)(A) through (C) of this section.
    (A) The natural gas must have a minimum higher heating value of 950 
Btu per standard cubic foot.
    (B) The natural gas must have a maximum CO2 content of 1 
percent by volume.
    (C) The natural gas must have a minimum CH4 content of 
85 percent by volume.
    (ii) For fuels listed in paragraph (z)(2)(i) of this section, 
calculate CO2, CH4, and N2O emissions 
for each unit or group of units combusting the same fuel according to 
Tier 2, Tier 3, or Tier 4 listed in subpart C of this part, except that 
each natural gas-fired reciprocating engine or gas turbine must use one 
of the methods in paragraph (z)(4) of this section to quantify a 
CH4 emission factor instead of using the CH4 
emission factor in table C-2 of subpart C of this part. You must follow 
all applicable calculation requirements for that tier listed in Sec.  
98.33, any monitoring or QA/QC requirements listed for that tier in 
Sec.  98.34, any missing data procedures specified in Sec.  98.35, and 
any recordkeeping requirements specified in Sec.  98.37. You must 
report emissions according to paragraph (z)(5) of this section.
    (3) If a fuel combusted in the stationary or portable equipment 
meets the specifications of paragraph (z)(3)(i) of this section, then 
calculate emissions according to paragraph (z)(3)(ii) of this section.
    (i) The fuel combusted in the stationary or portable equipment does 
not meet the criteria of either paragraph (z)(1)(i) or (z)(2)(i) of 
this section. Examples include natural gas that is not of pipeline 
quality, natural gas that has a higher heating value of less than 950 
Btu per standard cubic feet, and natural gas that is not pipeline 
quality and does not meet the composition criteria of either paragraph 
(z)(2)(i)(B) or (C) of this section. Other examples include field

[[Page 50411]]

gas that does not meet the definition of natural gas in Sec.  98.238 
and blends containing field gas that does not meet the definition of 
natural gas in Sec.  98.238.
    (ii) For fuels listed in paragraph (z)(3)(i) of this section, 
calculate combustion emissions for each unit or group of units 
combusting the same fuel as follows:
    (A) You may use company records to determine the volume of fuel 
combusted in the unit or group of units during the reporting year.
    (B) If you have a continuous gas composition analyzer on fuel to 
the combustion unit(s), you must use these compositions for determining 
the concentration of each constituent in the flow of gas to the unit or 
group of units. If you do not have a continuous gas composition 
analyzer on gas to the combustion unit(s), you may use engineering 
estimates based on best available data to determine the concentration 
of each constituent in the flow of gas to the unit or group of units. 
Otherwise, you must use the appropriate gas compositions for each 
stream going to the combustion unit(s) as specified in paragraph (u)(2) 
of this section.
    (C) Calculate GHG volumetric emissions at actual conditions using 
Equations W-39A and W-39B of this section:
[GRAPHIC] [TIFF OMITTED] TP01AU23.033

[GRAPHIC] [TIFF OMITTED] TP01AU23.034

Where:

Ea,CO2 = Contribution of annual CO2 emissions 
from portable or stationary fuel combustion sources in cubic feet, 
under actual conditions.
Va = Volume of gas sent to the combustion unit or group 
of units in actual cubic feet, during the year.
YCO2 = Mole fraction of CO2 in gas sent to the 
combustion unit or group of units.
[eta] = Fraction of gas combusted for portable and stationary 
equipment determined using engineering estimation. For internal 
combustion devices that are not reciprocating internal combustion 
engines or gas turbines, a default of 0.995 can be used. For two-
stroke lean-burn reciprocating internal combustion engines, a 
default of 0.953 must be used; for four-stroke lean-burn 
reciprocating internal combustion engines, a default of 0.962 must 
be used; for four-stroke rich-burn reciprocating internal combustion 
engines, a default of 0.997 must be used, and for gas turbines, a 
default of 0.999 must be used.
Yj = Mole fraction of hydrocarbon constituent j (such as 
methane, ethane, propane, butane, and pentanes plus) in gas sent to 
the combustion unit or group of units.
Rj = Number of carbon atoms in the hydrocarbon 
constituent j in gas sent to the combustion unit or group of units; 
1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for 
pentanes plus.
Ea,CH4 = Contribution of annual CH4 emissions 
from portable or stationary fuel combustion sources in cubic feet, 
under actual conditions.
YCH4 = Mole fraction of methane in gas sent to the 
combustion unit or group of units.

    (D) Calculate GHG volumetric emissions at standard conditions using 
calculations in paragraph (t) of this section.
    (E) Calculate both combustion-related CH4 and 
CO2 mass emissions from volumetric CH4 and 
CO2 emissions using calculation in paragraph (v) of this 
section.
    (F) Calculate N2O mass emissions using Equation W-40 of 
this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.035

Where:

MassN2O = Annual N2O emissions from the 
combustion of a particular type of fuel (metric tons).
Fuel = Annual mass or volume of the fuel combusted (mass or volume 
per year, choose appropriately to be consistent with the units of 
HHV).
HHV = Site-specific higher heating value of the fuel, mmBtu/unit of 
the fuel (in units consistent with the fuel quantity combusted).
EF = Use 1.0 x 10-4 kg N2O/mmBtu.
1 x 10-3 = Conversion factor from kilograms to metric 
tons.

    (4) For each natural gas-fired reciprocating internal combustion 
engine or gas turbine calculating emissions according to paragraph 
(z)(1)(ii) or (z)(2)(ii) of this section, you must determine a 
CH4 emission factor (kg CH4/MMBtu) using one of 
the methods provided in paragraphs (z)(4)(i) through (iii) of this 
section. If you are required to or elect to use the method in paragraph 
(z)(4)(i) of this section, you must use the results of the performance 
test to determine the CH4 emission factor.
    (i) Conduct a performance test following the applicable procedures 
in Sec.  98.234(i).
    (ii) Original equipment manufacturer information, which may include 
manufacturer specification sheets, emissions certification data, or 
other manufacturer data providing expected emission rates from the 
reciprocating internal combustion engine or gas turbine.
    (iii) Applicable equipment type-specific emission factor from table 
W-7 of this subpart.
    (5) Emissions from fuel combusted in stationary or portable 
equipment at onshore petroleum and natural gas production facilities, 
at onshore petroleum and natural gas gathering and boosting facilities, 
and at natural gas distribution facilities that are calculated 
according to the procedures in either paragraph (z)(1)(ii) or 
(z)(2)(ii) of this section must be reported according to the 
requirements specified in Sec.  98.236(z) rather than the reporting 
requirements specified in subpart C of this part.
    (6) External fuel combustion sources with a rated heat capacity 
equal to or less than 5 mmBtu/hr do not need to report combustion 
emissions or include these emissions for threshold determination in 
Sec.  98.231(a). You must report the type and number of each external 
fuel combustion unit.
    (7) Internal fuel combustion sources, not compressor-drivers, with 
a rated heat capacity equal to or less than 1 mmBtu/hr (or the 
equivalent of 130 horsepower), do not need to report combustion 
emissions or include these

[[Page 50412]]

emissions for threshold determination in Sec.  98.231(a). You must 
report the type and number of each internal fuel combustion unit.
    (aa) through (cc) [Reserved]
    (dd) Drilling mud degassing. Calculate annual volumetric 
CH4 emissions from the degassing of drilling mud using one 
of the calculation methods described in paragraphs (dd)(1) or (2) of 
this section. If you have taken mudlogging measurements, including gas 
trap-derived gas concentration and mud pumping rate, you must use 
Calculation Method 1 as described in paragraph (dd)(1) of this section. 
If you have not taken mudlogging measurements, you may use Calculation 
Method 2 as described in paragraph (dd)(2) of this section.
    (1) Calculation Method 1. For each well in the sub-basin in which 
drilling mud was used during well drilling, you must calculate 
CH4 emissions from drilling mud degassing applying an 
emissions rate derived from a representative well in the same sub-basin 
and at the same approximate total depth. You must follow the procedures 
specified in paragraph (dd)(1)(i) of this section to calculate 
CH4 emissions for the representative well and follow the 
procedures in paragraphs (dd)(1)(ii) through (iv) of this section to 
calculate CH4 emissions for every well drilled in the sub-
basin and at the same approximate total depth.
    (i) Calculate CH4 emissions from mud degassing for one 
representative well in each sub-basin and at each approximate total 
depth. For the representative well, you must use mudlogging 
measurements, including gas trap derived gas concentration and mud 
pumping rate, taken during the reporting year. In the first year of 
reporting, you may use measurements from the prior reporting year if 
measurements from the current reporting year are not available. Use 
Equation W-41 of this section to calculate natural gas emissions from 
mud degassing at the representative well. You must identify and 
calculate CH4 emissions for a new representative well for 
the sub-basin and same approximate total depth every 2 calendar years 
or on a more frequent basis. If a representative well is not available 
in the same sub-basin and at the same targeted approximate total depth, 
you may choose a well within the facility that is drilled into the same 
formation and at the same approximate total depth.
[GRAPHIC] [TIFF OMITTED] TP01AU23.036

Where:

Es,CH4,r = Annual total volumetric CH4 
emissions from mud degassing for the representative well, r, in 
standard cubic feet.
MRr = Average mud rate for the representative well, r, in 
gallons per minute.
Tr = Total time that drilling mud is circulated in the 
representative well, r, in minutes.
Xn = Concentration of natural gas in the drilling mud as 
measured by the gas trap, in parts per million.
GHGCH4 = Measured mole fraction of CH4 in 
natural gas entrained in the drilling mud.
0.1337 = Conversion from gallons to standard cubic feet.

    (ii) Calculate the emissions rate of CH4 in standard 
cubic feet per minute from the representative well using Equation W-42 
of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.037

Where:

ERs,CH4,r = Volumetric CH4 emission rate from 
mud degassing for the representative well, r, in standard cubic feet 
per minute.
Es,CH4,r = Annual total volumetric CH4 
emissions from mud degassing for the representative well, r, in 
standard cubic feet.
Tr = Total time that drilling mud is circulated in the 
representative well, r, in minutes.

    (iii) Use Equation W-43 of this section to calculate emissions for 
any wells drilled in the same sub-basin and targeting the same 
approximate total depth in the reporting year.
[GRAPHIC] [TIFF OMITTED] TP01AU23.038

Where:

Es,CH4,p = Annual total CH4 emissions from mud 
degassing for the well, p, in standard cubic feet.
ERs,CH4,r = Volumetric CH4 emission rate from 
mud degassing for the representative well, r, in standard cubic feet 
per minute.
Tp = Total time that drilling mud is circulated in the 
well, p, during the reporting year, in minutes.

    (iv) Calculate CH4 mass emissions using calculations in 
paragraph (v) of this section.
    (2) Calculation Method 2. If you did not take mudlogging 
measurements, calculate emissions from mud degassing for each well 
using Equation W-44 of this section:
[GRAPHIC] [TIFF OMITTED] TP01AU23.039

Where:

MassCH4,p = Annual total CH4 emissions for the 
well, p, in metric tons.
EFCH4 = Emission factor in metric tons CH4 per 
drilling day. Use 0.2605 for water-based drilling muds, 0.0586 for 
oil-based drilling muds, and 0.0586 for synthetic drilling muds.
DDp = Total number of drilling days for the well, p. The 
first drilling day is the day

[[Page 50413]]

that the borehole penetrated the first hydrocarbon-bearing zone and 
the last drilling day is the day drilling mud ceases to be 
circulated in the wellbore.

    (ee) Crankcase venting. For reciprocating internal combustion 
engines or gas turbines, calculate annual CH4 volumetric 
emissions from crankcase venting at standard conditions using Equation 
W-45 of this section:
[GRAPHIC] [TIFF OMITTED] TP01AU23.040

Where:

ECH4 = Annual total volumetric emissions of 
CH4 from crankcase venting on reciprocating internal 
combustion engines or gas turbines, in standard cubic feet.
EF = Emission factor for crankcase venting on reciprocating internal 
combustion engines or gas turbines, in standard cubic feet gas per 
hour per crankcase vent. Use 2.28 standard cubic feet gas per hour 
per crankcase vent.
GHGCH4 = Average concentration of CH4 in the 
gas stream entering reciprocating internal combustion engines or gas 
turbines. If the concentration of CH4 is unknown, use the 
concentration of CH4 in the gas stream either using 
engineering estimates based on best available data or as defined in 
paragraph (u)(2) of this section.
Count = Total number of crankcase vents on reciprocating internal 
combustion engines or gas turbines.
T = Total operating hours per year for reciprocating internal 
combustion engines or gas turbines with crankcase vents.

0
13. Amend Sec.  98.234 by:
0
a. Revising the introductory text and paragraphs (a) and (d)(3);
0
b. Adding paragraph (d)(5);
0
c. Removing the text ``Equation W-41'' and ``Eq. W-41'' in paragraph 
(e) and adding in its place the text ``Equation W-46'' and ``Eq. W-
46'', respectively;
0
d. Removing and reserving paragraphs (f) and (g); and
0
e. Adding paragraph (i).
    The revisions and additions read as follows:


Sec.  98.234  Monitoring and QA/QC requirements.

    The GHG emissions data for petroleum and natural gas emissions 
sources must be quality assured as applicable as specified in this 
section. Offshore petroleum and natural gas production facilities shall 
adhere to the monitoring and QA/QC requirements as set forth in 30 CFR 
550.
    (a) You must use any of the applicable methods described in 
paragraphs (a)(1) through (5) of this section to conduct leak 
detection(s) or screening survey(s) as specified in Sec.  98.233(k), 
(o), and (p) that occur during a calendar year. You must use any of the 
methods described in paragraphs (a)(1) through (5) of this section to 
conduct leak detection(s) of equipment leaks from components as 
specified in Sec.  98.233(q)(1)(i) or (ii) or (q)(1)(v)(A) that occur 
during a calendar year. You must use one of the methods described in 
paragraph (a)(1)(ii) or (iii) or (a)(2)(ii) of this section, as 
applicable, to conduct leak detection(s) of equipment leaks from 
components as specified in Sec.  98.233(q)(1)(iii) or (q)(1)(v)(B). If 
electing to comply with Sec.  98.233(q) as specified in Sec.  
98.233(q)(1)(iv), you must use any of the methods described in 
paragraphs (a)(1) through (5) of this section to conduct leak 
detection(s) of equipment leaks from component types as specified in 
Sec.  98.233(q)(1)(iv) that occur during a calendar year. Inaccessible 
emissions sources, as defined in 40 CFR part 60, are not exempt from 
this subpart. If the primary leak detection method employed cannot be 
used to monitor inaccessible components without elevating the 
monitoring personnel more than 2 meters above a support surface, you 
must use alternative leak detection devices as described in paragraph 
(a)(1) or (3) of this section to monitor inaccessible equipment leaks 
or vented emissions at least once per calendar year.
    (1) Optical gas imaging instrument. Use an optical gas imaging 
instrument for equipment leak detection as specified in either 
paragraph (a)(1)(i), (ii), or (iii) of this section. You may use any of 
the methods as specified in paragraphs (a)(1)(i) through (iii) of this 
section unless you are required to use a specific method in Sec.  
98.233(q)(1).
    (i) Optical gas imaging instrument as specified in Sec.  60.18 of 
this chapter. Use an optical gas imaging instrument for equipment leak 
detection in accordance with 40 CFR part 60, subpart A, Sec.  60.18 of 
the Alternative work practice for monitoring equipment leaks, Sec.  
60.18(i)(1)(i); Sec.  60.18(i)(2)(i) except that the minimum monitoring 
frequency shall be annual using the detection sensitivity level of 60 
grams per hour as stated in 40 CFR part 60, subpart A, Table 1: 
Detection Sensitivity Levels; Sec.  60.18(i)(2)(ii) and (iii) except 
the gas chosen shall be methane, and Sec.  60.18(i)(2)(iv) and (v); 
Sec.  60.18(i)(3); Sec.  60.18(i)(4)(i) and (v); including the 
requirements for daily instrument checks and distances, and excluding 
requirements for video records. Any emissions detected by the optical 
gas imaging instrument from an applicable component is a leak. In 
addition, you must operate the optical gas imaging instrument to image 
the source types required by this subpart in accordance with the 
instrument manufacturer's operating parameters.
    (ii) Optical gas imaging instrument as specified in Sec.  60.5397a 
of this chapter. Use an optical gas imaging instrument for equipment 
leak detection in accordance with Sec.  60.5397a(c)(3) and (7), and (e) 
of this chapter and paragraphs (a)(1)(ii)(A) through (C) of this 
section.
    (A) For the purposes of this subpart, any visible emissions 
observed by the optical gas imaging instrument from a component 
required or elected to be monitored as specified in Sec.  98.233(q)(1) 
is a leak.
    (B) For the purposes of this subpart, the term ``fugitive emissions 
component'' in Sec.  60.5397a of this chapter means ``component.''
    (C) For the purpose of complying with Sec.  98.233(q)(1)(iv), the 
phrase ``the collection of fugitive emissions components at well sites 
and compressor stations'' in Sec.  60.5397a of this chapter means ``the 
collection of components for which you elect to comply with Sec.  
98.233(q)(1)(iv).''
    (iii) Optical gas imaging instrument as specified in appendix K to 
part 60 of this chapter. Use an optical gas imaging instrument for 
equipment leak detection in accordance with appendix K to part 60, 
Determination of Volatile Organic Compound and Greenhouse Gas Leaks 
Using Optical Gas Imaging. Any emissions detected by the optical gas 
imaging instrument from an applicable component is a leak.
    (2) Method 21. Use the equipment leak detection methods in Method 
21 in appendix A-7 to part 60 of this chapter as specified in paragraph 
(a)(2)(i) or (ii) of this section. You may use either of the methods as 
specified in paragraphs (a)(2)(i) and (ii) of this section unless you 
are required to use a specific method in Sec.  98.233(q)(1). You must 
survey all applicable source types at the facility needed to conduct a 
complete equipment leak survey as defined in Sec.  98.233(q)(1). For 
the purposes of this subpart, the term ``fugitive emissions

[[Page 50414]]

component'' in Sec.  60.5397a of this chapter and Sec.  60.5397b of 
this chapter means ``component.''
    (i) Method 21 with a leak definition of 10,000 ppm. Use the 
equipment leak detection methods in Method 21 in appendix A-7 to part 
60 of this chapter using methane as the reference compound. If an 
instrument reading of 10,000 ppm or greater is measured for any 
applicable component, a leak is detected.
    (ii) Method 21 with a leak definition of 500 ppm. Use the equipment 
leak detection methods in Method 21 in appendix A-7 to part 60 of this 
chapter using methane as the reference compound. If an instrument 
reading of 500 ppm or greater is measured for any applicable component, 
a leak is detected.
    (3) Infrared laser beam illuminated instrument. Use an infrared 
laser beam illuminated instrument for equipment leak detection. Any 
emissions detected by the infrared laser beam illuminated instrument is 
a leak. In addition, you must operate the infrared laser beam 
illuminated instrument to detect the source types required by this 
subpart in accordance with the instrument manufacturer's operating 
parameters.
    (4) [Reserved]
    (5) Acoustic leak detection device. Use the acoustic leak detection 
device to detect through-valve leakage. When using the acoustic leak 
detection device to quantify the through-valve leakage, you must use 
the instrument manufacturer's calculation methods to quantify the 
through-valve leak. When using the acoustic leak detection device, if a 
leak of 3.1 scf per hour or greater is calculated, a leak is detected. 
In addition, you must operate the acoustic leak detection device to 
monitor the source valves required by this subpart in accordance with 
the instrument manufacturer's operating parameters. Acoustic 
stethoscope type devices designed to detect through-valve leakage when 
put in contact with the valve body and that provide an audible leak 
signal but do not calculate a leak rate can be used to identify 
through-valve leakage. For these acoustic stethoscope type devices, a 
leak is detected if an audible leak signal is observed or registered by 
the device. If the acoustic stethoscope type device is used as a 
screening to a measurement method and a leak is detected, the leak must 
be measured using any one of the methods specified in paragraphs (b) 
through (d) of this section.
* * * * *
    (d) * * *
    (3) For high volume samplers that output methane mass emissions, 
you must use the calculations in Sec.  98.233(u) and (v) in reverse to 
determine the natural gas volumetric emissions at standard conditions. 
For high volume samplers that output methane volumetric flow in actual 
conditions, divide the volumetric methane flow rate by the mole 
fraction of methane in the natural gas according to the provisions in 
Sec.  98.233(u) and estimate natural gas volumetric emissions at 
standard conditions using calculations in Sec.  98.233(t). Estimate 
CH4 and CO2 volumetric and mass emissions from 
volumetric natural gas emissions using the calculations in Sec.  
98.233(u) and (v).
* * * * *
    (5) If the measured methane flow exceeds the manufacturer's 
reported quantitation limit or if the measured natural gas flow 
determined as specified in paragraph (d)(3) of this section exceeds 70 
percent of the manufacturer's reported maximum sampling flow rate, then 
the flow exceeds the capacity of the instrument and you must either use 
a temporary or permanent flow meter according to paragraph (b) of this 
section or use calibrated bags according to paragraph (c) of this 
section to determine the leak or flow rate.
* * * * *
    (i) You must use any of the applicable methods described in 
paragraphs (j)(1) through (3) of this section to conduct a performance 
test to determine the concentration of CH4 in the exhaust 
gas. This concentration must be used to develop a CH4 
emission factor (kg/MMBtu) for estimating combustion slip from 
reciprocating internal combustion engines or gas turbines as specified 
in Sec.  98.233(z)(4). Each performance test must be conducted within 
10 percent of 100 percent peak load. You may not conduct performance 
tests during period of startup, shutdown or malfunction. You must 
conduct three separate test runs for each performance test. Each test 
run must be conducted within 10 percent of 100 percent peak (or the 
highest achievable) load and last at least 1 hour.
    (1) EPA Method 18, Volatile Organic Compounds by Gas Chromatography 
in appendix A-6 to part 60 of this chapter.
    (2) EPA Method 320, Measurement of Vapor Phase Organic and 
Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) 
Spectroscopy in appendix A to part 63 of this chapter.
    (3) ASTM D6348-12 Standard Test Method for Determination of Gaseous 
Compounds by Extractive Direct Interface Fourier Transform Infrared 
(FTIR) Spectroscopy (incorporated by reference, see Sec.  98.7).
0
14. Amend Sec.  98.235 by revising paragraph (f) to read as follows:


Sec.  98.235  Procedures for estimating missing data.

* * * * *
    (f) For the first 6 months of required data collection, facilities 
that are currently subject to this subpart W and that start up new 
emission sources or acquire new sources from another facility that were 
not previously subject to this subpart W may use best engineering 
estimates for any data related to those newly operating or newly 
acquired sources that cannot reasonably be measured or obtained 
according to the requirements of this subpart.
* * * * *
0
15. Amend Sec.  98.236 by:
0
a. Revising the introductory text and paragraph (a) introductory text, 
paragraphs (a)(1) through (8), (a)(9) introductory text, (a)(9)(iii), 
(vi), and (xii);
0
b. Adding paragraphs (a)(9)(xiii) and (xiv);
0
c. Revising paragraphs (a)(10), (b), (c), (d), (e), (f)(1) introductory 
text, (f)(1)(i) through (vii), and (f)(1)(xi) introductory text;
0
d. Adding paragraph (f)(1)(xi)(F);
0
e. Revising paragraph (f)(1)(xii) introductory text;
0
f. Adding paragraph (f)(1)(xii)(F);
0
g. Revising paragraphs (f)(2) introductory text and (f)(2)(i), (iii) 
through (v), (ix), and (x);
0
h. Adding paragraphs (f)(2)(xi) and (xii);
0
i. Revising paragraphs (g) introductory text, (g)(1) through (3), 
(g)(5)(i) through (iii), (g)(6) and (10), (h)(1) introductory text, 
(h)(1)(i), (iii), and (iv), (h)(2) introductory text, (h)(2)(i), (iii), 
and (iv);
0
j. Removing paragraphs (h)(2)(v) through (vii);
0
k. Revising paragraphs (h)(3) introductory text, (h)(3)(i), (h)(4), (i) 
introductory text, and (i)(1) introductory text;
0
l. Redesignating paragraphs (i)(1)(i) through (iii) as (i)(1)(ii) 
through (iv), respectively;
0
m. Adding new paragraph (i)(1)(i);
0
n. Revising paragraph (i)(2), (j), (k) introductory text, (k)(1), 
(k)(2) introductory text, and (k)(2)(i);
0
o. Removing paragraph (k)(3);
0
p. Revising paragraphs (l)(1) introductory text, (l)(1)(i) through (v), 
(l)(2), (l)(3) introductory text, (l)(3)(i) through (iv), (l)(4), (m) 
introductory text, and (m)(1) and (4) through (7);
0
q. Removing paragraph (m)(8);
0
r. Revising paragraphs (n), (o) introductory text, (o)(1), (o)(2)(i)(A) 
and (B), (o)(2)(ii)(A), (o)(2)(ii)(D)

[[Page 50415]]

introductory text, (o)(2)(ii)(E), (o)(5), (p) introductory text, 
(p)(1), (p)(2)(ii)(A), (p)(2)(ii)(D) introductory text, (p)(2)(ii)(E), 
(p)(3)(ii) introductory text, (p)(5), (q) introductory text, (q)(1) and 
(2), (r) introductory text, (r)(1) and (3), (s), (x)(1), (y), (z), (aa) 
introductory text, (aa)(1) introductory text, (aa)(1)(i) introductory 
text, and (aa)(1)(i)(B) and (C);
0
s. Adding paragraph (aa)(1)(i)(D);
0
t. Revising paragraphs (aa)(1)(ii)(D) through (H);
0
u. Adding paragraph (aa)(1)(iii) and (iv);
0
v. Revising paragraphs (aa)(2), (aa)(3) introductory text, and 
(aa)(3)(i);
0
w. Adding paragraphs (aa)(3)(viii) and (ix);
0
x. Revising paragraphs (aa)(4)(i), (aa)(5)(ii), (aa)(6) and (7), and 
(aa)(8)(ii);
0
y. Removing and reserving paragraph (aa)(9);
0
z. Revising paragraphs (aa)(10) introductory text and (aa)(10)(ii) and 
(iv);
0
aa. Adding paragraph (aa)(10)(v);
0
bb. Revising paragraphs (aa)(11)(ii) through (iv), (bb) introductory 
text, and (cc); and
0
cc. Adding paragraphs (dd) and (ee).
    The revisions and additions read as follows:


Sec.  98.236  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain reported emissions and related information 
as specified in this section. Reporters that use a flow or volume 
measurement system that corrects to standard conditions as provided in 
the introductory text in Sec.  98.233 for data elements that are 
otherwise required to be determined at actual conditions, report gas 
volumes at standard conditions rather than the gas volumes at actual 
conditions and report the standard temperature and pressure used by the 
measurement system rather than the actual temperature and pressure.
    (a) The annual report must include the information specified in 
paragraphs (a)(1) through (10) of this section for each applicable 
industry segment. The annual report must also include annual emissions 
totals, in metric tons of each GHG, for each applicable industry 
segment listed in paragraphs (a)(1) through (10) of this section, and 
each applicable emission source listed in paragraphs (b) through (z), 
(dd) and (ee) of this section.
    (1) Onshore petroleum and natural gas production. For the 
equipment/activities specified in paragraphs (a)(1)(i) through (xxii) 
of this section, report the information specified in the applicable 
paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Natural gas driven pneumatic pumps. Report the information 
specified in paragraph (c) of this section.
    (iii) Acid gas removal units and nitrogen removal units. Report the 
information specified in paragraph (d) of this section.
    (iv) Dehydrators. Report the information specified in paragraph (e) 
of this section.
    (v) Liquids unloading. Report the information specified in 
paragraph (f) of this section.
    (vi) Completions and workovers with hydraulic fracturing. Report 
the information specified in paragraph (g) of this section.
    (vii) Completions and workovers without hydraulic fracturing. 
Report the information specified in paragraph (h) of this section.
    (viii) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (ix) Hydrocarbon liquids and produced water storage tanks. Report 
the information specified in paragraph (j) of this section.
    (x) Well testing. Report the information specified in paragraph (l) 
of this section.
    (xi) Associated natural gas. Report the information specified in 
paragraph (m) of this section.
    (xii) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (xiii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (xiv) Reciprocating compressors. Report the information specified 
in paragraph (p) of this section.
    (xv) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (xvi) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (xvii) EOR injection pumps. Report the information specified in 
paragraph (w) of this section.
    (xviii) EOR hydrocarbon liquids. Report the information specified 
in paragraph (x) of this section.
    (xix) Other large release events. Report the information specified 
in paragraph (y) of this section.
    (xx) Combustion equipment. Report the information specified in 
paragraph (z) of this section.
    (xxi) Drilling mud degassing. Report the information specified in 
paragraph (dd) of this section.
    (xxii) Crankcase vents. Reporting the information specified in 
paragraph (ee) of this section.
    (2) Offshore petroleum and natural gas production. For the 
equipment/activities specified in paragraphs (a)(2)(i) and (ii) of this 
section, report the information specified in the applicable paragraphs 
of this section.
    (i) Offshore petroleum and natural gas production. Report the 
information specified in paragraph (s) of this section.
    (ii) Other large release events. Report the information specified 
in paragraph (y) of this section.
    (3) Onshore natural gas processing. For the equipment/activities 
specified in paragraphs (a)(3)(i) through (xi) of this section, report 
the information specified in the applicable paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Acid gas removal units and nitrogen removal units. Report the 
information specified in paragraph (d) of this section.
    (iii) Dehydrators. Report the information specified in paragraph 
(e) of this section.
    (iv) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (v) Hydrocarbon liquids and produced water storage tanks. Report 
the information specified in paragraph (j) of this section.
    (vi) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (vii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (viii) Reciprocating compressors. Report the information specified 
in paragraph (p) of this section.
    (ix) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (x) Other large release events. Report the information specified in 
paragraph (y) of this section.
    (xi) Crankcase vents. Report the information specified in paragraph 
(ee) of this section.
    (4) Onshore natural gas transmission compression. For the 
equipment/activities specified in paragraphs (a)(4)(i) through (x) of 
this section, report the information specified in the applicable 
paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Dehydrators. Report the information specified in paragraph (e) 
of this section.
    (iii) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.

[[Page 50416]]

    (iv) Condensate storage tanks. Report the information specified in 
paragraph (k) of this section.
    (v) Flare stacks. Report the information specified in paragraph (n) 
of this section.
    (vi) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (vii) Reciprocating compressors. Report the information specified 
in paragraph (p) of this section.
    (viii) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (ix) Other large release events. Report the information specified 
in paragraph (y) of this section.
    (x) Crankcase vents. Reporting the information specified in 
paragraph (ee) of this section.
    (5) Underground natural gas storage. For the equipment/activities 
specified in paragraphs (a)(5)(i) through (xi) of this section, report 
the information specified in the applicable paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Dehydrators. Report the information specified in paragraph (e) 
of this section.
    (iii) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (iv) Condensate storage tanks. Report the information specified in 
paragraph (k) of this section.
    (v) Flare stacks. Report the information specified in paragraph (n) 
of this section.
    (vi) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (vii) Reciprocating compressors. Report the information specified 
in paragraph (p) of this section.
    (viii) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (ix) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (x) Other large release events. Report the information specified in 
paragraph (y) of this section.
    (xi) Crankcase vents. Reporting the information specified in 
paragraph (ee) of this section.
    (6) LNG storage. For the equipment/activities specified in 
paragraphs (a)(6)(i) through (ix) of this section, report the 
information specified in the applicable paragraphs of this section.
    (i) Acid gas removal units and nitrogen removal units. Report the 
information specified in paragraph (d) of this section.
    (ii) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (iii) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (iv) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (v) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (vi) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (vii) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (viii) Other large release events. Report the information specified 
in paragraph (y) of this section.
    (ix) Crankcase vents. Reporting the information specified in 
paragraph (ee) of this section.
    (7) LNG import and export equipment. For the equipment/activities 
specified in paragraphs (a)(7)(i) through (ix) of this section, report 
the information specified in the applicable paragraphs of this section.
    (i) Acid gas removal units and nitrogen removal units. Report the 
information specified in paragraph (d) of this section.
    (ii) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (iii) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (iv) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (v) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (vi) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (vii) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (viii) Other large release events. Report the information specified 
in paragraph (y) of this section.
    (ix) Crankcase vents. Reporting the information specified in 
paragraph (ee) of this section.
    (8) Natural gas distribution. For the equipment/activities 
specified in paragraphs (a)(8)(i) through (vii) of this section, report 
the information specified in the applicable paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (iii) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (iv) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (v) Other large release events. Report the information specified in 
paragraph (y) of this section.
    (vi) Combustion equipment. Report the information specified in 
paragraph (z) of this section.
    (vii) Crankcase vents. Reporting the information specified in 
paragraph (ee) of this section.
    (9) Onshore petroleum and natural gas gathering and boosting. For 
the equipment/activities specified in paragraphs (a)(9)(i) through 
(xiv) of this section, report the information specified in the 
applicable paragraphs of this section.
* * * * *
    (iii) Acid gas removal units and nitrogen removal units. Report the 
information specified in paragraph (d) of this section.
* * * * *
    (vi) Hydrocarbon liquids and produced water storage tanks. Report 
the information specified in paragraph (j) of this section.
* * * * *
    (xii) Other large release events. Report the information specified 
in paragraph (y) of this section.
    (xiii) Combustion equipment. Report the information specified in 
paragraph (z) of this section.
    (xiv) Crankcase vents. Reporting the information specified in 
paragraph (ee) of this section.
    (10) Onshore natural gas transmission pipeline. For the equipment/
activities specified in paragraphs (a)(10)(i) through (iii) of this 
section, report the information specified in the applicable paragraphs 
of this section.
    (i) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (ii) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (iii) Other large release events. Report the information specified 
in paragraph (y) of this section.
    (b) Natural gas pneumatic devices. You must indicate whether the 
facility contains the following types of equipment: Continuous high 
bleed natural gas pneumatic devices, continuous low bleed natural gas 
pneumatic devices, and intermittent bleed natural gas pneumatic 
devices. If the facility contains any continuous high bleed natural gas 
pneumatic devices, continuous low bleed natural

[[Page 50417]]

gas pneumatic devices, or intermittent bleed natural gas pneumatic 
devices, then you must report the information specified in paragraphs 
(b)(1) through (5) of this section, as applicable. You must report the 
information specified in paragraphs (b)(1) through (5) of this section, 
as applicable, for each well-pad (for onshore petroleum and natural gas 
production), each gathering and boosting site (for onshore petroleum 
and natural gas gathering and boosting), or facility (for all other 
applicable industry segments).
    (1) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (2) The number of natural gas pneumatic devices as specified in 
paragraphs (b)(2)(i) through (vii) of this section, as applicable. If a 
natural gas pneumatic device was vented directly to the atmosphere for 
part of the year and routed to a flare, combustion unit, or vapor 
recovery system during another part of the year, then include the 
device in each of the applicable counts specified in paragraphs 
(b)(2)(ii) through (vii) of this section.
    (i) The total number of natural gas pneumatic devices of each type 
(continuous low bleed, continuous high bleed, and intermittent bleed), 
determined according to Sec.  98.233(a)(4) through (6).
    (ii) The total number of natural gas pneumatic devices of each type 
(continuous low bleed, continuous high bleed, and intermittent bleed) 
vented directly to the atmosphere, determined according to Sec.  
98.233(a)(4) through (6).
    (iii) The total number of natural gas pneumatic devices of each 
type (continuous low bleed, continuous high bleed, and intermittent 
bleed) routed to a flare, combustion, or vapor recovery system.
    (iv) The total number of natural gas pneumatic devices of each type 
(continuous low bleed, continuous high bleed, and intermittent bleed) 
vented directly to the atmosphere for which emissions were calculated 
using Calculation Method 1 according to Sec.  98.233(a)(1).
    (v) The total number of natural gas pneumatic devices of each type 
(continuous low bleed, continuous high bleed, and intermittent bleed) 
vented directly to the atmosphere for which emissions were calculated 
using Calculation Method 2 according to Sec.  98.233(a)(2).
    (vi) The total number of natural gas pneumatic devices of each type 
(continuous low bleed, continuous high bleed, and intermittent bleed) 
vented directly to the atmosphere for which emissions were calculated 
using Calculation Method 3 according to Sec.  98.233(a)(3).
    (vii) If the reported values in paragraphs (b)(2)(i) through (vi) 
of this section are estimated values determined according to Sec.  
98.233(a)(5), then you must report the information specified in 
paragraphs (b)(2)(vii)(A) through (C) of this section.
    (A) The number of natural gas pneumatic devices of each type 
reported in paragraphs (b)(2)(i) through (vi) of this section that are 
counted.
    (B) The number of natural gas pneumatic devices of each type 
reported in paragraphs (b)(2)(i) through (vi) of this section that are 
estimated (not counted).
    (C) Whether the calendar year is the first calendar year of 
reporting or the second calendar year of reporting.
    (3) For natural gas pneumatic devices for which emissions were 
calculated using Calculation Method 1 according to Sec.  98.233(a)(1), 
report the information in paragraphs (b)(3)(i) through (vi) of this 
section for each measurement location.
    (i) Unique measurement location identification number.
    (ii) Type of flow monitor (volumetric flow monitor; mass flow 
monitor).
    (iii) Number of natural gas pneumatic devices of each type 
(continuous low bleed, continuous high bleed, and intermittent bleed) 
downstream of the flow monitor.
    (iv) An indication of whether a natural gas driven pneumatic pump 
is also downstream of the flow monitor.
    (v) Annual CO2 emissions, in metric tons CO2, 
for the natural gas pneumatic devices calculated according to Sec.  
98.233(a)(1) for the measurement location.
    (vi) Annual CH4 emissions, in metric tons 
CH4, for the natural gas pneumatic devices calculated 
according to Sec.  98.233(a)(1) for the measurement location.
    (4) If you used Calculation Method 2 according to Sec.  
98.233(a)(2), report the information in paragraphs (b)(4)(i) through 
(vii) of this section, as applicable.
    (i) The number of years used in the current measurement cycle.
    (ii) For onshore petroleum and natural gas production and onshore 
petroleum and natural gas gathering and boosting facilities:
    (A) Indicate whether the emissions from the natural gas pneumatic 
devices at this well-pad or gathering and boosting site, as applicable, 
were measured during the reporting year or if the emissions were 
calculated using Equation W-1B.
    (B) If the natural gas pneumatic devices at this well-pad or 
gathering and boosting site, as applicable, were measured during the 
reporting year, indicate the primary measurement method used (temporary 
flow meter, calibrated bagging, or high volume sampler).
    (C) If the emissions from natural gas pneumatic devices at this 
well-pad or gathering and boosting site, as applicable, were calculated 
using Equation W-1B, report the following information for each type of 
natural gas pneumatic device (continuous low bleed, continuous high 
bleed, and intermittent bleed).
    (1) The value of the emissions factor for the reporting year as 
calculated using Equation W-1A (in scf/hour/device).
    (2) The total number of natural gas pneumatic devices measured 
across all years upon which the emission factor is based (i.e., the 
cumulative value of ``Sy=1n Countt,y'' in Equation W-1A of 
this subpart).
    (3) Total number of natural gas pneumatic devices that vent 
directly to the atmosphere and that were not directly measured 
according to the requirements in Sec.  98.233(a)(1) or (a)(2)(iii) 
(i.e., ``Countt'' in Equation W-1B).
    (4) The average estimated number of hours in the operating year the 
natural gas pneumatic devices were in service (i.e., supplied with 
natural gas) (``Tt'' in Equation W-1B of this subpart).
    (iii) For onshore natural gas processing facilities, onshore 
natural gas transmission compression facilities, underground natural 
gas storage facilities, and natural gas distribution facilities:
    (A) Indicate the primary measurement method used (temporary flow 
meter, calibrated bagging, or high volume sampler) to measure the 
emissions from natural gas pneumatic devices at this facility.
    (B) Indicate whether the emissions from any natural gas pneumatic 
devices at this facility were calculated using Equation W-1B.
    (C) If the emissions from any natural gas pneumatic devices at this 
facility were calculated using Equation W-1B, report the following 
information for each type of natural gas pneumatic device (continuous 
low bleed, continuous high bleed, and intermittent bleed).
    (1) The value of the emission factor for the reporting year as 
calculated using Equation W-1A (in scf/hour/device).

[[Page 50418]]

    (2) The total number of natural gas pneumatic devices measured 
across all years upon which the emission factor is based (i.e., the 
cumulative value of ``Sy=1n Countt,y'' in Equation W-1A of 
this subpart).
    (3) Total number of natural gas pneumatic devices that vent 
directly to the atmosphere and that were not directly measured 
according to the requirements in Sec.  98.233(a)(1) or (a)(2)(iii) 
(i.e., ``Countt'' in Equation W-1B of this subpart).
    (4) The average estimated number of hours in the operating year the 
natural gas pneumatic devices were in service (i.e., supplied with 
natural gas) (``Tt'' in Equation W-1B of this subpart).
    (iv) Annual CO2 emissions, in metric tons 
CO2, cumulative by type of natural gas pneumatic device for 
which emissions were directly measured and calculated as specified in 
Sec.  98.233(a)(2)(iii) through (viii). Enter 0 if the natural gas 
pneumatic devices at this well-pad or gathering and boosting were not 
monitored during the reporting year.
    (v) Annual CH4 emissions, in metric tons CH4, 
cumulative by type of natural gas pneumatic device for which emissions 
were directly measured and calculated as specified in Sec.  
98.233(a)(2)(iii) through (viii). Enter 0 if the devices at this well-
pad or gathering and boosting were not monitored during the reporting 
year.
    (vi) Annual CO2 emissions, in metric tons 
CO2, cumulative by type of natural gas pneumatic device for 
which emissions were calculated according to Sec.  98.233(a)(2)(ix). 
Enter 0 if all devices at this well-pad, gathering and boosting site, 
or facility were monitored during the reporting year.
    (vii) Annual CH4 emissions, in metric tons 
CH4, cumulative by type of natural gas pneumatic device for 
which emissions were calculated according to Sec.  98.233(a)(2)(ix). 
Enter 0 if all devices at this well-pad, gathering and boosting site, 
or facility were monitored during the reporting year.
    (5) If you used Calculation Method 3 according to Sec.  
98.233(a)(3), report the information in paragraphs (b)(5)(i) through 
(vi) of this section.
    (i) For continuous high bleed and continuous low bleed natural gas 
pneumatic devices:
    (A) Indicate whether you measured emissions according to Sec.  
98.233(a)(3)(i)(A) or used default emission factors according to Sec.  
98.233(a)(3)(i)(B) to calculate emissions from your continuous high 
bleed and continuous low bleed natural gas pneumatic devices vented 
directly to the atmosphere at this well-pad, gathering and boosting 
site, or facility, as applicable.
    (B) If measurements were made according to Sec.  
98.233(a)(3)(i)(A), indicate the primary measurement method used 
(temporary flow meter, calibrated bagging, or high volume sampler).
    (C) If default emission factors were used according to Sec.  
98.233(a)(3)(i)(B) to calculate emissions, report the following 
information for each type of applicable natural gas pneumatic device 
(continuous low bleed and continuous high bleed).
    (1) Total number of natural gas pneumatic devices that vent 
directly to the atmosphere and that were not directly measured 
according to the requirements in Sec.  98.233(a)(1) or (a)(2)(iii) 
(``Countt'' in Equation W-1B of this subpart).
    (2) The average estimated number of hours in the operating year 
that the natural gas pneumatic devices were in service (i.e., supplied 
with natural gas) (``Tt'' in Equation W-1B of this subpart).
    (ii) The number of years used in the current monitoring cycle for 
intermittent bleed pneumatic devices.
    (iii) For intermittent bleed natural gas pneumatic devices at 
onshore petroleum and natural gas production and onshore petroleum and 
natural gas gathering and boosting facilities:
    (A) Indicate whether the emissions from intermittent bleed natural 
gas pneumatic devices at this well-pad or gathering and boosting site, 
as applicable, were monitored during the reporting year and calculated 
using Equation W-1C of this subpart or if the emissions were calculated 
using Equation W-1D of this subpart.
    (B) If the natural gas pneumatic devices at this well-pad or 
gathering and boosting site, as applicable, were monitored during the 
reporting year, indicate the primary monitoring method used (OGI; 
Method 21 at 10,000 ppm; Method 21 at 500 ppm; or infrared laser beam) 
and the number of complete monitoring surveys conducted at the well-pad 
or gathering and boosting site.
    (C) If the emissions from intermittent bleed natural gas pneumatic 
devices at this well-pad or gathering and boosting site, as applicable, 
were calculated using Equation W-1C of this subpart, report the 
following information:
    (1) The total number of intermittent bleed natural gas pneumatic 
devices detected as malfunctioning in any pneumatic device monitoring 
survey during the calendar year (``x'' in Equation W-1C of this 
subpart).
    (2) Average time the intermittent bleed natural gas pneumatic 
devices were in service (i.e., supplied with natural gas) and assumed 
to be malfunctioning in the calendar year (average value of 
``Tm.z'' in Equation W-1C of this subpart).
    (3) The total number of intermittent bleed natural gas pneumatic 
devices that were monitored but were not detected as malfunctioning in 
any pneumatic device monitoring survey during the calendar year 
(``Count'' in Equation W-1C of this subpart).
    (4) Average time the intermittent bleed natural gas pneumatic 
devices that were monitored but were not detected as malfunctioning in 
any pneumatic device monitoring survey during the calendar year were in 
service (i.e., supplied with natural gas) during the calendar year 
(``Tavg'' in Equation W-1C of this subpart).
    (D) If the emissions from intermittent bleed natural gas pneumatic 
devices at this well-pad or gathering and boosting site, as applicable, 
were calculated using Equation W-1D of this subpart, report the 
following information:
    (1) Total number of intermittent bleed natural gas pneumatic 
devices that were not surveyed during the year at the well-pad or 
gathering and boosting site (``CountC'' in Equation W-1D of 
this subpart as applied to the well-pad or gathering and boosting 
site).
    (2) Total number the number of unique intermittent bleed natural 
gas pneumatic devices vented directly to the atmosphere facility-wide 
that were monitored during the reporting year and identified as 
malfunctioning as determined according to Sec.  98.233(a)(3)(iv)(B) 
(``CountB'' in Equation W-1D of this subpart).
    (3) Total number the number of unique intermittent bleed natural 
gas pneumatic devices vented directly to the atmosphere facility-wide 
that were monitored during the reporting year as determined according 
to Sec.  98.233(a)(3)(iv)(A) (``CountA'' in Equation W-1D of 
this subpart).
    (4) Average time, in hours, the intermittent bleed natural gas 
pneumatic devices that were not monitored but during the calendar year 
were in service (i.e., supplied with natural gas) during the calendar 
year (``Tavg'' in Equation W-1D of this subpart).
    (iv) For intermittent bleed natural gas pneumatic devices at 
onshore natural gas processing facilities, onshore natural gas 
transmission compression facilities, underground natural gas storage 
facilities, and natural gas distribution facilities:
    (A) Indicate the primary monitoring method used (OGI; Method 21 at 
10,000 ppm; Method 21 at 500 ppm, or infrared laser beam) and the 
number of complete

[[Page 50419]]

monitoring surveys conducted at the facility.
    (B) The total number of intermittent bleed natural gas pneumatic 
devices detected as malfunctioning in any pneumatic device monitoring 
survey during the calendar year (``x'' in Equation W-1C of this 
subpart).
    (C) Average time the intermittent bleed natural gas pneumatic 
devices were in service (i.e., supplied with natural gas) and assumed 
to be malfunctioning in the calendar year (average value of 
``Tm,z'' in Equation W-1C of this subpart).
    (D) The total number of intermittent bleed natural gas pneumatic 
devices that were monitored but were not detected as malfunctioning in 
any pneumatic device monitoring survey during the calendar year 
(``Count'' in Equation W-1C of this subpart).
    (E) Average time the intermittent bleed natural gas pneumatic 
devices that were monitored but were not detected as malfunctioning in 
any pneumatic device monitoring survey during the calendar year were in 
service (i.e., supplied with natural gas) during the calendar year 
(``Tavg'' in Equation W-1C of this subpart).
    (F) If the emissions from some of the intermittent bleed natural 
gas pneumatic devices at this facility were calculated using Equation 
W-1D of this subpart, report the following information:
    (1) Total number of intermittent bleed natural gas pneumatic 
devices that were not surveyed during the year at the facility 
(``CountC'' in Equation W-1D of this subpart).
    (2) Total number of unique intermittent bleed natural gas pneumatic 
devices vented directly to the atmosphere facility-wide that were 
monitored during the reporting year and identified as malfunctioning as 
determined according to Sec.  98.233(a)(3)(iv)(B) 
(``CountB'' in Equation W-1D of this subpart).
    (3) Total number the number of unique intermittent bleed natural 
gas pneumatic devices vented directly to the atmosphere facility-wide 
that were monitored during the reporting year as determined according 
to Sec.  98.233(a)(3)(iv)(A) (``CountA'' in Equation W-1D of 
this subpart).
    (4) Average time, in hours, the intermittent bleed natural gas 
pneumatic devices that were not monitored but during the calendar year 
were in service (i.e., supplied with natural gas) during the calendar 
year (``Tavg'' in Equation W-1D of this subpart).
    (v) Annual CO2 emissions, in metric tons CO2, 
for each type of natural gas pneumatic device calculated according to 
Calculation Method 3 in Sec.  98.233(a)(3).
    (vi) Annual CH4 emissions, in metric tons 
CH4, for each type of natural gas pneumatic device 
calculated according to Calculation Method 3 in Sec.  98.233(a)(3).
    (c) Natural gas driven pneumatic pumps. You must indicate whether 
the facility has any natural gas driven pneumatic pumps. If the 
facility contains any natural gas driven pneumatic pumps, then you must 
report the information specified in paragraphs (c)(1) through (7) of 
this section. If a pump was vented directly to the atmosphere for part 
of the year and routed to a flare, combustion, or vapor recovery system 
during another part of the year, then include the pump in each of the 
counts specified in paragraphs (c)(2) through (4) of this section. You 
must report the information specified in paragraphs (c)(1) through (7) 
of this section, as applicable, for each well-pad (for onshore 
petroleum and natural gas production) and each gathering and boosting 
site (for onshore petroleum and natural gas gathering and boosting).
    (1) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (2) The number of natural gas driven pneumatic pumps as specified 
in paragraphs (c)(2)(i) through (vi) of this section, as applicable. If 
a natural gas driven pneumatic pump was vented directly to the 
atmosphere for part of the year and routed to a flare, combustion unit, 
or vapor recovery system during another part of the year, then include 
the device in each of the applicable counts specified in paragraphs 
(c)(2)(ii) through (vi) of this section.
    (i) Count of natural gas driven pneumatic pumps.
    (ii) Count of natural gas driven pneumatic pumps vented directly to 
the atmosphere at any point during the year.
    (iii) Count of natural gas driven pneumatic pumps routed to a 
flare, combustion, or vapor recovery system at any point during the 
year.
    (iv) Count of natural gas driven pneumatic pumps vented directly to 
the atmosphere for which emissions were calculated using Calculation 
Method 1 according to Sec.  98.233(c)(1).
    (v) Count of natural gas driven pneumatic pumps vented directly to 
the atmosphere for which emissions were calculated using Calculation 
Method 2 according to Sec.  98.233(c)(2).
    (vi) Count of natural gas driven pneumatic pumps vented directly to 
the atmosphere for which emissions were calculated using Calculation 
Method 3 according to Sec.  98.233(c)(3).
    (3) For natural gas driven pneumatic pumps for which emissions were 
calculated using Calculation Method 1 according to Sec.  98.233(c)(1), 
report the information in paragraphs (c)(3)(i) through (vi) of this 
section for each measurement location.
    (i) Unique measurement location identification number.
    (ii) Type of flow monitor (volumetric flow monitor; mass flow 
monitor).
    (iii) Number of natural gas driven pneumatic pumps downstream of 
the flow monitor.
    (iv) An indication of whether any natural gas pneumatic devices are 
also downstream of the monitoring location.
    (v) Annual CO2 emissions, in metric tons CO2, 
for the pneumatic pump(s) calculated according to Sec.  98.233(c)(1) 
for the measurement location.
    (vi) Annual CH4 emissions, in metric tons 
CH4, for the pneumatic pump(s) calculated according to Sec.  
98.233(c)(1) for the measurement location.
    (4) If you used Calculation Method 2 according to Sec.  
98.233(c)(2), report the information in paragraphs (c)(4)(i) through 
(vi) of this section, as applicable.
    (i) The number of years used in the current measurement cycle.
    (ii) Indicate whether the emissions from the pneumatic pumps at 
this well-pad or gathering and boosting site, as applicable, were 
measured during the reporting year or if the emissions were calculated 
using Equation W-2C.
    (A) If the pneumatic pumps at this well-pad or gathering and 
boosting site, as applicable, were measured during the reporting year, 
indicate the primary measurement method used (temporary flow meter, 
calibrated bagging, or high volume sampler).
    (B) If the emissions from pneumatic pumps at this well-pad or 
gathering and boosting site, as applicable, were calculated using 
Equation W-2C, report the following information:
    (1) The value of the emissions factor for the reporting year as 
calculated using Equation W-2B (in scf/hour/pump).
    (2) The total number of pumps measured across all years upon which 
the emission factor is based (i.e., the cumulative value of 
``Sny=1 County'' term used in Equation W-2B).
    (3) Total number of natural gas driven pneumatic pumps that vent 
directly to the atmosphere and that were not directly measured 
according to the requirements in Sec.  98.233(c)(1) or (c)(2)(iii) 
(i.e., ``Count'' in Equation W-2B).

[[Page 50420]]

    (4) The average estimated number of hours in the operating year the 
pumps were pumping liquid (i.e., ``T'' in Equation W-2C).
    (iii) Annual CO2 emissions, in metric tons 
CO2, cumulative for all natural gas driven pneumatic pumps 
for which emissions were directly measured and calculated as specified 
in Sec.  98.233(c)(2)(ii) through (vi). Enter 0 if emissions from none 
of the natural gas driven pneumatic pumps at this well-pad or gathering 
and boosting site were measured during the reporting year.
    (iv) Annual CH4 emissions, in metric tons 
CH4, cumulative for all natural gas driven pneumatic pumps 
for which emissions were directly measured and calculated as specified 
in Sec.  98.233(c)(2)(ii) through (vi). Enter 0 if emissions from none 
of the natural gas driven pneumatic pumps at this well-pad or gathering 
and boosting site were measured during the reporting year.
    (v) Annual CO2 emissions, in metric tons CO2, 
cumulative for all natural gas driven pneumatic pumps for which 
emissions were calculated according to Sec.  98.233(c)(2)(vii)(B) 
through (D). Enter 0 if emissions from all natural gas driven pneumatic 
pumps at this well-pad or gathering and boosting site were measured 
during the reporting year.
    (vi) Annual CH4 emissions, in metric tons 
CH4, cumulative for all natural gas driven pneumatic pumps 
for which emissions were calculated according to Sec.  
98.233(c)(2)(vii)(B) through (D). Enter 0 if emissions from all natural 
gas driven pneumatic pumps at this well-pad or gathering and boosting 
site were measured during the reporting year.
    (5) If you used Calculation Method 3 according to Sec.  
98.233(c)(3), report the information in paragraphs (c)(5)(i) through 
(iii) of this section for the natural gas driven pneumatic pumps 
subject to Calculation Method 3.
    (i) Average estimated number of hours in the calendar year that 
natural gas driven pneumatic pumps that vented directly to atmosphere 
were pumping liquid (``T'' in Equation W-2C of this subpart).
    (ii) Annual CO2 emissions, in metric tons 
CO2, for all natural gas driven pneumatic pumps vented 
directly to the atmosphere combined, calculated according to Sec.  
98.233(c)(3).
    (iii) Annual CH4 emissions, in metric tons 
CH4, for all natural gas driven pneumatic pumps vented 
directly to the atmosphere combined, calculated according to Sec.  
98.233(c)(3).
    (d) Acid gas removal units and nitrogen removal units. You must 
indicate whether your facility has any acid gas removal units or 
nitrogen removal units that vent directly to the atmosphere, to a flare 
or engine, or to a sulfur recovery plant. For any acid gas removal 
units or nitrogen removal units that vent directly to the atmosphere or 
to a sulfur recovery plant, you must report the information specified 
in paragraphs (d)(1) and (2) of this section. For acid gas removal 
units or nitrogen removal units that were routed to a flare or routed 
to an engine for the entire year, you must only report the information 
specified in paragraph (d)(1)(i) through (iv) and (x) of this section.
    (1) You must report the information specified in paragraphs 
(d)(1)(i) through (x) of this section for each acid gas removal unit or 
nitrogen removal unit, as applicable.
    (i) A unique name or ID number for the acid gas removal unit or 
nitrogen removal unit. For the onshore petroleum and natural gas 
production and the onshore petroleum and natural gas gathering and 
boosting industry segments, a different name or ID may be used for a 
single acid gas removal unit or nitrogen removal unit for each location 
it operates at in a given year.
    (ii) Whether the acid gas removal unit or nitrogen removal unit 
vent was routed to a flare, and if so, whether it was routed for the 
entire year or only part of the year.
    (iii) Whether the acid gas removal unit or nitrogen removal unit 
vent was routed to combustion, and if so, whether it was routed for the 
entire year or only part of the year.
    (iv) Total feed rate entering the acid gas removal unit or nitrogen 
removal unit, using a meter or engineering estimate based on process 
knowledge or best available data, in million standard cubic feet per 
year.
    (v) If the acid gas removal unit or nitrogen removal unit was 
routed to a flare or to combustion for only part of the year, the feed 
rate entering the acid gas removal unit or nitrogen removal unit during 
the portion of the year that the emissions were vented directly to the 
atmosphere, using a meter or engineering estimate based on process 
knowledge or best available data, in million standard cubic feet per 
year.
    (vi) The calculation method used to calculate CO2 and 
CH4 emissions from the acid gas removal unit or to calculate 
CH4 emissions from the nitrogen removal unit, as specified 
in Sec.  98.233(d).
    (vii) Whether any CO2 emissions from the acid gas 
removal unit are recovered and transferred outside the facility, as 
specified in Sec.  98.233(d)(11). If any CO2 emissions from 
the acid gas removal unit were recovered and transferred outside the 
facility, then you must report the annual quantity of CO2, 
in metric tons CO2, that was recovered and transferred 
outside the facility under subpart PP of this part.
    (viii) Annual CO2 emissions, in metric tons 
CO2, vented directly to the atmosphere from the acid gas 
removal unit, calculated using any one of the calculation methods 
specified in Sec.  98.233(d) and as specified in Sec.  98.233(d)(10) 
and (11).
    (ix) Annual CH4 emissions, in metric tons 
CH4, vented directly to the atmosphere from the acid gas 
removal unit or nitrogen removal unit, calculated using any one of the 
calculation methods specified in Sec.  98.233(d) and as specified in 
Sec.  98.233(d)(10) and (11).
    (x) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (2) You must report information specified in paragraphs (d)(2)(i) 
through (iii) of this section, applicable to the calculation method 
reported in paragraph (d)(1)(iii) of this section, for each acid gas 
removal unit or nitrogen removal unit.
    (i) If you used Calculation Method 1 or Calculation Method 2 as 
specified in Sec.  98.233(d) to calculate CO2 emissions from 
the acid gas removal unit and Calculation Method 2 as specified in 
Sec.  98.233(d) to calculate CH4 emissions from the acid gas 
removal unit or nitrogen removal unit, then you must report the 
information specified in paragraphs (d)(2)(i)(A) through (C) of this 
section, as applicable.
    (A) Annual average volumetric fraction of CO2 in the 
vent gas exiting the acid gas removal unit.
    (B) Annual average volumetric fraction of CH4 in the 
vent gas exiting the acid gas removal unit or nitrogen removal unit.
    (C) Annual volume of gas vented from the acid gas removal unit or 
nitrogen removal unit, in cubic feet.
    (D) The temperature that corresponds to the reported annual volume 
of gas vented from the unit, in degrees Fahrenheit. If the annual 
volume of gas vented is reported in actual cubic feet, report the 
actual temperature; if it is reported in standard cubic feet, report 60 
[deg]F.
    (E) The pressure that corresponds to the reported annual volume of 
gas vented from the unit, in pounds per square inch absolute. If the 
annual volume of gas vented is reported in actual cubic feet, report 
the actual pressure; if it is reported in standard cubic feet, report 
14.7 psia.
    (ii) If you used Calculation Method 3 as specified in Sec.  
98.233(d) to calculate

[[Page 50421]]

CO2 or CH4 emissions from the acid gas removal 
unit or nitrogen removal unit, then you must report the information 
specified in paragraphs (d)(2)(ii)(A) through (M) of this section, as 
applicable depending on the equation used.
    (A) Indicate which equation was used (Equation W-4A, W-4B, or W-
4C).
    (B) Annual average volumetric fraction of CO2 in the 
natural gas flowing out of the acid gas removal unit, as specified in 
Equation W-4A, Equation W-4B, or Equation W-4C of this subpart.
    (C) Annual average volumetric fraction of CO2 content in 
natural gas flowing into the acid gas removal unit, as specified in 
Equation W-4A, Equation W-4B, or Equation W-4C of this subpart.
    (D) Annual average volumetric fraction of CO2 in the 
vent gas exiting the acid gas removal unit, as specified in Equation W-
4A or Equation W-4B of this subpart.
    (E) Annual average volumetric fraction of CH4 in the 
natural gas flowing out of the acid gas removal unit or nitrogen 
removal unit, as specified in Equation W-4A, Equation W-4B, or Equation 
W-4C of this subpart.
    (F) Annual average volumetric fraction of CH4 content in 
natural gas flowing into the acid gas removal unit or nitrogen removal 
unit, as specified in Equation W-4A, Equation W-4B, or Equation W-4C of 
this subpart.
    (G) Annual average volumetric fraction of CH4 in the 
vent gas exiting the acid gas removal unit or nitrogen removal unit, as 
specified in Equation W-4A or Equation W-4B of this subpart.
    (H) The total annual volume of natural gas flow into the acid gas 
removal unit or nitrogen removal unit, as specified in Equation W-4A or 
Equation W-4C of this subpart, in cubic feet at actual conditions.
    (I) The temperature that corresponds to the reported total annual 
volume of natural gas flow into the acid gas removal unit or nitrogen 
removal unit, as specified in Equation W-4A or Equation W-4C of this 
subpart, in degrees Fahrenheit. If the total annual volume of natural 
gas flow is reported in actual cubic feet, report the actual 
temperature; if it is reported in standard cubic feet, report 60 
[deg]F.
    (J) The pressure that corresponds to the reported total annual 
volume of natural gas flow into the acid gas removal unit or nitrogen 
removal unit, as specified in Equation W-4A or Equation W-4C of this 
subpart, in pounds per square inch absolute. If the total annual volume 
of natural gas flow is reported in actual cubic feet, report the actual 
pressure; if it is reported in standard cubic feet, report 14.7 psia.
    (K) The total annual volume of natural gas flow out of the acid gas 
removal unit or nitrogen removal unit, as specified in Equation W-4B or 
Equation W-4C of this subpart, in cubic feet at actual conditions.
    (L) The temperature that corresponds to the reported total annual 
volume of natural gas flow out of the acid gas removal unit or nitrogen 
removal unit, as specified in Equation W-4B or Equation W-4C of this 
subpart, in degrees Fahrenheit. If the total annual volume of natural 
gas flow is reported in actual cubic feet, report the actual 
temperature; if it is reported in standard cubic feet, report 60 
[deg]F.
    (M) The pressure that corresponds to the reported total annual 
volume of natural gas flow out of the acid gas removal unit or nitrogen 
removal unit, as specified in Equation W-4B or Equation W-4C of this 
subpart, in pounds per square inch absolute. If the total annual volume 
of natural gas flow is reported in actual cubic feet, report the actual 
pressure; if it is reported in standard cubic feet, report 14.7 psia.
    (iii) If you used Calculation Method 4 as specified in Sec.  
98.233(d) to calculate CO2 or CH4 emissions from 
the acid gas removal unit or nitrogen removal unit, then you must 
report the information specified in paragraphs (d)(2)(iii)(A) through 
(N) of this section, as applicable to the simulation software package 
used.
    (A) The name of the simulation software package used.
    (B) Annual average natural gas feed temperature, in degrees 
Fahrenheit.
    (C) Annual average natural gas feed pressure, in pounds per square 
inch.
    (D) Annual average natural gas feed flow rate, in standard cubic 
feet per minute.
    (E) Annual average acid gas content of the feed natural gas, in 
mole percent.
    (F) Annual average acid gas content of the outlet natural gas, in 
mole percent.
    (G) Annual average methane content of the feed natural gas, in mole 
percent.
    (H) Annual average methane content of the outlet natural gas, in 
mole percent.
    (I) Total annual unit operating hours, excluding downtime for 
maintenance or standby, in hours per year.
    (J) Annual average exit temperature of the natural gas, in degrees 
Fahrenheit.
    (K) Annual average solvent pressure, in pounds per square inch.
    (L) Annual average solvent temperature, in degrees Fahrenheit.
    (M) Annual average solvent circulation rate, in gallons per minute.
    (N) Solvent type used for the majority of the year, from one of the 
following options: SelexolTM, Rectisol[supreg], 
PurisolTM, Fluor Solvent, BenfieldTM, 20 wt% MEA, 
30 wt% MEA, 40 wt% MDEA, 50 wt% MDEA, and other (specify).
    (e) Dehydrators. You must indicate whether your facility contains 
any of the following equipment: Glycol dehydrators for which you 
calculated emissions using Calculation Method 1 according to Sec.  
98.233(e)(1), glycol dehydrators for which you calculated emissions 
using Calculation Method 2 according to Sec.  98.233(e)(2), and 
dehydrators that use desiccant. If your facility contains any of the 
equipment listed in this paragraph (e), then you must report the 
applicable information in paragraphs (e)(1) through (3) of this 
section.
    (1) For each glycol dehydrator for which you calculated emissions 
using Calculation Method 1 (as specified in Sec.  98.233(e)(1)), you 
must report the information specified in paragraphs (e)(1)(i) through 
(xviii) of this section for the dehydrator.
    (i) A unique name or ID number for the dehydrator. For the onshore 
petroleum and natural gas production and the onshore petroleum and 
natural gas gathering and boosting industry segments, a different name 
or ID may be used for a single dehydrator for each location it operates 
at in a given year.
    (ii) Annual average dehydrator feed natural gas flow rate, in 
million standard cubic feet per day.
    (iii) Annual average dehydrator feed natural gas water content, in 
pounds per million standard cubic feet.
    (iv) Annual average dehydrator outlet natural gas water content, in 
pounds per million standard cubic feet.
    (v) Dehydrator absorbent circulation pump type (e.g., natural gas 
pneumatic, air pneumatic, or electric).
    (vi) Annual average dehydrator absorbent circulation rate, in 
gallons per minute.
    (vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene 
glycol (DEG), or ethylene glycol (EG)).
    (viii) Whether stripping gas is used in dehydrator.
    (ix) Whether a flash tank separator is used in dehydrator.
    (x) Total time the dehydrator is operating during the year, in 
hours.
    (xi) Annual average temperature of the wet natural gas at the 
absorber inlet, in degrees Fahrenheit.
    (xii) Annual average pressure of the wet natural gas at the 
absorber inlet, in pounds per square inch gauge.
    (xiii) Annual average mole fraction of CH4 in wet 
natural gas.
    (xiv) Annual average mole fraction of CO2 in wet natural 
gas.
    (xv) Well-pad ID (for the onshore petroleum and natural gas 
production

[[Page 50422]]

industry segment only) or gathering and boosting site ID (for the 
onshore petroleum and natural gas gathering and boosting industry 
segment only).(xvi) If a flash tank separator is used in the 
dehydrator, then you must report the information specified in 
paragraphs (e)(1)(xvi)(A) through (F) of this section for the emissions 
from the flash tank vent, as applicable. If flash tank emissions were 
routed to a regenerator firebox/fire tubes, then you must also report 
the information specified in paragraphs (e)(1)(xvi)(G) through (I) of 
this section for the combusted emissions from the flash tank vent.
    (A) Whether any flash gas emissions are vented directly to the 
atmosphere, routed to a flare, routed to the regenerator firebox/fire 
tubes, routed to a vapor recovery system, used as stripping gas, or any 
combination.
    (B) Annual CO2 emissions, in metric tons CO2, 
from the flash tank when not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1) and, if 
applicable, (e)(4).
    (C) Annual CH4 emissions, in metric tons CH4, 
from the flash tank when not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1) and, if 
applicable, (e)(4).
    (D) Annual CO2 emissions, in metric tons CO2, 
that resulted from routing flash gas to a regenerator firebox/fire 
tubes, calculated according to Sec.  98.233(e)(5).
    (E) Annual CH4 emissions, in metric tons CH4, 
that resulted from routing flash gas to a regenerator firebox/fire 
tubes, calculated according to Sec.  98.233(e)(5).
    (F) Annual N2O emissions, in metric tons N2O, 
that resulted from routing flash gas to a regenerator firebox/fire 
tubes, calculated according to Sec.  98.233(e)(5).
    (G) Indicate whether the regenerator firebox/fire tubes was 
monitored with a CEMS. If a CEMS was used, then paragraphs 
(e)(1)(xvi)(E) and (F) and (e)(1)(xvi)(H) and (I) of this section do 
not apply.
    (H) Total volume of gas from the flash tank to a regenerator 
firebox/fire tubes, in standard cubic feet.
    (I) Average combustion efficiency, expressed as a fraction of gas 
from the flash tank combusted by a burning regenerator firebox/fire 
tubes.
    (xvii) Report the information specified in paragraphs 
(e)(1)(xvii)(A) through (F) of this section for the emissions from the 
still vent, as applicable. If still vent emissions were routed to a 
regenerator firebox/fire tubes, then you must also report the 
information specified in paragraphs (e)(1)(xvii)(G) through (I) of this 
section for the combusted emissions from the still vent.
    (A) Whether any still vent emissions are vented directly to the 
atmosphere, routed to a flare, routed to the regenerator firebox/fire 
tubes, routed to a vapor recovery system, used as stripping gas, or any 
combination.
    (B) Annual CO2 emissions, in metric tons CO2, 
from the still vent when not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1), and, if 
applicable, (e)(4).
    (C) Annual CH4 emissions, in metric tons CH4, 
from the still vent when not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1) and, if 
applicable, (e)(4).
    (D) Annual CO2 emissions, in metric tons CO2, 
that resulted from routing still vent gas to a regenerator firebox/fire 
tubes, calculated according to Sec.  [thinsp]98.233(e)(5).
    (E) Annual CH4 emissions, in metric tons CH4, 
that resulted from routing still vent gas to a regenerator firebox/fire 
tubes, calculated according to Sec.  [thinsp]98.233(e)(5).
    (F) Annual N2O emissions, in metric tons N2O, 
that resulted from routing still vent gas to a regenerator firebox/fire 
tubes, calculated according to Sec.  [thinsp]98.233(e)(5).
    (G) Indicate whether the regenerator firebox/fire tubes was 
monitored with a CEMS. If a CEMS was used, then paragraphs 
(e)(1)(xvii)(E) and (F) and (e)(1)(xvii)(H) and (I) of this section do 
not apply.
    (H) Total volume of gas from the still vent to a regenerator 
firebox/fire tubes, in standard cubic feet.
    (I) Average combustion efficiency, expressed as a fraction of gas 
from the still vent combusted by a burning regenerator firebox/fire 
tubes.
    (xviii) Name of the software package used.
    (2) You must report the information specified in paragraphs 
(e)(2)(i) through (vi) of this section for all glycol dehydrators with 
an annual average daily natural gas throughput greater than 0 million 
standard cubic feet per day and less than 0.4 million standard cubic 
feet per day for which you calculated emissions using Calculation 
Method 2 (as specified in Sec.  98.233(e)(2)) at the facility, well-
pad, or gathering and boosting site.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) The total number of dehydrators at the facility, well-pad, or 
gathering and boosting site for which you calculated emissions using 
Calculation Method 2.
    (iii) Whether any dehydrator emissions were routed to a vapor 
recovery system. If any dehydrator emissions were routed to a vapor 
recovery system, then you must report the total number of dehydrators 
at the facility that routed to a vapor recovery system.
    (iv) Whether any dehydrator emissions were routed to a control 
device that reduces CO2 and/or CH4 emissions 
other than a vapor recovery system or a flare or regenerator firebox/
fire tubes. If any dehydrator emissions were routed to a control device 
that reduces CO2 and/or CH4 emissions other than 
a vapor recovery system or a flare or regenerator firebox/fire tubes, 
then you must specify the type of control device(s) and the total 
number of dehydrators at the facility that were routed to each type of 
control device.
    (v) Whether any dehydrator emissions were routed to a flare or 
regenerator firebox/fire tubes. If any dehydrator emissions were routed 
to a flare or regenerator firebox/fire tubes, then you must report the 
information specified in paragraphs (e)(2)(v)(A) through (E) of this 
section.
    (A) The total number of dehydrators routed to a flare and the total 
number of dehydrators routed to regenerator firebox/fire tubes.
    (B) Total volume of gas from the flash tank to a regenerator 
firebox/fire tubes, in standard cubic feet.
    (C) Annual CO2 emissions, in metric tons CO2, 
for the dehydrators routed to a regenerator firebox/fire tubes reported 
in paragraph (e)(2)(v)(A) of this section, calculated according to 
Sec.  98.233(e)(5).
    (D) Annual CH4 emissions, in metric tons CH4, 
for the dehydrators routed to a regenerator firebox/fire tubes reported 
in paragraph (e)(2)(v)(A) of this section, calculated according to 
Sec.  98.233(e)(5).
    (E) Annual N2O emissions, in metric tons N2O, 
for the dehydrators routed to a regenerator firebox/fire tubes reported 
in paragraph (e)(2)(v)(A) of this section, calculated according to 
Sec.  98.233(e)(5).
    (vi) For dehydrator emissions that were not routed to a flare or 
regenerator firebox/fire tubes, report the information specified in 
paragraphs (e)(2)(vi)(A) and (B) of this section.
    (A) Annual CO2 emissions, in metric tons CO2, 
for emissions from all dehydrators reported in paragraph (e)(2)(ii) of 
this section that were not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(2) and, if 
applicable, (e)(4), where emissions are added together for all such 
dehydrators.

[[Page 50423]]

    (B) Annual CH4 emissions, in metric tons CH4, 
for emissions from all dehydrators reported in paragraph (e)(2)(ii) of 
this section that were not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(2) and, if 
applicable, (e)(4), where emissions are added together for all such 
dehydrators.
    (3) For dehydrators that use desiccant (as specified in Sec.  
98.233(e)(3)), you must report the information specified in paragraphs 
(e)(3)(i) through (vi) of this section for the entire facility.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) Count of desiccant dehydrators that had one or more openings 
during the calendar year at the facility, well-pad, or gathering and 
boosting site for which you calculated emissions using Calculation 
Method 3 as specified in paragraphs (e)(3)(ii)(A) through (C) of this 
section.
    (A) The total number of opened desiccant dehydrators.
    (B) The number of opened desiccant dehydrators that used 
deliquescing desiccant (e.g., calcium chloride or lithium chloride).
    (C) The number of opened desiccant dehydrators that used 
regenerative desiccant (e.g., molecular sieves, activated alumina, or 
silica gel).
    (iii) For desiccant dehydrators at the facility, well-pad, or 
gathering and boosting site identified in paragraph (e)(3)(ii)(A) of 
this section, total physical volume of all opened dehydrator vessels.
    (iv) For desiccant dehydrators at the facility, well-pad, or 
gathering and boosting site identified in paragraph (e)(3)(ii)(A) of 
this section, total number of dehydrator openings in the calendar year.
    (v) For desiccant dehydrators at the facility, well-pad, or 
gathering and boosting site identified in paragraph (e)(3)(ii)(A) of 
this section, whether any dehydrator emissions were routed to a vapor 
recovery system. If any dehydrator emissions were routed to a vapor 
recovery system, then you must report the total number of dehydrators 
at the facility that routed to a vapor recovery system.
    (vi) For desiccant dehydrators at the facility, well-pad, or 
gathering and boosting site identified in paragraph (e)(3)(ii)(A) of 
this section, whether any dehydrator emissions were routed to a control 
device that reduces CO2 and/or CH4 emissions 
other than a vapor recovery system or a flare or regenerator firebox/
fire tubes. If any dehydrator emissions were routed to a control device 
that reduces CO2 and/or CH4 emissions other than 
a vapor recovery system or a flare or regenerator firebox/fire tubes, 
then you must specify the type of control device(s) and the total 
number of dehydrators at the facility that were routed to each type of 
control device.
    (vii) For desiccant dehydrators at the facility, well-pad, or 
gathering and boosting site identified in paragraph (e)(3)(ii)(A) of 
this section, whether any dehydrator emissions were routed to a flare 
or regenerator firebox/fire tubes. If any dehydrator emissions were 
routed to a flare or regenerator firebox/fire tubes, then you must 
report the information specified in paragraphs (e)(3)(vii)(A) through 
(E) of this section.
    (A) The total number of dehydrators routed to a flare and the total 
number of dehydrators routed to regenerator firebox/fire tubes.
    (B) Total volume of gas from the flash tank to a regenerator 
firebox/fire tubes, in standard cubic feet.
    (C) Annual CO2 emissions, in metric tons CO2, 
for the dehydrators routed to a regenerator firebox/fire tubes reported 
in paragraph (e)(3)(vii)(A) of this section, calculated according to 
Sec.  98.233(e)(5).
    (D) Annual CH4 emissions, in metric tons CH4, 
for the dehydrators routed to a regenerator firebox/fire tubes reported 
in paragraph (e)(3)(vii)(A) of this section, calculated according to 
Sec.  98.233(e)(5).
    (E) Annual N2O emissions, in metric tons N2O, 
for the dehydrators routed to a regenerator firebox/fire tubes reported 
in paragraph (e)(3)(vii)(A) of this section, calculated according to 
Sec.  98.233(e)(5).
    (viii) For desiccant dehydrators at the facility, well-pad, or 
gathering and boosting site identified in paragraph (e)(3)(ii)(A) of 
this section that were not routed to a flare or regenerator firebox/
fire tubes, report the information specified in paragraphs 
(e)(3)(viii)(A) and (B) of this section.
    (A) Annual CO2 emissions, in metric tons CO2, 
for emissions from all desiccant dehydrators reported under paragraph 
(e)(3)(ii) of this section that are not venting to a flare or 
regenerator firebox/fire tubes, calculated according to Sec.  
98.233(e)(3) and, if applicable, (e)(4), and summing for all such 
dehydrators.
    (B) Annual CH4 emissions, in metric tons CH4, 
for emissions from all desiccant dehydrators reported in paragraph 
(e)(3)(ii) of this section that are not venting to a flare or 
regenerator firebox/fire tubes, calculated according to Sec.  
98.233(e)(3), and, if applicable, (e)(4), and summing for all such 
dehydrators.
    (f) * * *
    (1) For each well for which you used Calculation Method 1 to 
calculate natural gas emissions from well venting for liquids 
unloading, report the information specified in paragraphs (f)(1)(i) 
through (xii) of this section. Report information separately for wells 
by unloading type combination (with or without plunger lifts, automated 
or manual unloading).
    (i) Well ID number.
    (ii) Well tubing diameter and pressure group ID.
    (iii) Unloading type combination (with or without plunger lifts, 
automated or manual unloading).
    (iv) [Reserved]
    (v) Indicate whether the monitoring period used to determine the 
cumulative amount of time venting was not the full calendar year.
    (vi) Cumulative amount of time the well was vented (``Tp'' from 
Equation W-7A or W-7B of this subpart), in hours.
    (vii) Cumulative number of unloadings vented directly to the 
atmosphere for the well.
* * * * *
    (xi) For each well tubing diameter group and pressure group 
combination, you must report the information specified in paragraphs 
(f)(1)(xi)(A) through (F) of this section for each individual well not 
using a plunger lift that was tested during the year.
* * * * *
    (F) Unloading type (automated or manual).
    (xii) For each well tubing diameter group and pressure group 
combination, you must report the information specified in paragraphs 
(f)(1)(xii)(A) through (F) of this section for each individual well 
using a plunger lift that was tested during the year.
* * * * *
    (F) Unloading type (automated or manual).
    (2) For each well for which you used Calculation Method 2 or 3 (as 
specified in Sec.  93.233(f)) to calculate natural gas emissions from 
well venting for liquids unloading, you must report the information in 
paragraphs (f)(2)(i) through (xii) of this section. Report information 
separately for each calculation method and unloading type combination 
(with or without plunger lifts, automated or manual unloadings).
    (i) Well ID number.
* * * * *
    (iii) Unloading type combination (with or without plunger lifts, 
automated or manual unloadings).

[[Page 50424]]

    (iv) [Reserved]
    (v) Cumulative number of unloadings vented directly to the 
atmosphere for the well.
* * * * *
    (ix) Average flow-line rate of gas (average of ``SFRp'' 
from Equation W-8 or W-9 of this subpart, as applicable), at standard 
conditions in cubic feet per hour.
    (x) Cumulative amount of time that wells were left open to the 
atmosphere during unloading events (sum of ``HRp,q'' from 
Equation W-8 or W-9 of this subpart, as applicable), in hours.
    (xi) For each well without plunger lifts, the information in 
paragraphs (f)(2)(xi)(A) through (D) of this section.
    (A) Internal casing diameter (``CDp'' from Equation W-8 
of this subpart), in inches.
    (B) Well depth (``WDp'' from Equation W-8 of this 
subpart), in feet.
    (C) Shut-in pressure, surface pressure, or casing pressure 
(``SPp'' from Equation W-8 of this subpart), in pounds per 
square inch absolute.
    (D) The most recent calendar year Calculation Method 1 was used to 
calculate emissions from well venting for liquids unloading for wells 
without plunger lifts of the same sub-basin, well tubing diameter group 
and pressure group combination.
    (xii) For wells with plunger lifts, the information in paragraphs 
(f)(2)(xiii)(A) through (D) of this section.
    (A) Internal tubing diameter (``TDp'' from Equation W-9 
of this subpart), in inches.
    (B) Tubing depth (``WDp'' from Equation W-9 of this 
subpart), in feet.
    (C) Flow line pressure (``SPp'' from Equation W-9 of 
this subpart), in pounds per square inch absolute.
    (D) The most recent calendar year Calculation Method 1 was used to 
calculate emissions from well venting for liquids unloading for the 
wells with plunger lifts in the same sub-basin, well tubing diameter 
group and pressure group combination.
    (g) Completions and workovers with hydraulic fracturing. You must 
indicate whether your facility had any well completions or workovers 
with hydraulic fracturing during the calendar year. If your facility 
had well completions or workovers with hydraulic fracturing during the 
calendar year that vented directly to the atmosphere, then you must 
report information specified in paragraphs (g)(1) through (10) of this 
section, for each well. If your facility had well completions or 
workovers with hydraulic fracturing during the year that only routed to 
flares, then you must report the information specified in paragraphs 
(g)(1) through (3) of this section, for each well. Report information 
separately for completions and workovers.
    (1) Well ID number.
    (2) Well type combination (horizontal or vertical, flared or 
vented, reduced emission completion or not a reduced emission 
completion, gas well or oil well).
    (3) Number of completions or workovers for each well.
* * * * *
    (5) * * *
    (i) Cumulative gas flowback time, in hours, for all completions or 
workovers at the well from when gas is first detected until sufficient 
quantities are present to enable separation, and the cumulative 
flowback time, in hours, after sufficient quantities of gas are present 
to enable separation (sum of ``Tp,i'' and sum of 
``Tp,s'' values used in Equation W-10A of Sec.  98.233). You 
may delay the reporting of this data element if you indicate in the 
annual report that the well is a wildcat well and/or delineation well 
and the only wells in the same sub-basin and well type combination are 
wildcat wells and/or delineation wells. If you elect to delay reporting 
of this data element, you must report by the date specified in 
paragraph (cc) of this section the total number of hours of flowback 
from the well during completions or workovers.
    (ii) If the well is a measured well for the sub-basin and well-type 
combination, the flowback rate, in standard cubic feet per hour 
(average of ``FRs,p'' values used in Equation W-12A of Sec.  
98.233). You may delay the reporting of this data element if you 
indicate in the annual report that the well is a wildcat well and/or 
delineation well and the only wells that can be used for the 
measurement in the same sub-basin and well type combination are wildcat 
wells and/or delineation wells. If you elect to delay reporting of this 
data element, you must report by the date specified in paragraph (cc) 
of this section the measured flowback rate(s) during well completion or 
workover for the well.
    (iii) If you used Equation W-12C of Sec.  98.233 to calculate the 
average gas production rate for an oil well, then you must report the 
information specified in paragraphs (g)(6)(iii)(A) and (B) of this 
section.
    (A) Gas to oil ratio for the well in standard cubic feet of gas per 
barrel of oil (``GORp'' in Equation W-12C of Sec.  98.233). 
You may delay the reporting of this data element if you indicate in the 
annual report that the well is a wildcat well and/or delineation well 
and the only wells that can be used for the measurement in the same 
sub-basin and well type combination are wildcat wells and/or 
delineation wells. If you elect to delay reporting of this data 
element, you must report by the date specified in paragraph (cc) of 
this section the gas to oil ratio for the well.
    (B) Volume of oil produced during the first 30 days of production 
after completion of the newly drilled well or well workover using 
hydraulic fracturing, in barrels (``Vp'' in Equation W-12C 
of Sec.  98.233). You may delay the reporting of this data element if 
you indicate in the annual report that the well is a wildcat well and/
or delineation well and the only wells that can be used for the 
measurement in the same sub-basin and well type combination are wildcat 
wells and/or delineation wells. If you elect to delay reporting of this 
data element, you must report by the date specified in paragraph (cc) 
of this section the volume of oil produced during the first 30 days of 
production after well completion or workover for the well.
    (6) If you used Equation W-10B of Sec.  98.233 to calculate annual 
volumetric total gas emissions, then you must report the information 
specified in paragraphs (g)(6)(i) and (ii) of this section.
    (i) Vented natural gas volume, in standard cubic feet 
(``FVs,p'' in Equation W-10B of Sec.  98.233).
    (ii) Flow rate at the beginning of the period of time when 
sufficient quantities of gas are present to enable separation, in 
standard cubic feet per hour (``FRp,i'' in Equation W-10B of 
Sec.  98.233).
* * * * *
    (10) Indicate whether the completion(s) or workover(s) included 
flared emissions that are reported according to paragraph (n) of this 
section in addition to the vented emissions reported under paragraphs 
(g)(8) and (9) of this section.
    (h) * * *
    (1) For each well with one or more gas well completions without 
hydraulic fracturing and without flaring, report the information 
specified in paragraphs (h)(1)(i) through (vi) of this section.
    (i) Well ID number.
* * * * *
    (iii) Total number of hours that gas vented directly to the 
atmosphere during venting for all completions without hydraulic 
fracturing (``Tp'' for completions that vented directly to 
the atmosphere as used in Equation W-13B).
    (iv) Average daily gas production rate for all completions without 
hydraulic

[[Page 50425]]

fracturing without flaring, in standard cubic feet per hour 
(``Vp'' in Equation W-13B of Sec.  98.233). You may delay 
reporting of this data element if you indicate in the annual report 
that the well is a wildcat well and/or delineation well and the only 
wells that can be used for the measurement in the same sub-basin and 
well type combination are wildcat wells and/or delineation wells. If 
you elect to delay reporting of this data element, you must report by 
the date specified in paragraph (cc) of this section the measured 
average daily gas production rate during completions for the well.
* * * * *
    (2) For each well with one or more gas well completions without 
hydraulic fracturing and with flaring, report the information specified 
in paragraphs (h)(2)(i) through (iv) of this section.
    (i) Well ID number.
* * * * *
    (iii) Total number of hours that gas vented to a flare during 
venting for all completions without hydraulic fracturing (the sum of 
all ``Tp'' for completions that vented to a flare from 
Equation W-13B).
    (iv) Average daily gas production rate for all completions without 
hydraulic fracturing with flaring, in standard cubic feet per hour (the 
average of all ``Vp'' from Equation W-13B of Sec.  98.233). 
You may delay reporting of this data element if you indicate in the 
annual report that the well is a wildcat well and/or delineation well 
and the only wells that can be used for the measurement in the same 
sub-basin and well type combination are wildcat wells and/or 
delineation wells. If you elect to delay reporting of this data 
element, you must report by the date specified in paragraph (cc) of 
this section the measured average daily gas production rate during 
completions for the well.
    (3) For each well with one or more gas well workovers without 
hydraulic fracturing and without flaring, report the information 
specified in paragraphs (h)(3)(i) through (iv) of this section.
    (i) Well ID number.
* * * * *
    (4) For each well with one or more gas well workovers without 
hydraulic fracturing and with flaring, report the information specified 
in paragraphs (h)(4)(i) and (ii) of this section.
    (i) Well ID number.
    (ii) Number of workovers that flared gas.
    (i) Blowdown vent stacks. You must indicate whether your facility 
has blowdown vent stacks. If your facility has blowdown vent stacks, 
then you must report whether emissions were calculated by equipment or 
event type or by using flow meters or a combination of both. If you 
calculated emissions by equipment or event type for any blowdown vent 
stacks, then you must report the information specified in paragraph 
(i)(1) of this section considering, in aggregate, all blowdown vent 
stacks for which emissions were calculated by equipment or event type. 
If you calculated emissions using flow meters for any blowdown vent 
stacks, then you must report the information specified in paragraph 
(i)(2) of this section considering, in aggregate, all blowdown vent 
stacks for which emissions were calculated using flow meters. For the 
onshore natural gas transmission pipeline segment, you must also report 
the information in paragraph (i)(3) of this section. You must report 
the information specified in paragraphs (i)(1) through (3) of this 
section, as applicable, for each well-pad (for onshore production), 
each gathering and boosting site (for onshore petroleum and natural gas 
gathering and boosting), or facility (for all other applicable industry 
segments).
    (1) Report by equipment or event type. If you calculated emissions 
from blowdown vent stacks by the seven categories listed in Sec.  
98.233(i)(2)(iv)(A) for onshore petroleum and natural gas production, 
onshore natural gas processing, onshore natural gas transmission 
compression, underground natural gas storage, LNG storage, LNG import 
and export equipment, or onshore petroleum and natural gas gathering 
and boosting industry segments, then you must report the equipment or 
event types and the information specified in paragraphs (i)(1)(i) 
through (iv) of this section for each equipment or event type. If a 
blowdown event resulted in emissions from multiple equipment types, and 
the emissions cannot be apportioned to the different equipment types, 
then you may report the information in paragraphs (i)(1)(i) through 
(iv) of this section for the equipment type that represented the 
largest portion of the emissions for the blowdown event. If you 
calculated emissions from blowdown vent stacks by the eight categories 
listed in Sec.  98.233(i)(2)(iv)(B) for the natural gas distribution or 
onshore natural gas transmission pipeline segments, then you must 
report the pipeline segments or event types and the information 
specified in paragraphs (i)(1)(i) through (iv) of this section for each 
``equipment or event type'' (i.e., category). If a blowdown event 
resulted in emissions from multiple categories, and the emissions 
cannot be apportioned to the different categories, then you may report 
the information in paragraphs (i)(1)(i) through (iv) of this section 
for the ``equipment or event type'' (i.e., category) that represented 
the largest portion of the emissions for the blowdown event.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
* * * * *
    (2) Report by flow meter. If you elect to calculate emissions from 
blowdown vent stacks by using a flow meter according to Sec.  
98.233(i)(3), then you must report the information specified in 
paragraphs (i)(2)(i) through (iii) of this section.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) Annual CO2 emissions from all blowdown vent stacks 
for which emissions were calculated using flow meters, in metric tons 
CO2 (the sum of all CO2 mass emission values 
calculated according to Sec.  98.233(i)(3), for all flow meters).
    (iii) Annual CH4 emissions from all blowdown vent stacks 
at the facility, well-pad, or gathering and boosting site for which 
emissions were calculated using flow meters, in metric tons 
CH4, (the sum of all CH4 mass emission values 
calculated according to Sec.  98.233(i)(3), for all flow meters).
* * * * *
    (j) Hydrocarbon liquids and produced water storage tanks. You must 
indicate whether your facility sends hydrocarbon produced liquids and/
or produced water to atmospheric pressure storage tanks. If your 
facility sends hydrocarbon produced liquids and/or produced water to 
atmospheric pressure storage tanks, then you must indicate which 
Calculation Method(s) you used to calculate GHG emissions, and you must 
report the information specified in paragraphs (j)(1) and (2) of this 
section as applicable. If you used Calculation Method 1 or Calculation 
Method 2 of Sec.  98.233(j), and any atmospheric pressure storage tanks 
were observed to have malfunctioning dump valves during the calendar 
year, then you must indicate that dump valves were malfunctioning and 
must report the information specified in paragraph (j)(3) of this 
section.

[[Page 50426]]

    (1) If you used Calculation Method 1 or Calculation Method 2 of 
Sec.  98.233(j) to calculate GHG emissions, then you must report the 
information specified in paragraphs (j)(1)(i) through (xvi) of this 
section for each well-pad (for onshore petroleum and natural gas 
production), gathering and boosting site (for onshore petroleum and 
natural gas gathering and boosting), or facility (for all other 
applicable industry segments) and by calculation method and liquid 
type, as applicable. Onshore petroleum and natural gas gathering and 
boosting and onshore natural gas processing facilities do not report 
the information specified in paragraph (j)(1)(ix) of this section.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) Calculation method used, and name of the software package used 
if using Calculation Method 1.
    (iii) The total annual hydrocarbon liquids or produced water volume 
from gas-liquid separators and direct from wells or non-separator 
equipment that is sent to applicable atmospheric pressure storage 
tanks, in barrels. You may delay reporting of this data element for 
onshore production if you indicate in the annual report that wildcat 
wells and delineation wells are the only wells in the sub-basin with 
hydrocarbon liquids or produced water production flowing to gas-liquid 
separators or direct to atmospheric pressure storage tanks. If you 
elect to delay reporting of this data element, you must report by the 
date specified in paragraph (cc) of this section the total volume of 
hydrocarbon liquids or produced water from all wells and the well ID 
number(s) for the well(s) included in this volume.
    (iv) The average well, gas-liquid separator, or non-separator 
equipment temperature, in degrees Fahrenheit.
    (v) The average well, gas-liquid separator, or non-separator 
equipment pressure, in pounds per square inch gauge.
    (vi) For atmospheric pressure storage tanks receiving hydrocarbon 
liquids, the average sales oil or stabilized hydrocarbon liquids API 
gravity, in degrees.
    (vii) For atmospheric pressure storage tanks receiving hydrocarbon 
liquids, the flow-weighted average concentration (mole fraction) of 
CO2 in flash gas from atmospheric pressure storage tanks 
(calculated as the sum of all products of the concentration of 
CO2 in the flash gas for each storage tank times the total 
quantity of flash gas for that storage tank, divided by the sum of all 
flash gas emissions from storage tanks).
    (viii) The flow-weighted average concentration (mole fraction) of 
CH4 in flash gas from atmospheric pressure storage tanks 
(calculated as the sum of all products of the concentration of 
CH4 in the flash gas for each storage tank times the total 
quantity of flash gas for that storage tank, divided by the sum of all 
flash gas emissions from storage tanks).
    (ix) The number of wells sending hydrocarbon liquids or produced 
water to gas-liquid separators or directly to atmospheric pressure 
storage tanks.
    (x) Count of atmospheric pressure storage tanks specified in 
paragraphs (j)(1)(x)(A) through (F) of this section.
    (A) The number of fixed roof atmospheric pressure storage tanks.
    (B) The number of floating roof atmospheric pressure storage tanks.
    (C) The number of atmospheric pressure storage tanks that vented 
gas directly to the atmosphere and did not control emissions using a 
vapor recovery system and/or one or more flares at any point during the 
reporting year.
    (D) The number of atmospheric pressure storage tanks that routed 
emissions to a vapor recovery system at any point during the reporting 
year.
    (E) The number of atmospheric pressure storage tanks that routed 
emissions to one or more flares at any point during the reporting year.
    (F) The number of atmospheric pressure storage tanks in paragraph 
(j)(1)(x)(D) or (E) of this section that had an open or not properly 
seated thief hatch at some point during the year while the storage tank 
was also routing emissions to a vapor recovery system and/or a flare.
    (xi) For atmospheric pressure storage tanks receiving hydrocarbon 
liquids, annual CO2 emissions, in metric tons 
CO2, that resulted from venting gas directly to the 
atmosphere, calculated according to Sec.  98.233(j)(1) and (2).
    (xii) Annual CH4 emissions, in metric tons 
CH4, that resulted from venting gas directly to the 
atmosphere, calculated according to Sec.  98.233(j)(1) and (2).
    (xiii) For the atmospheric pressure storage tanks receiving 
hydrocarbon liquids identified in paragraphs (j)(1)(x)(D) of this 
section, total CO2 mass, in metric tons CO2, that 
was recovered during the calendar year using a vapor recovery system.
    (xiv) For the atmospheric pressure storage tanks identified in 
paragraphs (j)(1)(x)(D) of this section, total CH4 mass, in 
metric tons CH4, that was recovered during the calendar year 
using a vapor recovery system.
    (xv) For the atmospheric pressure storage tanks identified in 
paragraph (j)(1)(x)(F) of this section, the total volume of gas vented 
through open or not properly seated thief hatches, in scf, during 
periods while the storage tanks were also routing emissions to vapor 
recovery systems and/or flares.
    (2) If you used Calculation Method 3 to calculate GHG emissions, 
then you must report the information specified in paragraphs (j)(2)(i) 
through (iii) of this section.
    (i) Report the information specified in paragraphs (j)(2)(i)(A) 
through (H) of this section, at the facility level, for atmospheric 
pressure storage tanks where emissions were calculated using 
Calculation Method 3 of Sec.  98.233(j).
    (A) The total annual hydrocarbon liquids throughput that is sent to 
all atmospheric pressure storage tanks in the facility with emissions 
calculated using Calculation Method 3, in barrels. You may delay 
reporting of this data element for onshore production if you indicate 
in the annual report that wildcat wells and delineation wells are the 
only wells in the sub-basin with hydrocarbon liquids production that 
send hydrocarbon liquids to atmospheric pressure storage tanks. If you 
elect to delay reporting of this data element, you must report by the 
date specified in paragraph (cc) of this section the total annual 
hydrocarbon liquids throughput from all wells and the well ID number(s) 
for the well(s) included in this volume.
    (B) The total annual produced water throughput that is sent to all 
atmospheric pressure storage tanks in the facility with emissions 
calculated using Calculation Method 3, in barrels, specified in 
paragraphs (j)(2)(i)(B)(1) through (3) of this section. You may delay 
reporting of this data element for onshore production if you indicate 
in the annual report that wildcat wells and delineation wells are the 
only wells in the sub-basin flowing to gas-liquid separators or direct 
to atmospheric pressure storage tanks. If you elect to delay reporting 
of this data element, you must report by the date specified in 
paragraph (cc) of this section the total annual volume of produced 
water from all wells as specified in paragraphs (j)(2)(i)(B)(1) through 
(3) of this section and the well ID number(s) for the well(s) included 
in these volumes.
    (1) Total volume of produced water with pressure less than or equal 
to 50 psi.
    (2) Total volume of produced water with pressure greater than 50 
psi and less than or equal to 250 psi.
    (3) Total volume of produced water with pressure greater than 250 
psi.

[[Page 50427]]

    (C) An estimate of the fraction of hydrocarbon liquids throughput 
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric 
pressure storage tanks in the facility that controlled emissions with 
flares.
    (D) An estimate of the fraction of hydrocarbon liquids throughput 
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric 
pressure storage tanks in the facility that controlled emissions with 
vapor recovery systems.
    (E) An estimate of the fraction of total produced water throughput 
reported in paragraph (j)(2)(i)(B) of this section sent to atmospheric 
pressure storage tanks in the facility that controlled emissions with 
flares.
    (F) An estimate of the fraction of total produced water throughput 
reported in paragraph (j)(2)(i)(B) of this section sent to atmospheric 
pressure storage tanks in the facility that controlled emissions with 
vapor recovery systems.
    (G) The number of fixed roof atmospheric pressure storage tanks in 
the facility.
    (H) The number of floating roof atmospheric pressure storage tanks 
in the facility.
    (ii) Report the information specified in paragraphs (j)(2)(ii)(A) 
through (H) of this section for each well-pad (for onshore production), 
gathering and boosting site (for onshore petroleum and natural gas 
gathering and boosting), or facility (for all other applicable industry 
segments) with atmospheric pressure storage tanks receiving hydrocarbon 
liquids whose emissions were calculated using Sec.  98.233(j)(3)(i).
    (A) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (B) The number of atmospheric pressure storage tanks that did not 
control emissions with flares and for which emissions were calculated 
using Calculation Method 3.
    (C) The number of atmospheric pressure storage tanks that 
controlled emissions with flares and for which emissions were 
calculated using Calculation Method 3.
    (D) The number of atmospheric pressure storage tanks that had an 
open or not properly seated thief hatch at some point during the year 
while the storage tank was also routing emissions to a vapor recovery 
system and/or a flare.
    (E) The total number of separators, wells, or non-separator 
equipment with annual average daily hydrocarbon liquids throughput 
greater than 0 barrels per day and less than 10 barrels per day for 
which you used Calculation Method 3 (``Count'' from Equation W-15A of 
this subpart).
    (F) Annual CO2 emissions, in metric tons CO2, 
that resulted from venting gas directly to the atmosphere, calculated 
using Equation W-15A of Sec.  98.233(j) and adjusted using the 
requirements described in Sec.  98.233(j)(4), if applicable.
    (G) Annual CH4 emissions, in metric tons CH4, 
that resulted from venting gas directly to the atmosphere, calculated 
using Equation W-15A of Sec.  98.233(j) and adjusted using the 
requirements described in Sec.  98.233(j)(4), if applicable.
    (H) The total volume of gas vented through open or not properly 
seated thief hatches, in scf, during periods while the atmospheric 
pressure storage tanks were also routing emissions to vapor recovery 
systems and/or flares.
    (iii) Report the information specified in paragraphs (j)(2)(iii)(A) 
through (F) of this section for each well-pad (for onshore production), 
gathering and boosting site (for onshore petroleum and natural gas 
gathering and boosting), or facility (for onshore natural gas 
processing) with atmospheric pressure storage tanks receiving produced 
water whose emissions were calculated using Sec.  98.233(j)(3)(ii).
    (A) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (B) The number of atmospheric pressure storage tanks that did not 
control emissions with flares and for which emissions were calculated 
using Calculation Method 3.
    (C) The number of atmospheric pressure storage tanks that 
controlled emissions with flares and for which emissions were 
calculated using Calculation Method 3.
    (D) The number of atmospheric pressure storage tanks that had an 
open or not properly seated thief hatch at some point during the year 
while the storage tank was also routing emissions to a vapor recovery 
system and/or a flare.
    (E) Annual CH4 emissions, in metric tons CH4, 
that resulted from venting gas directly to the atmosphere, calculated 
using Equation W-15B of Sec.  98.233(j) and adjusted using the 
requirements described in Sec.  98.233(j)(4), if applicable.
    (F) The total volume of gas vented through open or not properly 
seated thief hatches, in scf, during periods while the atmospheric 
pressure storage tanks were also routing emissions to vapor recovery 
systems and/or flares.
    (3) If you used Calculation Method 1 or Calculation Method 2 of 
Sec.  98.233(j), and any gas-liquid separator liquid dump values did 
not close properly during the calendar year, then you must report the 
information specified in paragraphs (j)(3)(i) through (v) of this 
section for each well-pad (for onshore production), gathering and 
boosting site (for onshore petroleum and natural gas gathering and 
boosting), or facility (for all other applicable industry segments) by 
liquid type.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) The total number of gas-liquid separators whose liquid dump 
valves did not close properly during the calendar year.
    (iii) The total time the dump valves on gas-liquid separators did 
not close properly in the calendar year, in hours (sum of the 
``Tdv'' values used in Equation W-16 of this subpart).
    (iv) For atmospheric pressure storage tanks receiving hydrocarbon 
liquids, annual CO2 emissions, in metric tons 
CO2, that resulted from dump valves on gas-liquid separators 
not closing properly during the calendar year, calculated using 
Equation W-16 of this subpart.
    (v) Annual CH4 emissions, in metric tons CH4, 
that resulted from the dump valves on gas-liquid separators not closing 
properly during the calendar year, calculated using Equation W-16 of 
this subpart.
    (k) Condensate storage tanks. You must indicate whether your 
facility contains any condensate storage tanks. If your facility 
contains at least one condensate storage tank, then you must report the 
information specified in paragraphs (k)(1) and (2) of this section for 
each condensate storage tank vent stack.
    (1) For each condensate storage tank vent stack, report the 
information specified in (k)(1)(i) through (iv) of this section.
    (i) The unique name or ID number for the condensate storage tank 
vent stack.
    (ii) Indicate if a flare is attached to the condensate storage tank 
vent stack.
    (iii) Indicate whether scrubber dump valve leakage occurred for the 
condensate storage tank vent according to Sec.  98.233(k)(1).
    (iv) Which method specified in Sec.  98.233(k)(1) was used to 
determine if dump valve leakage occurred.
    (2) If scrubber dump valve leakage occurred for a condensate 
storage tank vent stack, as reported in paragraph

[[Page 50428]]

(k)(1)(iii) of this section, and the vent stack vented directly to the 
atmosphere during the calendar year, then you must report the 
information specified in paragraphs (k)(2)(i) through (v) of this 
section for each condensate storage vent stack where scrubber dump 
valve leakage occurred.
    (i) Which method specified in Sec.  98.233(k)(2) was used to 
measure the leak rate.
* * * * *
    (l) * * *
    (1) For oil wells not routed to a flare, you must report the 
information specified in paragraphs (l)(1)(i) through (vii) of this 
section for each well tested.
    (i) [Reserved]
    (ii) Well ID number.
    (iii) Number of well testing days for the tested well in the 
calendar year.
    (iv) Average gas to oil ratio for the tested well, in cubic feet of 
gas per barrel of oil.
    (v) Average flow rate for the tested well, in barrels of oil per 
day. You may delay reporting of this data element if you indicate in 
the annual report that the well is a wildcat well and/or delineation 
well and the only oil wells that are tested in the same basin are 
wildcat wells and/or delineation wells. If you elect to delay reporting 
of this data element, you must report by the date specified in 
paragraph (cc) of this section the measured average flow rate for the 
tested well.
* * * * *
    (2) For oil wells routed to a flare, you must report the 
information specified in paragraphs (l)(2)(i) through (v) of this 
section for each well tested. All reported data elements should be 
specific to the well for which Equation W-17A of Sec.  98.233 was used 
and for which well testing emissions were routed to flares.
    (i) [Reserved]
    (ii) Well ID number.
    (iii) Number of well testing days for the tested well in the 
calendar year.
    (iv) Average gas to oil ratio for the tested well, in cubic feet of 
gas per barrel of oil.
    (v) Average flow rate for the tested well, in barrels of oil per 
day. You may delay reporting of this data element if you indicate in 
the annual report that the well is a wildcat well and/or delineation 
well and the only wells that are tested in the same basin are wildcat 
wells and/or delineation wells. If you elect to delay reporting of this 
data element, you must report by the date specified in paragraph (cc) 
of this section the measured average flow rate for the tested well.
    (3) For gas wells not routed to a flare, you must report the 
information specified in paragraphs (l)(3)(i) through (vi) of this 
section for each well tested.
    (i) [Reserved]
    (ii) Well ID number.
    (iii) Number of well testing days for the tested well(s) in the 
calendar year.
    (iv) Average annual production rate for the tested well, in actual 
cubic feet per day. You may delay reporting of this data element if you 
indicate in the annual report that the well is a wildcat well and/or 
delineation well and the only wells that are tested in the same basin 
are wildcat wells and/or delineation wells. If you elect to delay 
reporting of this data element, you must report by the date specified 
in paragraph (cc) of this section the measured average annual 
production rate for the tested well.
* * * * *
    (4) For gas wells routed to a flare, you must report the 
information specified in paragraphs (l)(4)(i) through (iv) of this 
section for each well tested. All reported data elements should be 
specific to the well for which Equation W-17B of Sec.  98.233 was used 
and for which well testing emissions were routed to flares.
    (i) [Reserved]
    (ii) Well ID number.
    (iii) Number of well testing days for the tested well in the 
calendar year.
    (iv) Average annual production rate for the tested well, in actual 
cubic feet per day. You may delay reporting of this data element if you 
indicate in the annual report that the well is a wildcat well and/or 
delineation well and the only wells that are tested in the same basin 
are wildcat wells and/or delineation wells. If you elect to delay 
reporting of this data element, you must report by the date specified 
in paragraph (cc) of this section the measured average annual 
production rate for the tested well.
    (m) Associated natural gas. You must indicate whether any 
associated gas was vented or flared during the calendar year. If 
associated gas was vented during the calendar year, then you must 
report the information specified in paragraphs (m)(1) through (7) of 
this section for each well for which associated gas was vented. If 
associated gas was flared during the calendar year, then you must 
report the information specified in paragraphs (m)(1) through (3) of 
this section for each well for which associated gas was flared.
    (1) Well ID number.
* * * * *
    (4) Average gas to oil ratio, in standard cubic feet of gas per 
barrel of oil. Do not report the GOR if you vented or flared associated 
gas and used a continuous flow monitor to determine the total volume of 
associated gas vented or routed to the flare (i.e., if you did not use 
Equation W-18 for the well with associated gas venting or flaring 
emissions).
    (5) Volume of oil produced by the well, in barrels, in the calendar 
year only during the time periods in which associated gas was vented or 
flared (``Vp'' used in Equation W-18 of Sec.  98.233). You 
may delay reporting of this data element if you indicate in the annual 
report that the well is a wildcat well and/or delineation well and the 
only wells from which associated gas was vented or flared in the same 
sub-basin are wildcat wells and/or delineation wells. If you elect to 
delay reporting of this data element, you must report by the date 
specified in paragraph (cc) of this section the volume of oil produced 
by the well during the time periods in which associated gas venting and 
flaring was occurring. Do not report the volume of oil produced if you 
vented or flared associated gas and used a continuous flow monitor to 
determine the total volume of associated gas vented or routed to the 
flare (i.e., if you did not use Equation W-18 for the well with 
associated gas venting or flaring emissions).
    (6) Total volume of associated gas sent to sales or used on site 
and not sent to a vent or flare, in standard cubic feet, in the 
calendar year only during time periods in which associated gas was 
vented or flared (``SG'' value used in Equation W-18 of Sec.  
98.233(m)). You may delay reporting of this data element if you 
indicate in the annual report that the well is a wildcat well and/or 
delineation well and the only wells from which associated gas was 
vented or flared in the same basin are wildcat wells and/or delineation 
wells. If you elect to delay reporting of this data element, you must 
report by the date specified in paragraph (cc) of this section the 
measured total volume of associated gas sent to sales for the well 
during the time periods in which associated gas venting and flaring was 
occurring. Do not report the volume of gas sent to sales if you vented 
or flared associated gas and used a continuous flow monitor to 
determine the total volume of associated gas vented or routed to the 
flare (i.e., if you did not use Equation W-18).
    (7) If you had associated gas emissions vented directly to the 
atmosphere without flaring, then you must report the information 
specified in paragraphs (m)(7)(i) through (viii) of this section for 
each well.
    (i) [Reserved]
    (ii) Indicate whether the associated gas volume vented from the 
well was

[[Page 50429]]

measured using a continuous flow monitor.
    (iii) Indicate whether associated gas streams vented from the well 
were measured with continuous gas composition analyzers.
    (iv) Total volume of associated gas vented from the well, in 
standard cubic feet.
    (v) Flow-weighted average mole fraction of CH4 in 
associated gas vented from the well.
    (vi) Flow-weighted average mole fraction of CO2 in 
associated gas vented from the well.
    (vii) Annual CO2 emissions, in metric tons 
CO2, calculated according to Sec.  98.233(m)(3) and (4).
    (viii) Annual CH4 emissions, in metric tons 
CH4, calculated according to Sec.  98.233(m)(3) and (4).
    (n) Flare stacks. You must indicate if your facility has any flare 
stacks. You must report the information specified in paragraphs (n)(1) 
through (20) of this section for each flare stack at your facility.
    (1) Unique name or ID for the flare stack. For the onshore 
petroleum and natural gas production and onshore petroleum and natural 
gas gathering and boosting industry segments, a different name or ID 
may be used for a single flare stack for each location where it 
operates at in a given calendar year.
    (2) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (3) Unique IDs for each stream routed to the flare if you measure 
the flow of each stream that is routed to the flare as specified in 
Sec.  98.233(n)(1)(ii) and/or you measure the gas composition for each 
stream routed to the flare as specified in Sec.  98.233(n)(3)(iii) or 
(iv).
    (4) Indicate the type of flare (i.e., open ground-level flare, 
enclosed ground-level flare, open elevated flare, or enclosed elevated 
flare).
    (5) Indicate the type of flare assist (i.e., unassisted, air-
assisted with single speed fan/blower, air-assisted with dual speed 
fan/blower, air-assisted with variable speed fan/blower, steam-
assisted, or pressure-assisted).
    (6) Indicate whether the pilot flame or combustion flame was 
monitored continuously, visually inspected, or both. If visually 
inspected, report the number of inspections during the year, and 
indicate whether the flare has a continuous pilot or auto igniter. If 
the pilot flame was monitored continuously, report the number of times 
the continuous monitoring device was out of service or otherwise 
inoperable for a period of more than one week.
    (7) Indicate whether the volume of gas was determined using a 
continuous flow measurement device or whether it was determined using 
parameter monitoring and engineering calculations (Sec.  
98.233(n)(1)(i) for inlet gas to the flare or Sec.  98.233(n)(1)(ii) 
for each stream routed to the flare). If you switched from one method 
to the other during the year, then indicate both methods were used.
    (8) Indicate whether the gas composition was calculated using a 
continuous gas composition analyzer or by taking samples of the 
applicable gas stream(s) at least once per quarter (Sec.  
98.233(n)(3)(i) or (iii) for the inlet gas to the flare or Sec.  
98.233(n)(3)(ii) or (iv) for the streams from each source that routes 
emissions to the flare). If you switched from one method to the other 
during the year, then indicate both methods were used.
    (9) Flare-specific HHV, if you determined a flare-specific HHV 
based on measured composition of the inlet gas to the flare as 
specified in Sec.  98.233(n)(8)(i) or if you calculated a flare-
specific HHV based on the calculated flow-weighted average composition 
for the inlet gas to the flare as specified in Sec.  98.233(n)(8)(iii). 
Each individual stream HHV, if you determined HHVs for each individual 
stream routed to the flare and you used these HHVs to calculate 
N2O emissions for each stream as specified in Sec.  
98.233(n)(8)(ii).
    (10) For the onshore petroleum and natural gas production, onshore 
petroleum and natural gas gathering and boosting, and onshore natural 
gas processing industry segments, estimated fraction of total volume 
flared that was received from another facility solely for flaring 
(e.g., gas separated from liquid at a production facility that is 
routed to a flare that is assigned to an onshore petroleum and natural 
gas gathering and boosting facility).
    (11) Volume of gas sent to the flare, in standard cubic feet 
(``Vs'' in Equations W-19 and W-20 of this subpart). If you 
determine the volume of gas for each stream routed to the flare as 
specified in Sec.  98.233(n)(1)(ii), then also report the annual volume 
of each measured stream.
    (12) Fraction of the feed gas sent to an un-lit flare based on 
total time when continuous monitoring of the pilot or periodic 
inspections indicated the flare was not lit and the flow determined by 
continuous measurement of flow conducted during the times when the 
flare was not lit (``Zu'' in Equation W-19 of this subpart).
    (13) Flare combustion efficiency, expressed as the fraction of gas 
combusted by a burning flare (Sec.  98.233(n)(4)). If you used multiple 
monitoring methods during the year, report the flow-weighted average 
combustion efficiency based on each tier that applied. Report the 
efficiency to one decimal place.
    (i) If you report using the 95 percent default combustion 
efficiency, indicate if you are subject to part 60, subpart OOOOb of 
this chapter or if you are electing to comply with the flare monitoring 
requirements in part 60, subpart OOOOb of this chapter.
    (ii) If you are not required to comply with part 60, subpart OOOOb 
of this chapter but you elect to comply with the monitoring 
requirements in Sec.  60.5417b(d)(1)(viii) of this chapter as specified 
in Sec.  98.233(n)(4), indicate whether you use a calorimeter to 
continuously determine net heating value (NHV) or if you have 
demonstrated according to the methods described in Sec.  
60.5417b(d)(1)(viii)(C) of this chapter that the NHV consistently 
exceeds the operating limit specified in Sec.  60.18 of this chapter 
(or that it consistently exceeds 800 Btu/scf for a pressure assist 
flare).
    (14) Annual average mole fraction of CH4 in the feed gas 
to the flare if you measure composition of the inlet gas as specified 
in Sec.  98.233(n)(3)(i) or (ii) (``XCH4'' in Equation W-19 
of this subpart), or the annual average CH4 mole fractions 
for each stream if you measure composition of each stream routed to the 
flare as specified in Sec.  98.233(n)(3)(iii) or (iv).
    (15) Annual average mole fraction of CO2 in the feed gas 
to the flare if you measure composition of the inlet gas as specified 
in Sec.  98.233(n)(3)(i) or (ii) (``XCO2'' in Equation W-20 
of this subpart), or the annual average CO2 mole fractions 
for each stream if you measure composition of each stream routed to the 
flare as specified in Sec.  98.233(n)(3)(iii) or (iv).
    (16) Annual CO2 emissions, in metric tons CO2 
(refer to Equation W-20 of this subpart).
    (17) Annual CH4 emissions, in metric tons CH4 
(refer to Equation W-19 of this subpart).
    (18) Annual N2O emissions, in metric tons N2O 
(refer to Equation W-40 of this subpart).
    (19) Estimated disaggregated CH4, CO2, and 
N2O emissions attributed to each source type as determined 
using engineering calculations and best available data as specified in 
Sec.  98.233(n)(10) (i.e., AGR vents, dehydrator vents, well venting 
during completions and workovers with

[[Page 50430]]

hydraulic fracturing, gas well venting during completions and workovers 
without hydraulic fracturing, hydrocarbon liquids and produced water 
storage tanks, well testing venting and flaring, associated gas venting 
and flaring, other flared sources).
    (20) Indicate whether a CEMS was used to measure emissions from the 
flare. If a CEMS was used, then you are not required to report the 
CO2 mole fraction in paragraph (n)(15) of this section.
    (o) Centrifugal compressors. You must indicate whether your 
facility has centrifugal compressors. You must report the information 
specified in paragraphs (o)(1) and (2) of this section for all 
centrifugal compressors at your facility. For each compressor source or 
manifolded group of compressor sources that you conduct as found leak 
measurements as specified in Sec.  98.233(o)(2) or (4), you must report 
the information specified in paragraph (o)(3) of this section. For each 
compressor source or manifolded group of compressor sources that you 
conduct continuous monitoring as specified in Sec.  98.233(o)(3) or 
(5), you must report the information specified in paragraph (o)(4) of 
this section. Centrifugal compressors in onshore petroleum and natural 
gas production and onshore petroleum and natural gas gathering and 
boosting that calculate emissions according to Sec.  98.233(o)(10)(iii) 
are not required to report information in paragraphs (o)(1) through (4) 
of this section and instead must report the information specified in 
paragraph (o)(5) of this section.
    (1) Compressor activity data. Report the information specified in 
paragraphs (o)(1)(i) through (xi) of this section, as applicable, for 
each centrifugal compressor located at your facility.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) Unique name or ID for the centrifugal compressor.
    (iii) Hours in operating-mode.
    (iv) Hours in standby-pressurized-mode.
    (v) Hours in not-operating-depressurized-mode.
    (vi) If you conducted volumetric emission measurements as specified 
in Sec.  98.233(o)(1):
    (A) Indicate whether the compressor was measured in operating-mode.
    (B) Indicate whether the compressor was measured in standby-
pressurized-mode.
    (C) Indicate whether the compressor was measured in not-operating-
depressurized-mode.
    (vii) Indicate whether the compressor has blind flanges installed 
and associated dates.
    (viii) Indicate whether the compressor has wet or dry seals.
    (ix) If the compressor has wet seals, the number of wet seals.
    (x) If the compressor has dry seals, the number of dry seals.
    (xi) Power output of the compressor driver (hp).
    (2) * * *
    (i) * * *
    (A) Centrifugal compressor name or ID. Use the same ID as in 
paragraph (o)(1)(ii) of this section.
    (B) Centrifugal compressor source (wet seal, dry seal, isolation 
valve, or blowdown valve).
* * * * *
    (ii) * * *
    (A) Indicate whether the leak or vent is for a single compressor 
source or manifolded group of compressor sources and whether the 
emissions from the leak or vent are released to the atmosphere, routed 
to a flare, combustion, or vapor recovery system.
* * * * *
    (D) Report emissions as specified in paragraphs (o)(2)(ii)(D)(1) 
and (2) of this section for the leak or vent. If the leak or vent is 
routed to a flare, combustion, or vapor recovery system, you are not 
required to report emissions under this paragraph.
* * * * *
    (E) If the leak or vent is routed to flare, combustion, or vapor 
recovery system, report the percentage of time that the respective 
device was operational when the compressor source emissions were routed 
to the device.
* * * * *
    (5) Onshore petroleum and natural gas production and onshore 
petroleum and natural gas gathering and boosting. Centrifugal 
compressors with wet seal degassing vents in onshore petroleum and 
natural gas production and onshore petroleum and natural gas gathering 
and boosting that calculate emissions according to Sec.  
98.233(o)(10)(iii) must report the information specified in paragraphs 
(o)(5)(i) through (iv) of this section. You must report the information 
specified in paragraphs (o)(5)(i) through (iv) of this section, as 
applicable, for each well-pad (for onshore petroleum and natural gas 
production) or each gathering and boosting site (for onshore petroleum 
and natural gas gathering and boosting).
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) Report the following activity data.
    (A) Total number of centrifugal compressors at the facility.
    (B) Number of centrifugal compressors that have wet seals.
    (C) Number of centrifugal compressors that have atmospheric wet 
seal oil degassing vents (i.e., wet seal oil degassing vents where the 
emissions are released to the atmosphere rather than being routed to 
flares, combustion, or vapor recovery systems).
    (iii) Annual CO2 emissions, in metric tons 
CO2, from centrifugal compressors with atmospheric wet seal 
oil degassing vents.
    (iv) Annual CH4 emissions, in metric tons 
CH4, from centrifugal compressors with atmospheric wet seal 
oil degassing vents.
    (p) Reciprocating compressors. You must indicate whether your 
facility has reciprocating compressors. You must report the information 
specified in paragraphs (p)(1) and (2) of this section for all 
reciprocating compressors at your facility. For each compressor source 
or manifolded group of compressor sources that you conduct as found 
leak measurements as specified in Sec.  98.233(p)(2) or (4), you must 
report the information specified in paragraph (p)(3) of this section. 
For each compressor source or manifolded group of compressor sources 
that you conduct continuous monitoring as specified in Sec.  
98.233(p)(3) or (5), you must report the information specified in 
paragraph (p)(4) of this section. Reciprocating compressors in onshore 
petroleum and natural gas production and onshore petroleum and natural 
gas gathering and boosting that calculate emissions according to Sec.  
98.233(p)(10)(iii) are not required to report information in paragraphs 
(p)(1) through (4) of this section and instead must report the 
information specified in paragraph (p)(5) of this section.
    (1) Compressor activity data. Report the information specified in 
paragraphs (p)(1)(i) through (viii) of this section, as applicable, for 
each reciprocating compressor located at your facility.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) Unique name or ID for the reciprocating compressor.
    (iii) Hours in operating-mode.
    (iv) Hours in standby-pressurized-mode.

[[Page 50431]]

    (v) Hours in not-operating-depressurized-mode.
    (vi) If you conducted volumetric emission measurements as specified 
in Sec.  98.233(p)(1):
    (A) Indicate whether the compressor was measured in operating-mode.
    (B) Indicate whether the compressor was measured in standby-
pressurized-mode.
    (C) Indicate whether the compressor was measured in not-operating-
depressurized-mode.
    (vii) Indicate whether the compressor has blind flanges installed 
and associated dates.
    (viii) Power output of the compressor driver (hp).
    (2) * * *
    (ii) * * *
    (A) Indicate whether the leak or vent is for a single compressor 
source or manifolded group of compressor sources and whether the 
emissions from the leak or vent are released to the atmosphere, routed 
to a flare, combustion, or vapor recovery system.
* * * * *
    (D) Report emissions as specified in paragraphs (p)(2)(ii)(D)(1) 
and (2) of this section for the leak or vent. If the leak or vent is 
routed to a flare, combustion, or vapor recovery system, you are not 
required to report emissions under this paragraph.
* * * * *
    (E) If the leak or vent is routed to a flare, combustion, or vapor 
recovery system, report the percentage of time that the respective 
device was operational when the compressor source emissions were routed 
to the device.
    (3) * * *
    (ii) For each compressor mode-source combination where a reporter 
emission factor as calculated in Equation W-28 was used to calculate 
emissions in Equation W-27, report the information specified in 
paragraphs (p)(3)(ii)(A) through (D) of this section.
* * * * *
    (5) Onshore petroleum and natural gas production and onshore 
petroleum and natural gas gathering and boosting. Reciprocating 
compressors in onshore petroleum and natural gas production and onshore 
petroleum and natural gas gathering and boosting that calculate 
emissions according to Sec.  98.233(p)(10)(iii) must report the 
information specified in paragraphs (p)(5)(i) through (iv) of this 
section. You must report the information specified in paragraphs 
(p)(5)(i) through (iv) of this section, as applicable, for each well-
pad (for onshore petroleum and natural gas production) or each 
gathering and boosting site (for onshore petroleum and natural gas 
gathering and boosting).
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) Report the following activity data.
    (A) Total number of reciprocating compressors at the facility.
    (B) Number of reciprocating compressors that have rod packing 
emissions vented directly to the atmosphere (i.e., rod packing vents 
where the emissions are released to the atmosphere rather than being 
routed to flares, combustion, or vapor recovery systems).
    (iii) Annual CO2 emissions, in metric tons 
CO2, from reciprocating compressors with rod packing 
emissions vented directly to the atmosphere.
    (iv) Annual CH4 emissions, in metric tons 
CH4, from reciprocating compressors with rod packing 
emissions vented directly to the atmosphere.
    (q) Equipment leak surveys. For any components subject to or 
complying with the requirements of Sec.  98.233(q), you must report the 
information specified in paragraphs (q)(1) and (2) of this section. You 
must report the information specified in paragraphs (q)(1) and (2) of 
this section, as applicable, for each well-pad (for onshore 
production), gathering and boosting site (for onshore petroleum and 
natural gas gathering and boosting), or facility (for all other 
applicable industry segments). Natural gas distribution facilities with 
emission sources listed in Sec.  98.232(i)(1) must also report the 
information specified in paragraph (q)(3) of this section.
    (1) You must report the information specified in paragraphs 
(q)(1)(i) through (ix) of this section.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) Except as specified in paragraph (q)(1)(iii) of this section, 
the number of complete equipment leak surveys performed during the 
calendar year.
    (iii) Natural gas distribution facilities performing equipment leak 
surveys across a multiple year leak survey cycle must report the number 
of years in the leak survey cycle.
    (iv) Except for natural gas distribution facilities, indicate 
whether any of the leak detection surveys used in calculating emissions 
per Sec.  98.233(q)(2) were conducted for compliance with any of the 
standards in paragraphs (q)(1)(iv)(A) through (E) of this section. 
Report the indication per well-pad, gathering and boosting site, or 
facility, not per component type, as applicable.
    (A) The well site or compressor station fugitive emissions 
standards in Sec.  60.5397a of this chapter.
    (B) The well site, centralized production facility, or compressor 
station fugitive emissions standards in Sec.  60.5397b of this chapter.
    (C) The well site, centralized production facility, or compressor 
station fugitive emissions standards in an applicable approved state 
plan or applicable Federal plan in part 62 of this chapter.
    (D) The standards for equipment leaks at onshore natural gas 
processing plants in Sec.  60.5400b of this chapter.
    (E) The standards for equipment leaks at onshore natural gas 
processing plants in an applicable approved state plan or applicable 
Federal plan in part 62 of this chapter.
    (v) For facilities in onshore petroleum and natural gas production, 
onshore petroleum and natural gas gathering and boosting, onshore 
natural gas transmission compression, underground natural gas storage, 
LNG storage, and LNG import and export equipment, indicate whether you 
elected to comply with Sec.  98.233(q) according to Sec.  
98.233(q)(1)(iv) for any equipment components at your well-pad, 
gathering and boosting site, or facility.
    (vi) Report each type of method described in Sec.  98.234(a) that 
was used to conduct leak surveys.
    (vii) Report whether emissions were calculated using Calculation 
Method 1 (leaker factor emission calculation methodology) and/or using 
Calculation Method 2 (leaker measurement methodology).
    (viii) For facilities in onshore petroleum and natural gas 
production and onshore petroleum and natural gas gathering and 
boosting, report the number of major equipment (as listed in Table W-1) 
by service type for which leak detection surveys were conducted and 
emissions calculated according to Sec.  98.233(q).
    (ix) For facilities in onshore petroleum and natural gas production 
and onshore petroleum and natural gas gathering and boosting, report 
the number of major equipment (as listed in Table W-1) in vacuum 
service as defined in Sec.  98.238.
    (2) You must indicate whether your facility contains any of the 
component types subject to or complying with Sec.  98.233(q) that are 
listed in Sec.  98.232(c)(21), (d)(7), (e)(7) or (8), (f)(5) through 
(8), (g)(4), (g)(6) or (7), (h)(5), (h)(7) or (8), (i)(1), or (j)(10) 
for your facility's industry segment. For each component type and leak 
detection

[[Page 50432]]

method combination that is located at your well-pad, gathering and 
boosting site, or facility, you must report the information specified 
in paragraphs (q)(2)(i) through (ix) of this section. If a component 
type is located at your well-pad, gathering and boosting site, or 
facility and no leaks were identified from that component, then you 
must report the information in paragraphs (q)(2)(i) through (ix) of 
this section but report a zero (``0'') for the information required 
according to paragraphs (q)(2)(vi) through (ix) of this section. If you 
used Calculation Method 1 (leaker factor emission calculation 
methodology) for some complete leak surveys and used Calculation Method 
2 (leaker measurement methodology) for some complete leak surveys, you 
must report the information specified in paragraphs (q)(2)(i) through 
(ix) of this section separately for component surveys using Calculation 
Method 1 and Calculation Method 2.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) Component type.
    (iii) Leak detection method used for the screening survey (e.g., 
Method 21 as specified in Sec.  98.234(a)(2)(i); Method 21 as specified 
in Sec.  98.234(a)(2)(ii); and OGI and other leak detection methods as 
specified in Sec.  98.234(a)(1), (3), or (5)).
    (iv) Emission factor or measurement method used (e.g., default 
emission factor; site-specific emission factor developed according to 
Sec.  98.233(q)(4); or direct measurement according to Sec.  
98.233(q)(3)).
    (v) Total number of components surveyed by type and leak detection 
method in the calendar year.
    (vi) Total number of the surveyed component types by leak detection 
method that were identified as leaking in the calendar year 
(``xp'' in Equation W-30 of this subpart for the component 
type or the number of leaks measured for the specified component type 
according to the provisions in Sec.  98.233(q)(3)).
    (vii) Average time the surveyed components are assumed to be 
leaking and operational, in hours (average of ``Tp,z'' from 
Equation W-30 of this subpart for the component type or average 
duration of leaks for the specified component type determined according 
to the provisions in Sec.  98.233(q)(3)(ii)).
    (viii) Annual CO2 emissions, in metric tons 
CO2, for the component type as calculated using Equation W-
30 or Sec.  98.233(q)(3)(vii) (for surveyed components only).
    (ix) Annual CH4 emissions, in metric tons 
CH4, for the component type as calculated using Equation W-
30 or Sec.  98.233(q)(3)(vii) (for surveyed components only).
* * * * *
    (r) Equipment leaks by population count. If your facility is 
subject to the requirements of Sec.  98.233(r), then you must report 
the information specified in paragraphs (r)(1) through (3) of this 
section, as applicable. You must report the information specified in 
paragraphs (r)(1) through (3) of this section, as applicable, for each 
well-pad (for onshore petroleum and natural gas production), gathering 
and boosting site (for onshore petroleum and natural gas gathering and 
boosting), or facility (for all other applicable industry segments).
    (1) You must indicate whether your facility contains any of the 
emission source types required to use Equation W-32A of Sec.  98.233. 
You must report the information specified in paragraphs (r)(1)(i) 
through (vi) of this section separately for each emission source type 
required to use Equation W-32A that is located at your facility. For 
each well-pad and gathering and boosting site at onshore petroleum and 
natural gas production facilities and onshore petroleum and natural gas 
gathering and boosting facilities you must report the information 
specified in paragraphs (r)(1)(i) through (vi) of this section 
separately by equipment type and service type.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) Emission source type. Onshore petroleum and natural gas 
production facilities and onshore petroleum and natural gas gathering 
and boosting facilities must report the equipment type and service 
type.
    (iii) Total number of the emission source type at the well-pad, 
gathering and boosting site, or facility, as applicable 
(``Counte'' in Equation W-32A of this subpart).
    (iv) Average estimated time that the emission source type was 
operational in the calendar year, in hours (``Te'' in 
Equation W-32A of this subpart).
    (v) Annual CO2 emissions, in metric tons CO2, 
for the emission source type.
    (vi) Annual CH4 emissions, in metric tons 
CH4, for the emission source type.
* * * * *
    (3) You must indicate whether your facility contains any emission 
source types in vacuum service as defined in Sec.  98.238. If your 
facility contains equipment in vacuum service, you must report the 
information specified in paragraphs (r)(3)(i) through (iii) of this 
section separately for each emission source type in vacuum service that 
is located at your well-pad, gathering and boosting site, or facility, 
as applicable.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) Emission source type.
    (iii) Total number of the emission source type at the well-pad, 
gathering and boosting site, or facility, as applicable.
    (s) Offshore petroleum and natural gas production. You must report 
the information specified in paragraphs (s)(1) through (3) of this 
section for your facility.
    (1) For facilities that report to BOEM's emissions inventory, the 
BOEM Facility ID(s) that correspond(s) to this facility.
    (2) If you adjusted emissions according to Sec.  98.233(s)(1)(i) or 
(s)(2)(i), report the information specified in paragraphs (s)(2)(i) and 
(ii) of this section.
    (i) Facility operating hours for the year of the most recent BOEM 
emissions inventory.
    (ii) Facility operating hours for the current year.
    (3) For each emission source type listed in the most recently 
published BOEM emissions inventory, report the information specified in 
paragraphs (s)(3)(i) through (iii) of this section.
    (i) Annual CO2 emissions, in metric tons CO2.
    (ii) Annual CH4 emissions, in metric tons 
CH4.
    (iii) Annual N2O emissions, in metric tons 
N2O.
* * * * *
    (x) * * *
    (1) Well-pad ID.
* * * * *
    (y) Other large release events. You must indicate whether there 
were any other large release events from your facility during the 
reporting year and indicate whether your facility was notified of a 
potential super-emitter release under the provisions of Sec.  60.5371b 
of this chapter or an applicable approved state plan or applicable 
Federal plan in part 62 of this chapter. If there were any other large 
release events, you must report the total number of other large release 
events from your facility that occurred during the reporting year and, 
for each

[[Page 50433]]

other large release event, report the information specified in 
paragraphs (y)(1) through (10) of this section. If you received a 
notification of a potential super-emitter release from a third-party 
for this facility or a super-emitter release notification under the 
provisions of Sec.  60.5371b of this chapter or an applicable approved 
state plan or applicable Federal plan in part 62 of this chapter, you 
must also report the information specified in paragraph (y)(11) of this 
section.
    (1) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (2) Unique release event identification number (e.g., Event 1, 
Event 2).
    (3) The latitude and longitude of the release in decimal degrees to 
at least four digits to the right of the decimal point.
    (4) The approximate start date, start time, and duration (in hours) 
of the release event, and an indication of how the start date and time 
were determined (determined based on pressure monitor, temperature 
monitor, other monitored process parameter (specify), assigned based on 
last monitoring or measurement survey showing no large release, or used 
the 182-day default maximum duration).
    (5) A general description of the event. Include:
    (i) Identification of the equipment involved in the release.
    (ii) A description of how the release occurred, from one of the 
following categories: maintenance event, fire/explosion, gas well 
blowout, oil well blowout, gas well release, oil well release, pressure 
relief, large leak, and other (specify).
    (iii) An indication of whether the release exceeded a threshold in 
Sec.  98.233(y)(1)(i) or in Sec.  98.233(y)(1)(ii).
    (iv) A description of the technology or method used to identify the 
release.
    (v) An indication of whether the release was identified under the 
provisions of Sec.  60.5371b of this chapter or an applicable approved 
state plan or applicable Federal plan in part 62 of this chapter or a 
third-party notification and, if the release was identified under the 
provisions of Sec.  60.5371b of this chapter or an applicable approved 
state plan or applicable Federal plan in part 62 of this chapter or a 
third-party notification, a unique notification ID number for the 
notification as assigned in paragraph (y)(11)(i) of this section.
    (vi) An indication of whether a portion of the natural gas released 
was combusted during the release, and if so, the fraction of the 
natural gas released that was estimated to be combusted and the assumed 
combustion efficiency for the combusted natural gas.
    (6) The total volume of gas released during the event in standard 
cubic feet.
    (7) The volume fraction of CO2 in the gas released 
during the event.
    (8) The volume fraction of CH4 in the gas released 
during the event.
    (9) Annual CO2 emissions, in metric tons CO2, 
from the release event that occurred during the reporting year.
    (10) Annual CH4 emissions, in metric tons 
CH4, from the release event that occurred during the 
reporting year and the maximum CH4 emissions rate, in 
kilograms per hour, determined for any period of the event according to 
the provisions of Sec.  98.233(y)(2)(i).
    (11) Report the total number of super-emitter release notifications 
received from a third party for this facility during the reporting year 
and, for each such super-emitter release notification, report the 
information specified in paragraphs (y)(11)(i) through (vi) of this 
section.
    (i) Unique notification identification number (e.g., 
Notification_01, Notification_02). If a unique notification number was 
provided with a notification received under the provisions of Sec.  
60.5371b of this chapter, an applicable approved state plan, or 
applicable Federal plan in part 62 of this chapter, report the number 
associated with the event provided in the notification.
    (ii) The latitude and longitude of the release as provided in the 
notification.
    (iii) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only) to which the notification was attributed.
    (iv) An indication of whether the super-emitter release 
notification was received under the provisions of Sec.  60.5371b of 
this chapter, an applicable approved state plan, or applicable Federal 
plan in part 62 of this chapter, or from another third-party. If the 
notification was received from another third-party, report the 
following information about the notifier and data received, if known.
    (A) The name of the person and/or company that provided the 
notification.
    (B) The method used during by the notifier to quantify the 
emissions (satellite detection; remote-sensing equipment on aircraft; 
mobile monitoring platform; other, specify; or unknown).
    (C) The date(s) and time(s) the measurement was made.
    (D) The measured methane emission rate and uncertainty bounds (in 
kilograms per hour).
    (v) Based on any assessment or investigation triggered by the 
notification, indicate if the emissions were from normal operations, a 
planned maintenance event, leaking equipment, malfunctioning equipment 
or device, or undetermined cause.
    (vi) An indication of whether the emissions identified via the 
notification are included in annual emissions reported for under this 
subpart and, if so, the source type under which those emissions are 
reported. If the emissions were reported following the requirements of 
Sec.  98.233(y) as an other large release event, report the unique 
release event identification number assigned to the other large release 
event as reported in paragraph (y)(2) of this section. If the emissions 
identified via the notification are not included in annual emissions 
reported under this subpart, you must provide the reason for not 
including the emissions related to this notification (the emissions 
could not be verified or corroborated during site inspection or 
facility data records; the location of the emissions as provided in the 
notification do not belong to the facility; the information was 
determined not to be credible, explain; other, specify).
    (z) Combustion equipment at onshore petroleum and natural gas 
production facilities, onshore petroleum and natural gas gathering and 
boosting facilities, and natural gas distribution facilities. If your 
facility is required by Sec.  98.232(c)(22), (i)(7), or (j)(12) to 
report emissions from combustion equipment, then you must indicate 
whether your facility has any combustion units subject to reporting 
according to paragraph (a)(1)(xx), (a)(8)(vi), or (a)(9)(xiii) of this 
section. If your facility contains any combustion units subject to 
reporting according to paragraph (a)(1)(xx), (a)(8)(vi), or 
(a)(9)(xiii) of this section, then you must report the information 
specified in paragraphs (z)(1) and (2) of this section, as applicable. 
You must report the information specified in paragraphs (z)(1) and (2) 
of this section, as applicable, for each well-pad (for onshore 
petroleum and natural gas production), gathering and boosting site (for 
onshore petroleum and natural gas gathering and boosting), or facility 
(for all other applicable industry segments).
    (1) Indicate whether the combustion units include: External fuel 
combustion units with a rated heat capacity less than or equal to 5 
million Btu per hour; or, internal fuel combustion units that are not 
compressor-drivers, with a rated

[[Page 50434]]

heat capacity less than or equal to 1 mmBtu/hr (or the equivalent of 
130 horsepower). If the facility contains external fuel combustion 
units with a rated heat capacity less than or equal to 5 million Btu 
per hour or internal fuel combustion units that are not compressor-
drivers, with a rated heat capacity less than or equal to 1 million Btu 
per hour (or the equivalent of 130 horsepower), then you must report 
the information specified in paragraphs (z)(1)(i) through (iii) of this 
section for each unit type.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) The type of combustion unit.
    (iii) The total number of combustion units.
    (2) Indicate whether the combustion units include: External fuel 
combustion units with a rated heat capacity greater than 5 million Btu 
per hour; internal fuel combustion units that are not compressor-
drivers, with a rated heat capacity greater than 1 million Btu per hour 
(or the equivalent of 130 horsepower); or, internal fuel combustion 
units of any heat capacity that are compressor-drivers. For each type 
of combustion unit at your facility, you must report the information 
specified in paragraphs (z)(2)(i) through (iv) and (z)(2)(viii) through 
(x) of this section, except for internal fuel combustion units that are 
not compressor-drivers, with a rated heat capacity greater than 1 
million Btu per hour (or the equivalent of 130 horsepower) or internal 
fuel combustion units of any heat capacity that are compressor-drivers 
that combust natural gas meeting the criteria in Sec.  98.233(z)(1) or 
(2), which must report the information specified in paragraphs 
(z)(2)(i) through (x) of this section. Information must be reported for 
each combustion unit type, fuel type, and method for determining the 
CH4 emission factor combination, as applicable.
    (i) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (ii) The type of combustion unit including external fuel combustion 
units with a rated heat capacity greater than 5 million Btu per hour; 
internal fuel combustion units that are not compressor-drivers, with a 
rated heat capacity greater than 1 million Btu per hour (or the 
equivalent of 130 horsepower); or internal fuel combustion units of any 
heat capacity that are compressor-drivers.
    (iii) The type of fuel combusted.
    (iv) The quantity of fuel combusted in the calendar year, in 
thousand standard cubic feet, gallons, or tons.
    (v) The equipment type, including reciprocating 2-stroke-lean burn, 
reciprocating 4-stroke lean-burn, reciprocating 4-stroke rich-burn, and 
gas turbine.
    (vi) The method used to determine the methane emission factor, 
including the default emission factor from Table W-7 of subpart W, OEM 
data, or performance tests in Sec.  98.234(i).
    (vii) The value of the CH4 emission factor (kg 
CH4/mmBtu).
    (viii) Annual CO2 emissions, in metric tons 
CO2, calculated according to Sec.  98.233(z)(1) through (3).
    (ix) Annual CH4 emissions, in metric tons 
CH4, calculated according to Sec.  98.233(z)(1) through (3).
    (x) Annual N2O emissions, in metric tons N2O, 
calculated according to Sec.  98.233(z)(1) through (3).
    (aa) Industry segment-specific information. Each facility must 
report the information specified in paragraphs (aa)(1) through (11) of 
this section, for each applicable industry segment, determined using a 
flow meter that meets the requirements of Sec.  98.234(b) for 
quantities that are sent to sale or through the facility and determined 
by using best available data for other quantities. If a quantity 
required to be reported is zero, you must report zero as the value.
    (1) For onshore petroleum and natural gas production, report the 
data specified in paragraphs (aa)(1)(i) and (iv) of this section.
    (i) Report the information specified in paragraphs (aa)(1)(i)(A) 
through (D) of this section for the basin as a whole, unless otherwise 
specified.
* * * * *
    (B) The quantity of natural gas produced from producing wells that 
is sent to sale in the calendar year, in thousand standard cubic feet.
    (C) The quantity of crude oil produced from producing wells that is 
sent to sale in the calendar year, in barrels.
    (D) The quantity of condensate produced from producing wells that 
is sent to sale in the calendar year, in barrels.
    (ii) * * *
    (D) The number of producing wells at the end of the calendar year 
(exclude only those wells permanently shut-in and plugged).
    (E) The number of producing wells acquired during the calendar 
year.
    (F) The number of producing wells divested during the calendar 
year.
    (G) The number of wells completed during the calendar year.
    (H) The number of wells permanently shut-in and plugged during the 
calendar year.
* * * * *
    (iii) Report the information specified in paragraphs 
(aa)(1)(iii)(A) through (E) of this section for each well located in 
the facility.
    (A) Well ID number.
    (B) Well-pad ID.
    (C) For each well permanently shut-in and plugged during the 
calendar year, the quantity of natural gas produced that is sent to 
sale in the calendar year, in thousand standard cubic feet.
    (D) For each well permanently shut-in and plugged during the 
calendar year, the quantity of crude oil produced that is sent to sale 
in the calendar year, in barrels.
    (E) For each well permanently shut-in and plugged during the 
calendar year, the quantity of condensate produced that is sent to sale 
in the calendar year, in barrels.
    (iv) Report the information specified in paragraphs (aa)(1)(iv)(A) 
through (F) of this section for each well-pad located in the facility.
    (A) A unique name or ID number for the well-pad.
    (B) Sub-basin ID.
    (C) The latitude and longitude of the well-pad representing the 
geographic centroid or center point of the well-pad in decimal degrees 
to at least four digits to the right of the decimal point.
    (D) For each well-pad with a well that was permanently shut-in and 
plugged during the calendar year, report the quantity of gas produced 
from all producing wells on the well-pad that is sent to sale in the 
calendar year, in thousand standard cubic feet.
    (E) For each well-pad with a well that was permanently shut-in and 
plugged during the calendar year, report the quantity of crude oil 
produced from all producing wells on the well-pad that is sent to sale 
in the calendar year for sales, in barrels.
    (F) For each well-pad with a well that was permanently shut-in and 
plugged during the calendar year, report the quantity of condensate 
produced from all producing wells on the well-pad that is sent to sale 
in the calendar year, in barrels.
    (2) For offshore production, report the quantities specified in 
paragraphs (aa)(2)(i) through (vi) of this section.
    (i) The quantity of natural gas produced from producing wells that 
is sent to sale in the calendar year, in thousand standard cubic feet.

[[Page 50435]]

    (ii) The quantity of crude oil produced from producing wells that 
is sent to sale in the calendar year, in barrels.
    (iii) The quantity of condensate produced from producing wells that 
is sent to sale in the calendar year, in barrels.
    (iv) For each well permanently shut-in and plugged during the 
calendar year, the quantity of natural gas produced that is sent to 
sale in the calendar year, in thousand standard cubic feet.
    (v) For each well permanently shut-in and plugged during the 
calendar year, the quantity of crude oil produced that is sent to sale 
in the calendar year, in barrels.
    (vi) For each well permanently shut-in and plugged during the 
calendar year, the quantity of condensate produced that is sent to sale 
in the calendar year, in barrels.
    (3) For natural gas processing, if your facility fractionates NGLs 
and also reports as a supplier to subpart NN of this part, you must 
report the information specified in paragraphs (aa)(3)(ii) and 
(aa)(3)(v) through (ix) of this section. Otherwise, report the 
information specified in paragraphs (aa)(3)(i) through (ix) of this 
section.
    (i) The quantity of natural gas received at the gas processing 
plant for processing in the calendar year, in thousand standard cubic 
feet.
* * * * *
    (viii) Indicate whether the facility reports as a supplier to 
subpart NN of this part.
    (ix) The quantity of residue gas leaving that has been processed by 
the facility and any gas that passes through the facility to sales 
without being processed by the facility.
    (4) * * *
    (i) The quantity of natural gas transported through the compressor 
station in the calendar year, in thousand standard cubic feet.
* * * * *
    (5) * * *
    (ii) The quantity of natural gas withdrawn from storage and sent to 
sale in the calendar year, in thousand standard cubic feet.
* * * * *
    (6) For LNG import equipment, report the quantity of LNG imported 
that is sent to sale in the calendar year, in thousand standard cubic 
feet.
    (7) For LNG export equipment, report the quantity of LNG exported 
that is sent to sale in the calendar year, in thousand standard cubic 
feet.
    (8) * * *
    (ii) The quantity of LNG withdrawn from storage and sent to sale in 
the calendar year, in thousand standard cubic feet.
* * * * *
    (10) For onshore petroleum and natural gas gathering and boosting 
facilities, report the quantities specified in paragraphs (aa)(10)(i) 
through (v) of this section.
* * * * *
    (ii) The quantity of natural gas transported through the facility 
to a downstream endpoint such as a natural gas processing facility, a 
natural gas transmission pipeline, a natural gas distribution pipeline, 
a storage facility, or another gathering and boosting facility in the 
calendar year, in thousand standard cubic feet.
* * * * *
    (iv) The quantity of all hydrocarbon liquids transported to a 
downstream endpoint such as a natural gas processing facility, a 
natural gas transmission pipeline, a natural gas distribution pipeline, 
a storage facility, or another gathering and boosting facility in the 
calendar year, in barrels.
    (v) Report the information specified in paragraphs (aa)(10)(v)(A) 
through (E) of this section for each gathering and boosting site 
located in the facility.
    (A) A unique name or ID number for the gathering and boosting site.
    (B) Gathering and boosting site type (gathering compressor station, 
centralized oil production site, gathering pipeline, or other fence-
line site).
    (C) State.
    (D) For gathering compressor stations, centralized oil production 
sites, and other fence-line sites, county.
    (E) For gathering compressor stations, centralized oil production 
sites, and other fence-line sites, the latitude and longitude of the 
gathering and boosting site representing the geographic centroid or 
center point of the site in decimal degrees to at least four digits to 
the right of the decimal point.
    (11) * * *
    (ii) The quantity of natural gas withdrawn from underground natural 
gas storage and LNG storage (regasification) facilities owned and 
operated by the onshore natural gas transmission pipeline owner or 
operator that are not subject to this subpart in the calendar year, in 
thousand standard cubic feet.
    (iii) The quantity of natural gas added to underground natural gas 
storage and LNG storage (liquefied) facilities owned and operated by 
the onshore natural gas transmission pipeline owner or operator that 
are not subject to this subpart in the calendar year, in thousand 
standard cubic feet.
    (iv) The quantity of natural gas transported through the facility 
and transferred to third parties such as LDCs or other transmission 
pipelines, in thousand standard cubic feet.
* * * * *
    (bb) Missing data. For any missing data procedures used, report the 
information in Sec.  98.3(c)(8) and the procedures used to substitute 
an unavailable value of a parameter, except as provided in paragraphs 
(bb)(1) and (2) of this section.
* * * * *
    (cc) Delay in reporting for wildcat wells and delineation wells. If 
you elect to delay reporting the information in paragraph (g)(5)(i) or 
(ii), (g)(5)(iii)(A) or (B), (h)(1)(iv), (h)(2)(iv), (j)(1)(iii), 
(j)(2)(i)(A), (l)(1)(v), (l)(2)(v), (l)(3)(iv), (l)(4)(iv), or (m)(5) 
or (6) of this section, you must report the information required in 
that paragraph no later than the date 2 years following the date 
specified in Sec.  98.3(b) introductory text.
    (dd) Drilling mud degassing. You must indicate whether there were 
mud degassing operations at your facility, and if so, which methods (as 
specified in Sec.  98.233(dd)) were used to calculate emissions. For 
wells for which your facility performed mud degassing operations and 
used Calculation Method 1, then you must report the information 
specified in paragraph (dd)(1) of this section. For wells for which 
your facility performed mud degassing operations and used Calculation 
Method 2, then you must report the information specified in paragraph 
(dd)(2) of this section.
    (1) For each well for which you used Calculation Method 1 to 
calculate natural gas emissions from mud degassing, report the 
information specified in paragraphs (dd)(1)(i) through (vii) of this 
section.
    (i) Well ID number.
    (ii) Approximate total depth below surface, in feet.
    (iii) Total time that drilling mud is circulated in the well, in 
minutes.
    (iv) The composition of the drilling mud: water-based, oil-based, 
or synthetic.
    (v) If the well is not a representative well, Well ID number of the 
representative well used to derive the CH4 emission rate 
used to calculate CH4 emissions for this well.
    (vi) If the well is a representative well, report the information 
specified in paragraphs (dd)(1)(vi)(A) through (D) of this section.
    (A) Average mud rate, in gallons per minute.
    (B) Concentration of natural gas in the drilling mud (Xn 
in Equation W-41), in parts per million.

[[Page 50436]]

    (C) Measured mole fraction for CH4 in natural gas 
entrained in the drilling mud (GHGCH4 in Equation W-41).
    (D) Calculated CH4 emissions rate in standard cubic per 
minute (ERs,CH4,r in Equation W-42).
    (vii) Annual CH4 emissions, in metric tons 
CH4, from well drilling mud degassing, calculated according 
to Sec.  98.233(dd)(1).
    (2) For each well for which you used Calculation Method 2 to 
calculate natural gas emissions from mud degassing, report the 
information specified in paragraphs (dd)(2)(i) through (iv) of this 
section.
    (i) Well ID number.
    (ii) Total number of drilling days.
    (iii) The composition of the drilling mud: water-based, oil-based, 
or synthetic.
    (iv) Annual CH4 emissions, in metric tons 
CH4, from drilling mud degassing, calculated according to 
Sec.  98.233(dd)(2).
    (ee) Crankcase vents. You must indicate whether your facility 
performs any crankcase venting from reciprocating internal combustion 
engines or gas turbines. If your facility contains at least one 
crankcase vent on an applicable engine, you must report the information 
specified in paragraphs (ee)(1) through (4) of this section for each 
well-pad (for onshore petroleum and natural gas production), gathering 
and boosting site (for onshore petroleum and natural gas gathering and 
boosting), or facility (for all other applicable industry segments).
    (1) Well-pad ID (for the onshore petroleum and natural gas 
production industry segment only) or gathering and boosting site ID 
(for the onshore petroleum and natural gas gathering and boosting 
industry segment only).
    (2) Total number of crankcase vents at the well-pad, gathering and 
boosting site, or facility, as applicable (``Count'' in Equation W-45 
of this subpart).
    (3) Average estimated time that the reciprocating internal 
combustion engines or gas turbines with crankcase venting were 
operational in the calendar year, in hours (``T'' in Equation W-45 of 
this subpart).
    (4) Annual CH4 emissions, in metric tons CH4, 
calculated according to Sec.  98.233(ee)(1).
0
16. Amend Sec.  98.238 by:
0
a. Removing the definition for ``Acid gas removal vent emissions'' and 
adding the definition for ``Acid gas removal unit (AGR) vent 
emissions'' in alphabetical order;
0
b. Adding definitions for ``Atmospheric pressure storage tank,'' 
``Automated liquids unloading,'' and ``Centralized oil production 
site'' in alphabetical order;
0
c. Revising the definitions for ``Compressor mode'' and ``Compressor 
source'';
0
d. Adding definitions for ``Crankcase venting,'' ``Drilling mud,'' and 
``Drilling mud degassing'' in alphabetical order;
0
e. Removing the second definition for ``Facility with respect to 
natural gas distribution for purposes of reporting under this subpart 
and for the corresponding subpart A requirements'';
0
f. Revising the definitions for ``Flare stack emissions'' and ``Forced 
extraction of natural gas liquids'';
0
g. Adding the definition for ``Gathering and boosting site'' in 
alphabetical order;
0
h. Revising the definitions for ``Gathering and boosting system'' and 
``Gathering and boosting system owner or operator''; and
0
i. Adding definitions for ``Gathering compressor station,'' ``Gathering 
pipeline site,'' ``In vacuum service,'' ``Manual liquids unloading,'' 
``Mud rate,'' ``Nitrogen removal unit (NRU),'' ``Nitrogen removal unit 
vent emissions,'' ``Other large release event,'' ``Produced water,'' 
``Routed to combustion,'' ``Well blowout,'' and ``Well release'' in 
alphabetical order.
    The additions and revisions read as follows:


Sec.  98.238  Definitions.

* * * * *
    Acid gas removal unit (AGR) vent emissions mean the acid gas 
separated from the acid gas absorbing medium (e.g., an amine solution) 
and released with methane and other light hydrocarbons to the 
atmosphere or a flare.
* * * * *
    Atmospheric pressure storage tank means a vessel (excluding sumps) 
operating at atmospheric pressure that is designed to contain an 
accumulation of crude oil, condensate, intermediate hydrocarbon 
liquids, or produced water and that is constructed entirely of non-
earthen materials (e.g., wood, concrete, steel, plastic) that provide 
structural support. Atmospheric pressure storage tanks include both 
fixed roof tanks and floating roof tanks. Floating roof tanks include 
tanks with either an internal floating roof or an external floating 
roof.
    Automated liquids unloading means an unloading that is performed 
without manual interference. Examples of automated liquids unloadings 
include a timing and/or pressure device used to optimize intermittent 
shut-in of the well before liquids choke off gas flow or to open and 
close valves, continually operating equipment that does not require 
presence of an operator such as rod pumping units, automated and 
unmanned plunger lifts, or other unloading activities that do not 
entail a physical presence at the well-pad.
* * * * *
    Centralized oil production site means any permanent combination of 
one or more hydrocarbon liquids storage tanks located on one or more 
contiguous or adjacent properties that does not also contain a 
permanent combination of one or more compressors that are part of the 
onshore petroleum and natural gas gathering and boosting facility that 
gathers hydrocarbon liquids from multiple well-pads. A centralized oil 
production site is a type of gathering and boosting site for purposes 
of reporting under Sec.  98.236.
* * * * *
    Compressor mode means the operational and pressurized status of a 
compressor. For both centrifugal compressors and reciprocating 
compressors, ``mode'' refers to either: Operating-mode, standby-
pressurized-mode, or not-operating-depressurized-mode.
    Compressor source means the source of certain venting or leaking 
emissions from a centrifugal or reciprocating compressor. For 
centrifugal compressors, ``source'' refers to blowdown valve leakage 
through the blowdown vent, unit isolation valve leakage through an open 
blowdown vent without blind flanges, wet seal oil degassing vents, and 
dry seal vents. For reciprocating compressors, ``source'' refers to 
blowdown valve leakage through the blowdown vent, unit isolation valve 
leakage through an open blowdown vent without blind flanges, and rod 
packing emissions.
* * * * *
    Crankcase venting means the process of venting or removing blow-by 
from the void spaces of an internal combustion engine outside of the 
combustion cylinders to prevent excessive pressure build-up within the 
engine. This does not include ingestive systems that vent blow-by into 
the engine where it is returned to the combustion process.
* * * * *
    Drilling mud means a mixture of clays and additives with water, 
oil, or synthetic materials. While drilling, the drilling mud is 
continuously pumped through the drill string and out the bit to cool 
and lubricate the drill bit, and move cuttings through the wellbore to 
the surface.
    Drilling mud degassing means the practice of safely removing 
pockets of free gas entrained in the drilling mud once it is outside of 
the wellbore.
* * * * *

[[Page 50437]]

    Flare stack emissions means CO2 in gas routed to a 
flare, CO2 from partial combustion of hydrocarbons in gas 
routed to a flare, CH4 emissions resulting from the 
incomplete combustion of hydrocarbons in gas routed to a flare, and 
N2O resulting from operation of a flare.
    Forced extraction of natural gas liquids means removal of ethane or 
higher carbon number hydrocarbons existing in the vapor phase in 
natural gas, by removing ethane or heavier hydrocarbons derived from 
natural gas into natural gas liquids by means of a forced extraction 
process. Forced extraction processes include but are not limited to 
refrigeration, absorption (lean oil), cryogenic expander, and 
combinations of these processes. Forced extraction does not include in 
and of itself; natural gas dehydration, the collection or gravity 
separation of water or hydrocarbon liquids from natural gas at ambient 
temperature or heated above ambient temperatures, the condensation of 
water or hydrocarbon liquids through passive reduction in pressure or 
temperature, a Joule-Thomson valve, a dew point depression valve, or an 
isolated or standalone Joule-Thomson skid.
    Gathering and boosting site means a single gathering compressor 
station as defined in this section, centralized oil production site as 
defined in this section, gathering pipeline site as defined in this 
section, or other fence-line site within the onshore petroleum and 
natural gas gathering and boosting industry segment.
    Gathering and boosting system means a single network of pipelines, 
compressors and process equipment, including equipment to perform 
natural gas compression, dehydration, and acid gas removal, that has 
one or more connection points to gas and oil production or one or more 
other gathering and boosting systems and a downstream endpoint, 
typically a gas processing plant, transmission pipeline, LDC pipeline, 
or other gathering and boosting system.
    Gathering and boosting system owner or operator means any person 
that holds a contract in which they agree to transport petroleum or 
natural gas from one or more onshore petroleum and natural gas 
production wells or one or more other gathering and boosting systems to 
a natural gas processing facility, another gathering and boosting 
system, a natural gas transmission pipeline, or a distribution 
pipeline, or any person responsible for custody of the petroleum or 
natural gas transported.
    Gathering compressor station means any permanent combination of one 
or more compressors located on one or more contiguous or adjacent 
properties that are part of the onshore petroleum and natural gas 
gathering and boosting facility that move natural gas at increased 
pressure through gathering pipelines or into or out of storage. A 
gathering compressor station is a type of gathering and boosting site 
for purposes of reporting under Sec.  98.236.
    Gathering pipeline site means all of the gathering pipelines within 
a single state. A gathering pipeline site is a type of gathering and 
boosting site for purposes of reporting under Sec.  98.236.
* * * * *
    In vacuum service means equipment operating at an internal pressure 
which is at least 5 kilopascals (kPa) (0.7 psia) below ambient 
pressure.
* * * * *
    Manual liquids unloading means an unloading when field personnel 
attend to the well at the well-pad, for example to manually plunge a 
well at the site using a rig or other method, to open a valve to direct 
flow to an atmospheric tank to clear the well, or to manually shut-in 
the well to allow pressure to build in the well-bore. Manual unloadings 
may be performed on a routine schedule or on ``as needed'' basis.
* * * * *
    Mud rate means the pumping rate of the mud by the mud pumps, 
usually measured in gallons per minute (gpm).
* * * * *
    Nitrogen removal unit (NRU) means a process unit that separates 
nitrogen from natural gas using various separation processes (e.g., 
cryogenic units, membrane units, etc.)
    Nitrogen removal unit vent emissions means the nitrogen gas 
separated from the natural gas and released with methane and other 
gases to the atmosphere, flare, or other combustion unit.
* * * * *
    Other large release event means any planned or unplanned 
uncontrolled release to the atmosphere of gas, liquids, or mixture 
thereof, from wells and/or other equipment that result in emissions for 
which there are no methodologies in Sec.  98.233 other than under Sec.  
98.233(y) to appropriately estimate these emissions. Other large 
release events include, but are not limited to, well blowouts, well 
releases, pressure relief valve releases from process equipment other 
than hydrocarbon liquids storage tanks, storage tank cleaning and other 
maintenance activities, and releases that occur as a result of an 
accident, equipment rupture, fire, or explosion. Other large release 
events also include failure of equipment or equipment components such 
that a single equipment leak or release has emissions that exceed the 
emissions calculated for that source using applicable methods in Sec.  
98.233(a) through (s), (w), (x), (dd), or (ee) by the threshold in 
Sec.  98.233(y)(1)(ii).
* * * * *
    Produced water means 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.
* * * * *
    Routed to combustion means, for onshore petroleum and natural gas 
production facilities, natural gas distribution facilities, and onshore 
petroleum and natural gas gathering and boosting facilities, that 
emissions are routed to stationary or portable fuel combustion 
equipment specified in Sec.  98.232(c)(22), (i)(7), or (j)(12), as 
applicable. For all other industry segments in this subpart, routed to 
combustion means that emissions are routed to a stationary fuel 
combustion unit subject to subpart C of this part (General Stationary 
Fuel Combustion Sources).
* * * * *
    Well blowout means a complete loss of well control for a long 
duration of time resulting in an emissions release.
* * * * *
    Well release means a short duration of uncontrolled emissions 
release from a well followed by a period of controlled emissions 
release in which control techniques were successfully implemented.
* * * * *
    17. Remove table W-1A, table W-1B, table W-1C, table W-1D, and 
table W-1E to subpart W of part 98 and add table W-1 to subpart W of 
part 98 in numerical order to read as follows:

[[Page 50438]]



Table W-1 to Subpart W of Part 98--Default Whole Gas Population Emission
                                 Factors
------------------------------------------------------------------------
                                                        Emission factor
       Industry segment         Source type/component   (scf whole gas/
                                                           hour/unit)
------------------------------------------------------------------------
Population Emission Factors--Pneumatic Device Vents and Pneumatic Pumps,
                              Gas Service 1
------------------------------------------------------------------------
 Onshore petroleum and  Continuous Low Bleed                 6.8
 natural gas production.         Pneumatic Device                     21
 Onshore petroleum and   Vents 2.
 natural gas gathering and      Continuous High Bleed
 boosting.                       Pneumatic Device
                                 Vents 2.
                                Pneumatic Pumps 3....               13.3
 Onshore natural gas    Continuous Low Bleed                 6.8
 processing.                     Pneumatic Device
                                 Vents 2.
 Onshore natural gas    Continuous High Bleed                 30
 transmission compression.       Pneumatic Device
                                 Vents 2.
 Underground natural
 gas storage.
 Natural gas
 distribution.
------------------------------------------------------------------------
       Population Emission Factors--Major Equipment, Gas Service 1
------------------------------------------------------------------------
 Onshore petroleum and  Wellhead.............               8.87
 natural gas production.        Separator............               9.65
 Onshore petroleum and  Meters/Piping........               7.04
 natural gas gathering and      Compressor...........               13.8
 boosting.
                                Dehydrator...........               8.09
                                Heater...............               5.22
                                Storage Vessel.......               1.83
------------------------------------------------------------------------
       Population Emission Factors--Major Equipment, Crude Service
------------------------------------------------------------------------
Onshore petroleum and natural   Wellhead.............               4.13
 gas production.                Separator............               4.77
                                Meters/Piping........               12.4
                                Compressor...........               13.8
                                Dehydrator...........               8.09
                                Heater...............                3.2
                                Storage Vessel.......               1.91
------------------------------------------------------------------------
  Population Emission Factors--Gathering Pipelines, by Material Type 4
------------------------------------------------------------------------
Onshore petroleum and natural   Protected Steel......               0.93
 gas gathering and boosting.    Unprotected Steel....                8.2
                                Plastic/Composite....               0.28
                                Cast Iron............                8.4
------------------------------------------------------------------------
\1\ For multi-phase flow that includes gas, use the gas service emission
  factors.
\2\ Emission factor is in units of ``scf whole gas/hour/device.''
\3\ Emission factor is in units of ``scf whole gas/hour/pump.''
\4\ Emission factors are in units of ``scf whole gas/hour/mile of
  pipeline.''

0
18. Revise table W-2 to subpart W of part 98 to read as follows:

                  Table W-2 to Subpart W of Part 98--Default Whole Gas Leaker Emission Factors
----------------------------------------------------------------------------------------------------------------
                                                     Emission factor (scf whole gas/hour/component)
                                      --------------------------------------------------------------------------
                                         If you survey using      If you survey using    If you survey using any
         Equipment components           Method 21 as specified   Method 21 as specified   of the methods in Sec.
                                               in Sec.                  in Sec.            98.234(a)(1), (3), or
                                           98.234(a)(2)(i)          98.234(a)(2)(ii)               (5)
----------------------------------------------------------------------------------------------------------------
   Leaker Emission Factors--Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas
                              Gathering and Boosting--All Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve................................                      9.6                      5.5                       16
Flange...............................                      6.9                      4.0                       11
Connector (other)....................                      4.9                      2.8                      7.9
Open-Ended Line 2....................                      6.3                      3.6                       10
Pressure Relief Valve................                      7.8                      4.5                       13
Pump Seal............................                       14                      8.3                       23
Other 3..............................                      9.1                      5.3                       15
----------------------------------------------------------------------------------------------------------------
       Leaker Emission Factors--Onshore Petroleum and Natural Gas Production--All Components, Oil Service
----------------------------------------------------------------------------------------------------------------
Valve................................                      5.6                      3.3                      9.2
Flange...............................                      2.7                      1.6                      4.4
Connector (other)....................                      5.6                      3.2                      9.1

[[Page 50439]]

 
Open-Ended Line......................                      1.6                     0.93                      2.6
Pump 4...............................                      3.7                      2.2                      6.0
Other 3..............................                      2.2                      1.0                      2.9
----------------------------------------------------------------------------------------------------------------
\1\ For multi-phase flow that includes gas, use the gas service emission factors.
\2\ The open-ended lines component type includes blowdown valve and isolation valve leaks emitted through the
  blowdown vent stack for centrifugal and reciprocating compressors.
\3\ ``Others'' category includes any equipment leak emission point not specifically listed in this table, as
  specified in Sec.   98.232(c)(21) and (j)(10).
\4\ The pumps component type in oil service includes agitator seals.

0
19. Remove table W-3A and table W-3B to subpart W of part 98 and add 
table W-3 to subpart W of part 98 in numerical order to read as 
follows:

            Table W-3 to Subpart W of Part 98--Default Total Hydrocarbon Population Emission Factors
----------------------------------------------------------------------------------------------------------------
                                                                                      Emission factor (scf total
               Industry segment                        Source type/component              hydrocarbon/ hour/
                                                                                              component)
----------------------------------------------------------------------------------------------------------------
                           Population Emission Factors--Storage Wellheads, Gas Service
----------------------------------------------------------------------------------------------------------------
Underground natural gas storage..............  Connector...........................                         0.01
                                               Valve...............................                          0.1
                                               Pressure Relief Valve...............                         0.17
                                               Open-Ended Line.....................                         0.03
----------------------------------------------------------------------------------------------------------------

0
20. Remove table W-4A and table W-4B to subpart W of part 98 and add 
table W-4 to subpart W of part 98 in numerical order to read as 
follows:

              Table W-4 to Subpart W of Part 98--Default Total Hydrocarbon Leaker Emission Factors
----------------------------------------------------------------------------------------------------------------
                                                 Emission factor (scf total hydrocarbon/hour/component)
                                      --------------------------------------------------------------------------
                                         If you survey using      If you survey using    If you survey using any
         Equipment components           Method 21 as specified   Method 21 as specified   of the methods in Sec.
                                               in Sec.                  in Sec.            98.234(a)(1), (3), or
                                           98.234(a)(2)(i)          98.234(a)(2)(ii)               (5)
----------------------------------------------------------------------------------------------------------------
     Leaker Emission Factors--Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression--
                                       Compressor Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\............................                    14.84                     9.51                     24.2
Connector............................                     5.59                     3.58                     9.13
Open-Ended Line......................                    17.27                    11.07                     28.2
Pressure Relief Valve................                    39.66                    25.42                     64.8
Meter................................                    19.33                    12.39                     31.6
Other \2\............................                      4.1                     2.63                     6.70
----------------------------------------------------------------------------------------------------------------
   Leaker Emission Factors--Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression--Non-
                                       Compressor Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\............................                     6.42                     4.12                     10.5
Connector............................                     5.71                     3.66                      9.3
Open-Ended Line......................                    11.27                     7.22                     18.4
Pressure Relief Valve................                     2.01                     1.29                     3.28
Meter................................                     2.93                     1.88                     4.79
Other \2\............................                      4.1                     2.63                     6.70
----------------------------------------------------------------------------------------------------------------
             Leaker Emission Factors--Underground Natural Gas Storage--Storage Station, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\............................                    14.84                     9.51                     24.2
Connector (other)....................                     5.59                     3.58                     9.13
Open-Ended Line......................                    17.27                    11.07                     28.2
Pressure Relief Valve................                    39.66                    25.42                     64.8
Meter and Instrument.................                    19.33                    12.39                     31.6
Other \2\............................                      4.1                     2.63                     6.70
----------------------------------------------------------------------------------------------------------------

[[Page 50440]]

 
            Leaker Emission Factors--Underground Natural Gas Storage--Storage Wellheads, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve\1\.............................                      4.5                      3.2                     7.35
Connector (other than flanges).......                      1.2                      0.7                     1.96
Flange...............................                      3.8                      2.0                     6.21
Open-Ended Line......................                      2.5                      1.7                     4.08
Pressure Relief Valve................                      4.1                      2.5                     6.70
Other \2\............................                      4.1                      2.5                     6.70
----------------------------------------------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Other includes any potential equipment leak emission point in gas service that is not specifically listed in
  this table, as specified in Sec.   98.232(e)(8) for onshore natural gas transmission compression, and as
  specified in Sec.   98.232(f)(6) and (8) for underground natural gas storage.

0
21. Remove table W-5A and table W-5B to subpart W of part 98 and add 
table W-5 to subpart W of part 98 in numerical order to read as 
follows:

 Table W-5 to Subpart W of Part 98--Default Methane Population Emission
                                 Factors
------------------------------------------------------------------------
                                                    Emission factor (scf
      Industry segment            Source type/          methane/hour/
                                    component            component)
------------------------------------------------------------------------
    Population Emission Factors--LNG Storage Compressor, Gas Service
------------------------------------------------------------------------
LNG storage.................  Vapor Recovery                        4.17
LNG import and export          Compressor \1\.
 equipment.
------------------------------------------------------------------------
   Population Emission Factors--Below Grade Transmission-Distribution
 Transfer Station Components and Below Grade Metering-Regulating Station
                      \2\ Components, Gas Service
------------------------------------------------------------------------
Natural gas distribution....  Below Grade T-D                       0.30
                               Transfer Station.
                              Below Grade M&R                       0.30
                               Station.
------------------------------------------------------------------------
      Population Emission Factors--Distribution Mains, Gas Service
------------------------------------------------------------------------
Natural gas distribution....  Unprotected Steel...                   5.1
                              Protected Steel.....                  0.57
                              Plastic.............                  0.17
                              Cast Iron...........                   6.9
------------------------------------------------------------------------
    Population Emission Factors--Distribution Services, Gas Service
------------------------------------------------------------------------
Natural gas distribution....  Unprotected Steel...                 0.086
                              Protected Steel.....                0.0077
                              Plastic.............                0.0016
                              Copper..............                  0.03
------------------------------------------------------------------------
   Population Emission Factors--Interconnect, Direct Sale, or Farm Tap
                            Station Stations
------------------------------------------------------------------------
Onshore natural gas           Transmission Company                   166
 transmission pipeline.        Interconnect M&R
                               Station.
                              Direct Sale or Farm                    1.3
                               Tap Station.
------------------------------------------------------------------------
    Population Emission Factors--Transmission Pipelines, Gas Service
------------------------------------------------------------------------
Onshore natural gas           Unprotected Steel...                  0.74
 transmission pipeline.
                              Protected Steel.....                 0.041
                              Plastic.............                 0.061
                              Cast Iron...........                    27
------------------------------------------------------------------------
\1\ Emission Factor is in units of ``scf methane/hour/compressor.''
\2\ Excluding customer meters.
\3\ Emission Factor is in units of ``scf methane/hour/station.''
\4\ Emission Factor is in units of ``scf methane/hour/mile.''
\5\ Emission Factor is in units of ``scf methane/hour/number of
  services.''


[[Page 50441]]

0
22. Remove table W-6A and table W-6B to subpart W of part 98 and add 
table W-6 to subpart W of part 98 in numerical order to read as 
follows:

                   Table W-6 to Subpart W of Part 98--Default Methane Leaker Emission Factors
----------------------------------------------------------------------------------------------------------------
                                                      Emission factor (scf methane/hour/component)
                                      --------------------------------------------------------------------------
                                         If you survey using      If you survey using    If you survey using any
         Equipment components           Method 21 as specified   Method 21 as specified   of the methods in Sec.
                                               in Sec.                  in Sec.            98.234(a)(1), (3), or
                                           98.234(a)(2)(i)          98.234(a)(2)(ii)               (5)
----------------------------------------------------------------------------------------------------------------
   Leaker Emission Factors--LNG Storage and LNG Import and Export Equipment--Storage Components and Terminals
                                             Components, LNG Service
----------------------------------------------------------------------------------------------------------------
Valve................................                     1.19                     0.23                     1.94
Pump Seal............................                     4.00                     0.73                     6.54
Connector............................                     0.34                     0.11                     0.56
Other \1\............................                     1.77                     0.99                      2.9
----------------------------------------------------------------------------------------------------------------
   Leaker Emission Factors--LNG Storage and LNG Import and Export Equipment--Storage Components and Terminals
                                             Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \2\............................                    14.84                     9.51                     24.2
Connector............................                     5.59                     3.58                     9.13
Open-Ended Line......................                    17.27                    11.07                     28.2
Pressure Relief Valve................                    39.66                    25.42                     64.8
Meter and Instrument.................                    19.33                    12.39                     31.6
Other \3\............................                      4.1                     2.63                     6.70
----------------------------------------------------------------------------------------------------------------
 Leaker Emission Factors--Natural Gas Distribution--Transmission-Distribution Transfer Station  Components, Gas
                                                     Service
----------------------------------------------------------------------------------------------------------------
Connector............................                     1.69  .......................                     2.76
Block Valve..........................                    0.557  .......................                     0.91
Control Valve........................                     9.34  .......................                     15.3
Pressure Relief Valve................                     0.27  .......................                     0.44
Orifice Meter........................                    0.212  .......................                     0.35
Regulator............................                    0.772  .......................                     1.26
Open-ended Line......................                   26.131  .......................                     42.7
----------------------------------------------------------------------------------------------------------------
\1\ ``Other'' equipment type for components in LNG service should be applied for any equipment type other than
  connectors, pumps, or valves.
\2\ Valves include control valves, block valves and regulator valves.
\3\ ``Other'' equipment type for components in gas service should be applied for any equipment type other than
  valves, connectors, flanges, open-ended lines, pressure relief valves, and meters and instruments, as
  specified in Sec.   98.232(g)(6) and (7) and Sec.   98.232(h)(7) and (8).
\4\ Excluding customer meters.

0
23. Revise table W-7 to subpart W of part 98 to read as follows:

 Table W-7 to Subpart W of Part 98--Default Methane Emission Factors for
                      Internal Combustion Equipment
------------------------------------------------------------------------
                                                        Emission factor
         Internal combustion equipment type             (kg CH4/mmBtu)
------------------------------------------------------------------------
Reciprocating Engine, 2-stroke lean-burn............               0.658
Reciprocating Engine, 4-stroke lean-burn............               0.522
Reciprocating Engine, 4-stroke rich-burn............               0.045
Gas Turbine.........................................               0.004
------------------------------------------------------------------------


[FR Doc. 2023-14338 Filed 7-31-23; 8:45 am]
 BILLING CODE 6560-50-P


