[Federal Register Volume 87, Number 118 (Tuesday, June 21, 2022)]
[Proposed Rules]
[Pages 36920-37119]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-09660]
[[Page 36919]]
Vol. 87
Tuesday,
No. 118
June 21, 2022
Part II
Environmental Protection Agency
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40 CFR Parts 9 and 98
Revisions and Confidentiality Determinations for Data Elements Under
the Greenhouse Gas Reporting Rule; Proposed Rule
Federal Register / Vol. 87 , No. 118 / Tuesday, June 21, 2022 /
Proposed Rules
[[Page 36920]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 9 and 98
[EPA-HQ-OAR-2019-0424; FRL-7230-02-OAR]
RIN 2060-AU35
Revisions and Confidentiality Determinations for Data Elements
Under the Greenhouse Gas Reporting Rule
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: The Environmental Protection Agency (EPA) is proposing to
amend specific provisions in the Greenhouse Gas Reporting Rule to
improve the quality and consistency of the data collected under the
rule, streamline and improve implementation, and clarify or propose
minor updates to certain provisions that have been the subject of
questions from reporting entities. These proposed changes include
revisions to improve the existing calculation, recordkeeping, and
reporting requirements by incorporating updates to existing emissions
estimation methodologies and providing for collection of additional
data to understand new source categories or new emission sources for
specific sectors. The proposed changes would improve understanding of
the sector-specific processes or other factors that influence
greenhouse gas emissions rates, improve verification of collected data,
and complement or inform other EPA programs. The EPA is also proposing
revisions that would improve implementation of the Greenhouse Gas
Reporting Rule such as updates to applicability estimation
methodologies, providing flexibility for or simplifying calculation and
monitoring methodologies, streamlining recordkeeping and reporting, and
other minor technical corrections or clarifications. 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. Further, this action includes a request
for comment to solicit information that may aid in potential future
revisions to the Greenhouse Gas Reporting Rule.
DATES:
Comments. Comments must be received on or before August 22, 2022.
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 22, 2022.
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 June 27, 2022, 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 your comments, identified by Docket Id.
No. EPA-HQ-OAR-2019-0424, by any of the following methods:
Federal eRulemaking Portal: https://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 https://www.regulations.gov/, including any personal
information provided. Out of an abundance of caution for members of the
public and our staff, the EPA Docket Center and Reading Room are closed
to the public, with limited exceptions, to reduce the risk of
transmitting Coronavirus 2019 (COVID-19). Our Docket Center staff will
continue to provide remote customer service via email, phone, and
webform. We encourage the public to submit comments via https://www.regulations.gov/ or email, as there may be a delay in processing
mail and faxes. Hand deliveries and couriers may be received by
scheduled appointment only. For further information on EPA Docket
Center services and the current status, please visit us online at
https://www.epa.gov/dockets.
Once submitted, comments cannot be edited or withdrawn. The EPA may
publish any comment received to its public docket. Do not submit
electronically any information you consider to be confidential business
information (CBI) 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). For additional submission
methods, the full EPA public comment policy, information about CBI or
multimedia submissions, and general guidance on making effective
comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.
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, https://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 https://www.epa.gov/ghgreporting.
SUPPLEMENTARY INFORMATION:
Participation in virtual public hearing. Please note that the EPA
is deviating from its typical approach for public hearings because the
President has declared a national emergency. Due to the current Centers
for Disease Control and Prevention (CDC) recommendations, as well as
state and local orders for social distancing to limit the spread of
COVID-19, the EPA cannot hold in-person public meetings at this time.
To request a hearing, please contact the person listed in the
following FOR FURTHER INFORMATION CONTACT section by June 27, 2022. If
requested, the virtual hearing will be held on July 6, 2022. The
hearing will convene at 9 a.m. Eastern Time (ET) and will conclude at 3
p.m. ET. The EPA may close the hearing 15 minutes after the last pre-
registered speaker has testified if there are no additional speakers.
The EPA will provide further information about the hearing on its
website (https://www.epa.gov/ghgreporting) if a hearing is requested.
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Upon publication of this document in the Federal Register (FR), the
EPA will begin pre-registering speakers for the hearing, if a hearing
is requested. To register to speak at the virtual hearing, please use
the online registration form available at https://www.epa.gov/ghgreporting. If you have questions regarding registration, consult the
person listed in the preceding FOR FURTHER INFORMATION CONTACT section.
The last day to pre-register to speak at the hearing will be July 5,
2022. Prior to the hearing, the EPA will post a general agenda that
will list pre-registered speakers in approximate order at: https://www.epa.gov/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 5 minutes to provide oral testimony. The
EPA encourages commenters to provide the EPA with a copy of their oral
testimony 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 https://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 a translator or a special
accommodation such as audio description, please pre-register for the
hearing with the public hearing team and describe your needs by June
28, 2022. The EPA may not be able to arrange accommodations without
advanced notice.
Regulated entities. 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 certain suppliers and direct emitters of 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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Category NAICS Examples of affected facilities
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General Stationary Fuel Combustion ................. Facilities operating boilers, process heaters,
Sources. incinerators, turbines, and internal combustion
engines.
211 Extractors of crude petroleum and natural gas.
321 Manufacturers of lumber and wood products.
322 Pulp and paper mills.
325 Chemical manufacturers.
324 Petroleum refineries, and manufacturers of coal
products.
316, 326, 339 Manufacturers of rubber and miscellaneous plastic
products.
331 Steel works, blast furnaces.
332 Electroplating, plating, polishing, anodizing, and
coloring.
336 Manufacturers of motor vehicle parts and
accessories.
221 Electric, gas, and sanitary services.
622 Health services.
611 Educational services.
Electric Power Generation............... 2211 Generation facilities that produce electric energy.
Ammonia Manufacturing................... 325311 Anhydrous and aqueous ammonia manufacturing
facilities.
Cement Production....................... 327310 Portland cement manufacturing plants.
Electronics Manufacturing............... 334111 Microcomputers manufacturing facilities.
334413 Semiconductor, photovoltaic (PV) (solid-state)
device manufacturing facilities.
334419 Liquid crystal display (LCD) unit screens
manufacturing facilities; Microelectromechanical
(MEMS) manufacturing facilities.
Ferroalloy Production................... 331110 Ferroalloys manufacturing facilities.
Fluorinated Greenhouse Gas Production... 325120 Industrial gases manufacturing facilities.
Glass Production........................ 327211 Flat glass manufacturing facilities.
327213 Glass container manufacturing facilities.
327212 Other pressed and blown glass and glassware
manufacturing facilities.
Hydrogen Production..................... 325120 Hydrogen manufacturing facilities.
Iron and Steel Production............... 333110 Integrated iron and steel mills, steel companies,
sinter plants, blast furnaces, basic oxygen
process furnace (BOPF) shops.
Lime Manufacturing...................... 327410 Calcium oxide, calcium hydroxide, dolomitic
hydrates manufacturing facilities.
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Miscellaneous Uses of Carbonate......... Facilities included elsewhere.
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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.
Petrochemical Production................ 325110 Ethylene dichloride manufacturing facilities.
325199 Acrylonitrile, ethylene oxide, methanol
manufacturing facilities.
325110 Ethylene manufacturing facilities.
325180 Other basic inorganic chemical manufacturing.
Petroleum Refineries.................... 324110 Petroleum refineries.
Silicon Carbide Production.............. 327910 Silicon carbide abrasives manufacturing facilities.
Electrical Equipment Use................ 221121 Electric bulk power transmission and control
facilities.
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Underground Coal Mines.................. 212113 Underground anthracite coal mining operations.
212112 Underground bituminous coal mining operations.
Zinc Production......................... 331419 Primary zinc refining facilities.
331492 Zinc dust recycling facilities, recovering from
scrap and/or alloying purchased metals.
311411 Frozen fruit, juice, and vegetable manufacturing
facilities.
311421 Fruit and vegetable canning facilities.
Municipal Solid Waste Landfills......... 562212 Solid waste landfills.
221320 Sewage treatment facilities.
Suppliers of Coal-based Liquid Fuels.... 211130 Coal liquefaction at mine sites.
Suppliers of Natural Gas and Natural Gas 221210 Natural gas distribution facilities.
Liquids.
211112 Natural gas liquid extraction facilities.
Suppliers of Petroleum Products......... 324110 Petroleum refineries.
Suppliers of Carbon Dioxide............. 325120 Industrial gas manufacturing facilities.
Suppliers of Industrial Greenhouse Gases 325120 Industrial greenhouse gas manufacturing facilities.
Electrical Equipment Manufacture or 33531 Power transmission and distribution switchgear and
Refurbishment. specialty transformers manufacturing facilities.
Carbon Dioxide Enhanced Oil Recovery 211 Oil and gas extraction projects using carbon
Projects. dioxide enhanced oil recovery.
Calcium Carbide Production.............. 325180 Other basic inorganic chemical manufacturing.
Coke Calcining.......................... 324199 All other petroleum and coal products
manufacturing.
Glyoxal, Glyoxylic Acid, and Caprolactam 325199 All other basic organic chemical manufacturing.
Production.
Ceramics Manufacturing.................. 327110 Pottery, ceramics, and plumbing fixture
manufacturing.
327120 Clay building material and refractories
manufacturing.
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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. 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 each source category. Many
facilities that are affected by 40 CFR part 98 have greenhouse gas
emissions from multiple source categories listed in Table 1 of this
preamble.
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
AGA American Gas Association
AIM American Innovation and Manufacturing Act of 2020
AMLD Advanced Mobile Leak Detection
ANOVA analysis of variance
ANSI American National Standards Institute
API American Petroleum Institute
ASTM American Society for Testing and Materials
BAMM best available monitoring methods
BEF by-product emission factor
BOEM Bureau of Ocean Energy Management
BOPF basic oxygen process furnace
C&D construction and demolition
CAA Clean Air Act
CARB California Air Resources Board
CBI confidential business information
CBP U.S. Customs and Border Protection
CCUS carbon capture, utilization, and sequestration
CDA clean dry air
CDC Centers for Disease Control and Prevention
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
CGA cylinder gas audit
CF4 perfluoromethane
CH4 methane
CKD cement kiln dust
CO2 carbon dioxide
CO2e carbon dioxide equivalent
CO carbon monoxide
COF2 carbonic difluoride
COVID-19 Coronavirus 2019
CSA CSA Group
CVD chemical vapor deposition
DAC direct air capture
DCU delayed coking unit
DOC degradable organic carbon
DOT Department of Transportation
DRE destruction or removal efficiency
e-GGRT electronic Greenhouse Gas Reporting Tool
EAF electric arc furnace
EDC ethylene dichloride
EF emission factor
EG emission guidelines
EIA Energy Information Administration
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
EREF Environmental Research and Education Foundation
ET Eastern time
FAQ frequently asked question
FR Federal Register
F-GHG fluorinated greenhouse gas
F-HTFs fluorinated heat transfer fluids
FTIR Fourier Transform Infrared
GCS gas collection system
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GIE gas-insulated equipment
GIS geographic information systems
GOR gas-to-oil ratio
GRI Gas Research Institute
GWP global warming potential
HCFC hydrochlorofluorocarbons
HFC hydrofluorocarbons
HHV high heating value
HTS Harmonized Tariff System
HVAE high voltage anode effect
IAI International Aluminium Institute
ICR Information Collection Request
IPCC Intergovernmental Panel on Climate Change
IRC Internal Revenue Code
IRS Internal Revenue Service
ISBN International Standard Book Number
ISO International Standards Organization
IVT Inputs Verification Tool
k first order decay rate
kg kilograms
LCA life cycle analysis
LCD liquid crystal display
LDC local distribution company
LNG liquified natural gas
LVAE low voltage anode effect
MCF moisture correction factor
MDEA methyl diethanolamine
MEA monoethanolamine
MEMS microelectromechanical systems
mmBtu/hr million British thermal units per hour
MMscf million standard cubic feet
MRV monitoring, reporting, and verification plan
MSHA Mine Safety and Health Administration
MSW municipal solid waste
mtCO2e metric tons carbon dioxide equivalent
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N2O nitrous oxide
NAICS North American Industry Classification System
NGLs natural gas liquids
NSPS New Source Performance Standards
OAR Office of Air and Radiation
OEM original equipment manufacturer
OGI optical gas imaging
OMB Office of Management and Budget
OMP operations management plan
PCA Portland Cement Association
PFC perfluorocarbon
PRA Paperwork Reduction Act
ppmv parts per million by volume
PV photovoltaic
QA/QC quality assurance/quality control
QMS Quadrupole Mass Spectroscopy
RFA Regulatory Flexibility Act
RMA Rubber Manufacturers Association
RPC remote plasma cleaning
RY reporting year
scfh standard cubic feet per hour
SF6 sulfur hexafluoride
SIA Semiconductor Industry Association
SIC Standard Industrial Classification System
SSM startup, shutdown, and malfunction
TBD to be determined
TFI The Fertilizer Institute
TSCA Toxic Substances Control Act
TSD technical support document
UIC underground injection control
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
USGS U.S. Geological Survey
USTMA U.S. Tire Manufacturers Association
VCM vinyl chloride monomer
VOC volatile organic compound
WMO World Meteorological Organization
WWW World Wide Web
Table of Contents
I. Background
A. How is this preamble organized?
B. Executive Summary
C. Background on This Proposed Rule
D. Legal Authority
II. Overview and Rationale for Proposed Amendments to 40 CFR Part 98
and 40 CFR Part 9
A. Revisions To Improve the Quality of Data Collected Under 40
CFR Part 98 and Other Minor Revisions or Clarifications
B. Revisions To Streamline and Improve Implementation of 40 CFR
Part 98
C. Revisions to 40 CFR Part 9
III. Proposed Amendments to 40 CFR Part 98
A. Subpart A--General Provisions
B. Subpart C--General Stationary Fuel Combustion Sources
C. Subpart G--Ammonia Manufacturing
D. Subpart H--Cement Production
E. Subpart I--Electronics Manufacturing
F. Subpart N--Glass Production
G. Subpart P--Hydrogen Production
H. Subpart Q--Iron and Steel Production
I. Subpart S--Lime Manufacturing
J. Subpart W--Petroleum and Natural Gas Systems
K. Subpart X--Petrochemical Production
L. Subpart Y--Petroleum Refineries
M. Subpart BB--Silicon Carbide Production
N. Subpart DD--Electrical Transmission and Distribution
Equipment Use
O. Subpart FF--Underground Coal Mines
P. Subpart GG--Zinc Production
Q. Subpart HH--Municipal Solid Waste Landfills
R. Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids
S. Subpart OO--Suppliers of Industrial Greenhouse Gases
T. Subpart PP--Suppliers of Carbon Dioxide
U. Subpart SS--Electrical Equipment Manufacturers or
Refurbishment
V. Subpart UU--Injection of Carbon Dioxide
W. Subpart VV--Geologic Sequestration of Carbon Dioxide With
Enhanced Oil Recovery Using ISO 27916
IV. Additional Requests for Comment
A. Energy Consumption
B. Ceramics Production
C. Calcium Carbide Production
D. Glyoxal, Glyoxylic Acid, and Caprolactam Production
E. Coke Calcining
F. CO2 Utilization
G. Aluminum Production
V. Schedule for the Proposed Amendments
VI. Proposed Confidentiality Determinations for Certain Data
Reporting Elements
A. Overview and Background
B. Proposed Confidentiality Determinations and Emissions Data
Designations
C. Proposed Reporting Determinations for Inputs to Emissions
Equations
D. Proposed Revisions to Confidentiality Determinations for
Existing 40 CFR part 98 Data Elements Affected by the AIM
Implementation Rule
E. Request for Comments on Proposed Category Assignments,
Confidentiality Determinations, or Determinations of Inputs To Be
Reported
VII. Impacts of the Proposed Amendments
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
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 origin of 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 (hereinafter referred to as
``part 98''), and 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 is organized by part 98 subpart and
contains detailed information on the proposed revisions to part 98 and
the rationale for the proposed amendments in each section. Section IV
of this preamble discusses additional requests for comments related to
potentially expanding or adding new source categories and other
potential future amendments to the GHG Reporting Rule. Section V of
this preamble discusses when the proposed revisions to part 98 would
apply to reporters. Section VI of this preamble discusses the proposed
confidentiality determinations for new or substantially revised (i.e.,
requiring additional or different data to be reported) data reporting
elements, as well as for certain existing data elements for which a
determination has not been previously established. Section VII of this
preamble discusses the impacts of the proposed amendments. Section VIII
of this preamble describes the statutory and executive order
requirements applicable to this action.
B. Executive Summary
The EPA is proposing amendments to part 98 to implement
improvements to the GHGRP. After more than 10 years of implementation
of the program, the EPA has assessed the data collected, emissions, and
trends established from annual reports in each industrial sector
required to report. In this review, the EPA has evaluated the
requirements of the GHGRP to identify areas of improvement, such as
where the rule may be modified to reflect the EPA's current
understanding of United States (U.S.) GHG emission trends, or to
improve data collection and reporting where additional data may be
necessary to better understand emissions from specific sectors or
inform future policy decisions. The EPA has subsequently identified
improvements to the calculation, monitoring, and reporting
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requirements that would incorporate new data or updated scientific
knowledge; reflect new emissions sources; improve analysis and
verification of collected data; provide additional data to complement
or inform other EPA programs; or streamline calculation, monitoring, or
reporting to provide flexibility or increase the efficiency of data
collection.
The proposed amendments include improvements to requirements that
would enhance the quality of the data collected, clarify elements of
the rule, and streamlining changes. The types of proposed amendments
that would improve the quality of the data collected under the rule
include revisions to update emission factors to more accurately reflect
industry emissions; refinements to existing emissions calculation
methodologies to reflect an improved understanding of emissions sources
and end uses of GHGs; providing for collection of additional data to
understand new source categories or new emission sources for specific
sectors; additions or modifications to reporting requirements in order
to eliminate data gaps and improve verification of emissions estimates;
revisions that address prior commenter concerns or clarify
requirements, and editorial corrections that would improve the public's
understanding of the rule.
The types of streamlining changes that the EPA is proposing include
revisions to applicability for certain industry sectors to account for
changes in usage of certain GHGs or where the current applicability
estimation methodology may overestimate emissions; revisions that
provide flexibility for or simplify monitoring and calculation methods;
and revisions to streamline reported data elements or recordkeeping
where the current requirements are redundant, where reported data are
not currently useful for verification or analysis, or for which
continued collection of the data at the same frequency would not likely
provide new insights or knowledge of the industry sector, emissions, or
trends at this time.
This action also includes a request for comment related to
potentially expanding existing categories or including additional new
source categories to the Greenhouse Gas Reporting Rule. In these cases,
the EPA is seeking additional information to better inform our
consideration of proposing these new source categories to the GHGRP.
Therefore, the EPA is specifically requesting comment related to the
potential expanded or new source categories described in this section.
The EPA is also requesting comment on potential future amendments to
add new calculation, monitoring, and reporting requirements for the
aluminum production source category. If the Agency becomes comfortable
that the information available is sufficient to support a rule
revision, the EPA may consider undertaking a future action to revise or
add source categories or to incorporate updated calculation and
reporting requirements.
Further, this action includes a proposal to update 40 CFR part 9 in
accordance with the publication requirements of the PRA to include the
OMB control number issued under the PRA for the information collection
request (ICR) for the GHGRP.
Finally, this action proposes to establish and/or revise
confidentiality determinations for the reporting of certain data
elements added or revised in these proposed amendments, and for certain
existing data elements for which no confidentiality determination has
been previously proposed, or for which we are proposing to amend a
previously established confidentiality determination.
Most of the changes that are proposed are not anticipated to
significantly increase the recordkeeping and reporting burden
associated with the GHGRP. The proposed changes are anticipated to
improve the quality of the data reported under the program. Some of the
proposed revisions could potentially increase burden in cases where the
proposed amendments add or revise reporting requirements. The estimated
incremental costs include an average burden of $1,424,775 per year
beginning in reporting year (RY) 2023.
The EPA anticipates that the proposed changes may take effect on
January 1, 2023 and would apply beginning with reports submitted for
RY2023, which are required to be submitted to the EPA by April 1, 2024.
C. Background on This Proposed Rule
The GHG 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\ The EPA
issued additional rules in 2010 finalizing the requirements for subpart
T (Magnesium Production), subpart FF (Underground Coal Mines), subpart
II (Industrial Wastewater Treatment), and subpart TT (Industrial Waste
Landfills) (75 FR 39736, July 12, 2010); subpart W (Petroleum and
Natural Gas Systems) (75 FR 74458, November 30, 2010); subpart I
(Electronics Manufacturing), subpart L (Fluorinated Gas Production),
subpart DD (Electrical Transmission and Distribution Equipment Use),
subpart QQ (Importers and Exporters of Fluorinated GHGs Contained in
Pre- Charged Equipment or Closed-Cell Foams), and subpart SS
(Electrical Equipment Manufacture or Refurbishment) (75 FR 74774,
December 1, 2010); and subpart RR (Geologic Sequestration of Carbon
Dioxide) and subpart UU (Injection of Carbon Dioxide) (75 FR 75060,
December 1, 2010). Following the promulgation of these subparts, the
EPA finalized several technical and clarifying amendments to these and
other subparts under the GHGRP (75 FR 79092, December 17, 2010; 76 FR
22825, April 25, 2011; 76 FR 36339, June 22, 2011; 76 FR 59533,
September 27, 2011; 76 FR 59542, September 27, 2011; 76 FR 73866,
November 29, 2011; 76 FR 80554, December 23, 2011; 77 FR 10373,
February 22, 2012; 77 FR 48072, August 13, 2012; 77 FR 51477, August
24, 2012; 78 FR 25392, May 1, 2013; 78 FR 68162, November 13, 2013; 78
FR 71904, November 29, 2013; 79 FR 63750, October 24, 2014; 79 FR
70352, November 25, 2014; 79 FR 73750, December 11, 2014; 80 FR 64262,
October 22, 2015; and 81 FR 86490, November 30, 2016). The amendments
generally added or revised requirements in the existing subparts of
part 98, including revisions that were intended to improve clarity and
consistency across the calculation, monitoring, and data reporting
requirements. The EPA finalized additional amendments (81 FR 89188,
December 6, 2016) to streamline implementation of the rule, to improve
the quality and consistency of the data collected under the rule, and
to clarify or provide updates to certain provisions that have been the
subject of questions from reporting entities. The EPA is proposing
additional amendments and requesting comment in a continuation of the
effort to improve the GHGRP.
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\1\ Consolidated Appropriations Act, 2008, Public Law 110-161,
121 Stat. 1844, 2128. See https://www.congress.gov/110/plaws/publ161/PLAW-110publ161.pdf (accessed September 7, 2021).
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D. Legal Authority
The EPA is proposing these rule amendments under its existing CAA
authority provided in CAA section 114. As stated in the preamble to the
2009 Final Rule (74 FR 56260), CAA section 114(a)(1) provides the EPA
broad authority to require the information
[[Page 36925]]
proposed to be gathered by this rule because such data would inform and
are relevant to the EPA's carrying out of a wide variety of CAA
provisions. See the preambles to the proposed GHG Reporting Rule (74 FR
16606, October 10, 2009) and the 2009 Final Rule for further
information.
II. Overview and Rationale for Proposed Amendments to 40 CFR Part 98
and 40 CFR Part 9
Since 2010, the GHGRP has been a reliable and high-quality source
of GHG data. The data collected under 40 CFR part 98 is used to inform
the EPA's understanding of the relative emissions and distribution of
emissions from specific industries, the factors that influence GHG
emission rates, and to inform policy options and potential regulations.
The data published under the GHGRP also serves to enable key
stakeholders to understand, track, and compare greenhouse gas emissions
and identify and take action on emission reduction opportunities.
Further, the data collected under the GHGRP has also been used to
inform other regulations, for example, proposed New Source Performance
Standards (NSPS) and Emission Guidelines for the oil and gas industry
and for municipal solid waste (MSW) landfills under 40 CFR part 60.
Throughout the life of the GHGRP, the EPA has made several
improvements to the rule to address data gaps, reflect updates to
scientific information, or to incorporate improvements to calculation,
monitoring, or measurement methodologies. For example, in 2013, the EPA
finalized technical amendments including changes to applicability,
improvements to calculation methods, and updated reporting
requirements, as well as amendments to incorporate new data from the
Intergovernmental Panel on Climate Change (IPCC) on estimated global
warming potentials (GWPs) (78 FR 71904, November 29, 2013). More
recently, the EPA finalized edits to the petroleum and natural gas
systems source category to address potential gaps in coverage, improve
methods, and ensure high quality data reporting (81 FR 86490, November
30, 2016). The EPA last updated the GHGRP in 2016, when it implemented
revisions to streamline and improve implementation of the rule and to
improve the quality of the data collected, including expanding
monitoring and reporting requirements that were necessary to improve
verification and served to improve the accuracy of the data used to
inform the Inventory of U.S. Greenhouse Gas Emissions and Sinks
(hereafter referred to as the ``U.S. GHG Inventory'') (81 FR 89188,
December 9, 2016).
The EPA has also continuously conducted outreach to stakeholders
through various means, including responding to questions from
reporters, engaging through compliance assistance webinars, soliciting
feedback via a public testing process, interacting with reporters
during the verification of submitted data, and soliciting comments
during rulemakings. Thus, the EPA has subsequently identified,
proposed, and finalized several technical and clarifying amendments to
various subparts under the GHGRP to enhance the quality of the data
reported, improve our understanding of GHG emission sources and trends,
and improve implementation, particularly where we have identified
changes to industry processes, emissions trends, types of emissions
sources, or new data or scientific knowledge that would allow us to
better understand the quantity and distribution of U.S. GHG emissions.
The EPA recently evaluated the requirements of the GHGRP to
identify areas of improvement, such as where the rule may be modified
to reflect the EPA's current understanding of U.S. GHG emission trends,
or to improve data collection and reporting where additional data may
be necessary to better understand emissions from specific sectors or
inform future policy decisions. The proposed amendments include
improvements to the calculation, monitoring, and reporting requirements
that would incorporate updates to existing emissions estimation
methodologies; implement requirements to collect additional data to
understand new source categories or new emission sources for specific
sectors; improve the EPA's understanding of the sector-specific
processes or other factors that influence GHG emission rates and
improve verification of collected data; and provide additional data to
complement or inform other EPA programs. We are also proposing
revisions that clarify or update provisions that have been unclear. The
proposed amendments include:
Amendments to update emission factors to incorporate new
measurement data that more accurately reflects industry emissions;
Revisions to refine existing emissions calculation
methodologies to reflect an improved understanding of emissions sources
and end uses of GHGs, or to incorporate more recent research on GHG
emissions or formation;
Revisions to specific sectors to expand reporting to
include new source categories or new emission sources, in order to
improve the accuracy and completeness of the data provided by the
GHGRP;
Adding or modifying reporting requirements to eliminate
data gaps and improve verification of emissions estimates; and
Revisions that address prior commenter concerns or provide
additional information for reporters to better or more fully understand
their compliance obligations, that clarify requirements that reporters
have previously found vague to ensure that accurate data are being
collected, and editorial corrections or harmonizing changes that would
improve the public's understanding of the rule.
The EPA is also soliciting additional comment on potentially
expanding existing subparts or adding other new subparts to collect
data for several new source categories, as well as requesting comment
on potential future amendments to add new calculation, monitoring, and
reporting requirements for the aluminum production source category, as
discussed in section IV of this preamble.
The EPA has also identified additional areas in the GHGRP where
revisions to part 98 could be streamlined. Through this document, the
EPA is proposing several amendments to revise specific provisions in
part 98 that would streamline calculation, monitoring, or reporting to
provide flexibility or increase the efficiency of data collection. The
types of revisions we are proposing would simplify requirements while
maintaining the quality of the data collected under part 98, where
continued collection of information assists in evaluation and support
of EPA programs and policies. The proposed revisions include:
Revisions to applicability for certain industry sectors
without the 25,000 metric tons carbon dioxide equivalent
(mtCO2e) per year reporting threshold to account for changes
in usage of certain GHGs, or where the current applicability estimation
methodology may overestimate emissions;
Providing flexibility for and simplifying monitoring and
calculation methods where further monitoring and data collection would
not likely significantly improve our understanding of emission sources
at this time, or where we currently allow similar less burdensome
methodologies for other sources; and
Revisions to streamline reported data elements or
recordkeeping where the current requirements are redundant
[[Page 36926]]
or where reported data are not currently useful for verification or
analysis, or for which continued collection of the data at the same
frequency would not likely provide new insights or knowledge of the
industry sector, emissions, or trends at this time.
Sections II.A and II.B of this preamble describe the above changes
in more detail and provide 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 to be outside of the scope of this proposed rulemaking.
Finally, we are also proposing a technical amendment to 40 CFR part
9 to update the table that lists the OMB control numbers issued under
the PRA to include the ICR for 40 CFR part 98. This amendment is
described in section II.C of this preamble.
A. Revisions To Improve the Quality of Data Collected Under 40 CFR Part
98 and Other Minor Revisions or Clarifications
The data collected under part 98 are used to inform the EPA's
understanding of the relative emissions and distribution of emissions
from specific industries, the factors that influence GHG emission
rates, and to inform policy options and potential regulations.
Following several years of implementation and outreach, the EPA has
identified certain areas of the rule where updates to emissions factors
or other default factors; improvements to calculation methodologies;
collection of additional data on GHG emissions, emissions sources, or
end uses; additions or revisions to data elements or other reporting
requirements; and other technical amendments, clarifications, and
corrections would enhance the quality and accuracy of the data
collected under the GHGRP. These proposed changes include consideration
of comments raised by stakeholders in prior rulemakings that would more
closely align rule requirements with the processes conducted at
specific facilities, consideration of data gaps identified in collected
data where additional data would improve verification of data reported
to the GHGRP, and consideration of additional data needed to help
better understand changing industry emission trends. Overall, these
proposed changes would provide a more comprehensive, nationwide GHG
emissions profile reflective of the origin and distribution of GHG
emissions in the United States and would more accurately inform EPA
policy options for potential regulatory or non-regulatory CAA programs.
The EPA additionally uses the data from the GHGRP, which would include
data from these proposed changes, to improve estimates used in the U.S.
GHG Inventory.
In some cases, we are proposing to redefine certain industry
sectors to include additional GHGs not previously reported, or to add
emissions estimations methodologies and include reporting of GHGs from
newly identified sources of emissions in certain industry sectors, to
better account for changes in industry emission trends. The proposed
amendments reflect adjustments to the rule where we have identified
changes in the type and scope of GHGs emitted or supplied, such as
certain sectors that have implemented alternative equipment technology,
switched to use of GHGs with a lower GWP, or that have implemented new
end uses for GHGs that are emitted or supplied. In other cases, we have
identified gaps in the current coverage of the GHGRP that leave out
potentially significant emission sources, for example, large, atypical
release events at oil and gas facilities such as wellhead leaks. The
proposed amendments would also add a new source category that would
provide additional data on amounts of CO2 that are
geologically sequestered in association with enhanced oil recovery
(EOR) operations. Many of the revisions proposed in this action would
better capture the changing landscape of greenhouse gas emissions and
provide for more complete coverage of U.S. GHG emission sources. Such
changes are necessary for the EPA to continue to analyze the relative
emissions and distribution of emissions from specific industries and to
improve the overall quality of the data collected under the GHGRP.
These changes would also complement other EPA regulations, such as NSPS
and emission guidelines (EG) for the oil and gas industry and would
also be used to inform and improve future policy decisions.
The specific changes that we are proposing, as described in this
section, are described in detail for each subpart in sections III.A
through III.W of this preamble.
1. Updates to Emission Factors To Improve Accuracy of Reported Data
In order to improve the accuracy of the data collected under the
GHGRP, we are proposing to revise emission factors where we have
received improved measurement data or feedback from stakeholders. Some
of the calculation methodologies provided in the GHGRP rely on the use
of emission factors, and the use of emissions or default factors
decreases the need for additional monitoring or measurements from
individual facilities. The proposed rule includes revisions to emission
factors in a number of source categories, where we have received or
identified updated measurement data. For example, we are proposing
several updates to the emission factors and default destruction and
removal efficiency values in subpart I (Electronics Manufacturing). The
proposed emission factors are based on review of newly submitted data
from the 2017 and 2020 technology assessment reports submitted with
RY2016 and RY2019 annual reports, as well as consideration of new
emission factors available in the 2019 Refinement to the 2006 IPCC
Guidelines for National Greenhouse Gas Inventories (hereafter ``2019
Refinement'').\2\ We are also proposing updates to the emission factor
calculation methods that are used to calculate utilization and by-
product emission rates submitted in the technology assessment report
under subpart I, in order to ensure that emission factors are developed
in a consistent manner across facilities and over time and to allow the
EPA to compare emission factors across the industry and track trends in
industry emission rates.
---------------------------------------------------------------------------
\2\ Intergovernmental Panel on Climate Change (IPCC). 2019
Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas
Inventories, Calvo Buendia, E., Tanabe, K., Kranjc, A., Baasansuren,
J., Fukuda, M., Ngarize, S., Osako, A., Pyrozhenko, Y., Shermanau,
P. and Federici, S. (eds). Published: IPCC, Switzerland. 2019.
https://www.ipcc-nggip.iges.or.jp/public/2019rf/index.html.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424.
---------------------------------------------------------------------------
In some cases, the proposed emission factors would improve reported
data by better reflecting recent industry trends. For example, based on
input from stakeholders, we are proposing updated emission factors for
the modeling of methane (CH4) generation from waste disposed
at landfills in subpart HH (Municipal Waste Landfills). The updated
emission factors reflect an industry trend of increased disposal of
inert materials that do not contribute to CH4 generation.
The EPA received data from stakeholders in the waste industry following
comments received during the expert and public review period for the
U.S. GHG Inventory, which uses directly reported emissions values from
subpart HH to estimate national CH4 emissions from MSW
landfills
[[Page 36927]]
throughout the entire United States. The proposed change will update
default factors and will result in more accurate estimates of landfill
emissions and pose no additional reporting burden.
We are also proposing to update the default biogenic fraction for
tire combustion in subpart C (General Stationary Fuel Combustion) and
the emission factors for 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 (Petroleum and Natural Gas Systems). The proposed emission factors
are more representative of GHG emissions sources and would improve the
overall accuracy of the data collected under the GHGRP and would
ultimately benefit stakeholders who rely on GHGRP data to understand
the sources and magnitude of GHGs from specific facilities, as well as
improve the quality of data used to inform future policy or regulation.
2. Improvements To Existing Emissions Estimation Methodologies
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 will improve the quality and
accuracy of the data collected under the GHGRP, increase our
understanding of the relative distribution of GHGs that are emitted,
and better reflect GHG end uses or where GHGs are bound in products.
For example, for subpart I, we are proposing several edits to the
stack testing methodology, including adding new equations and a table
of default weighting factors to calculate the fraction of fluorinated
input gases and by-products exhausted from tools with abatement
systems; revising equations that calculate the weighted average DREs
for individual fluorinated greenhouse gases (F-GHGs) across process
types; requiring that all stacks be tested if the stack test method is
used; and updating a set of equations that will more accurately account
for emissions when pre-control emissions of a F-GHG approach or exceed
the consumption of that gas during the test period.
For other subparts, including subparts G (Ammonia Manufacturing), P
(Hydrogen Production), and S (Lime Manufacturing), we are proposing
revisions to the calculation methodology to allow for subtraction of
carbon dioxide (CO2) that is captured and bound in other
products (e.g., urea or methanol) from calculated and reported
emissions. The proposed changes, by removing the CO2 that is
not directly emitted from these facilities from the calculation
methodology, would provide a more accurate estimate of the direct
sector emissions and would provide consistency in our approach across
the GHGRP.
For subpart Y (Petroleum Refineries), we are proposing to amend the
calculation methodology for delayed coking units (DCUs), which uses a
steam generation model to estimate emissions. The proposed changes are
targeted to address issues identified during verification of reported
data, where we have noticed that the activities conducted at certain
facilities do not comport with some of the underlying assumptions of
the steam generation model. The proposed changes will modify the
current equation to more accurately estimate emissions and to be more
universally applicable to these facilities.
Additional details of these types of proposed changes are discussed
in section III of this preamble.
3. 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 for specific sectors to
address potential gaps in reporting. We are also proposing to improve
the existing rule requirements by proposing new or revised calculation,
monitoring, or reporting requirements that would help us to better
understand and track emissions in specific sectors; establish
requirements for a new source category for quantifying geologic
sequestration of CO2 in association with EOR operations; and
identify end uses of GHGs that are not currently accounted for in
existing reporting, for consideration in future policy development.
Such data would continue to inform, and are relevant to, the EPA's
carrying out a wide variety of CAA provisions. For example, identifying
new emissions or new emission sources from direct emitters could inform
decisions about whether and how to use section 111 of the CAA to
establish NSPS for various source categories emitting GHGs. The data
may also inform the EPA's implementation of section 103(g) of the CAA
regarding improvements in nonregulatory strategies and technologies for
preventing or reducing air pollutants. The data published under the
GHGRP serves to enable the Agency and stakeholders to understand,
track, and compare greenhouse gas emissions and identify emission
reduction opportunities. Over the last 10 years, the collection of
these data has allowed the Agency and relevant stakeholders to identify
changes in industry and emissions trends, such as transitions in
equipment technology or use of alternative lower-GWP greenhouses gases,
that may be beneficial for informing other EPA programs under the CAA.
The amendments we are proposing are intended to address data gaps that
have been identified in the implementation of the program or from
review of improved scientific assessments and would allow the EPA to
better characterize U.S. GHG emissions. The improved data would
subsequently better inform other agency policies and programs under the
CAA.
For example, we are proposing several revisions to subparts DD
(Electrical Transmission and Distribution Equipment Use) and SS
(Electrical Equipment Manufacture or Refurbishment) to improve the
quality of the data collected from these industrial sectors. Currently,
these subparts include ``all electric transmission and distribution
equipment and servicing inventory'' used within an electric power
system, and related manufacturing and refurbishing processes, that use
or include sulfur hexafluoride (SF6) and perfluorocarbons
(PFCs). When the final rule establishing subpart DD was published in
2010 (75 FR 74774, December 1, 2010, hereinafter referred to as the
2010 Final Rule for Additional Sources of Fluorinated GHGs),
SF6 was the most commonly used insulating gas in the
electrical power industry, and PFCs were occasionally used as
dielectrics and heat transfer fluids in power transformers. During the
implementation of the reporting program, electrical power systems
equipment manufacturers and fluorinated greenhouse gas suppliers
[[Page 36928]]
have introduced alternative technologies and replacements for
SF6 with lower GWPs, including fluorinated gas mixtures. We
are proposing to revise the existing calculation, monitoring, and
reporting requirements of these subparts to require reporting of
additional F-GHGs, in order to better track emissions from equipment
using alternative gases that are not currently accounted for.
Additionally, we have become aware of potentially significant
sources of emissions in specific industry sectors for which there are
no current emission estimation methods within part 98. For example,
under subpart I, we are proposing a calculation methodology to estimate
emissions of perfluoromethane (CF4) from hydrocarbon-based
emissions control systems. The proposed changes reflect recent studies
that have shown that direct reaction between molecular fluorine
(F2) and hydrocarbons to form CF4 can occur in
hydrocarbon-fueled combustion emissions control systems, and we are
proposing to incorporate calculations from the 2019 Refinement to
account for the formation and emission of CF4 from this
potentially significant emissions source.
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, 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 require
reporting of existing emission sources by additional industry segments.
For example, we are proposing to require liquified natural gas (LNG)
import/export facilities to begin calculating and reporting emissions
from acid gas removal vents.
In other cases, we are proposing changes to improve our
understanding of end-uses of GHGs and to better understand GHG supply.
For subpart OO (Suppliers of Industrial Greenhouse Gases), we are
proposing to require suppliers of nitrous oxide (N2O),
saturated PFCs, and SF6 to identify the end uses for which
the N2O, SF6, or PFC is used, and the quantities
of N2O, SF6, or each PFC transferred to each end
use, if known. This requirement would help to inform the development of
GHG policies and programs by providing information on N2O,
SF6, and PFC uses and their relative importance, where the
GWP-weighted quantities of these compounds that are supplied annually
to the U.S. economy are relatively large, and where the identities and
magnitudes of the uses of these compounds are less well understood.
The EPA is also proposing revisions to incorporate a new source
category to add calculation and reporting requirements for quantifying
geologic sequestration of CO2 in association with EOR
operations. The proposed requirements would be included under a new
subpart VV and would apply to reporters that choose to use the
International Standards Organization (ISO) standard designated as CSA
Group (CSA)/American National Standards Institute (ANSI) ISO
27916:2019, Carbon Dioxide Capture, Transportation and Geological
Storage--Carbon Dioxide Storage 3 Using Enhanced Oil
Recovery (CO2-EOR) (hereafter referred to as ``CSA/ANSI ISO
27916:2019'') as a means of quantifying geologic sequestration. Under
existing GHGRP requirements, facilities that sequester CO2
through EOR operations may opt into subpart RR. Proposed new subpart VV
provides an alternative method of reporting geologic sequestration in
association with CO2-EOR presenting another option for
reporters who are sequestering CO2 through their EOR
operations but do not choose to report under subpart RR. We are
proposing to add this new source category because collecting additional
information from these sources would improve our knowledge on the
amounts of CO2 that are geologically sequestered in
association with EOR operations and allow the Agency to more
comprehensively track and document the flow of CO2 through
the economy to better inform EPA policy and programs under the CAA
related to the use of CO2 capture and geologic
sequestration. Thus, the rationale for proposing subpart VV is
analogous to the rationale for originally proposing and finalizing
subpart RR, that is to enable the EPA to monitor the growth and
efficacy of geologic sequestration as a greenhouse gas mitigation
technology over time, to evaluate relevant policy options, and to
reconcile information obtained with data obtained from 40 CFR part 98,
subpart PP on CO2 supplied to the economy. The proposed
requirements are discussed in section III.W of this preamble.
---------------------------------------------------------------------------
\3\ The terms ``geologic sequestration'' and ``geologic
storage'' are used synonymously for purposes of this subpart.
---------------------------------------------------------------------------
The proposed changes would improve the overall quality and
completeness of the data collected by the GHGRP, and would be useful
for informing future policy decisions, such as opportunities to reduce
emissions. The EPA is also soliciting additional comment on potential
collection of data under other new source categories, as discussed in
section IV of this preamble.
4. Revisions to Reporting Requirements To Improve Verification and the
Accuracy of the Data Collected
The EPA is proposing several revisions to existing reporting
requirements to improve the quality of the data that are currently
reported, or to collect more useful data that would improve
verification of reported data. Such revisions would better characterize
U.S. GHG emissions and trends and would better enable the EPA to obtain
data that is of sufficient quality that it can be used to support a
range of future climate change policies and regulations, including but
not limited to information relevant to carrying out provisions
involving research, evaluating and setting standards, endangerment
determinations, or informing EPA non-regulatory programs.
For example, we are proposing revisions to the reporting of unit
level information under subpart C. Currently, individual unit
information (i.e., the unit type and the maximum rated heat input
capacity) is only required to be reported for specific individual unit
reporting configurations. The individual unit information allows the
EPA to aggregate emissions according to unit type and size and provides
a better understanding of the emissions from specific unit types. To
improve verification and analysis of reported data, the EPA is
proposing to require reporting of certain unit level information for
each unit in an aggregation of units or common pipe configuration,
excluding units less than 10 million British thermal units per hour
(mmBtu/hr).
Under subpart H (Cement Production) and subpart S, we are proposing
to collect additional data elements where the EPA has little data on
which to build verification checks. For these subparts, we are
proposing to collect annual averages of chemical composition input data
on a facility-basis. The proposed data elements would assist the EPA in
verification of continuous emission monitoring systems (CEMS) facility
emissions.
[[Page 36929]]
Because CEMS facilities typically include combustion and process
emissions that are vented through the same stack, process and
combustion emissions are usually mixed and indifferentiable. By
collecting average chemical composition data, the EPA would be able to
compare and differentiate process emissions from CEMS facilities. Such
additions to reporting would improve the accuracy of the emissions data
and render such information more valuable and useful.
For subpart W, we are proposing to add or revise reporting
requirements to better understand and 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.
Additionally, under subpart GG (Zinc Production), the EPA is
proposing that facilities report the total amount of electric arc
furnace (EAF) dust annually consumed by all Waelz kilns at the
facility. In this case, because the amount of EAF dust consumed in
Waelz kilns is strongly correlated with CO2 emissions, the
proposed data element would serve as a useful data validation point and
could potentially be used for the future development of an emission
factor.
The proposed revisions to add new reporting requirements would also
extend the usefulness of GHGRP data to improve the EPA's ability to
carry out other CAA programs. For example, we are proposing under
subpart HH to require MSW landfills to report data on the landfill
CH4 emissions that are destroyed versus sent to landfill gas
energy projects. This information would additionally help inform the
development of GHG policies and programs by providing information on
the amount of recovered CH4 that is beneficially used in
energy recovery projects and would inform the EPA, as well as state and
local government officials, on progress towards renewable energy
targets, and would also be useful to other stakeholders. As discussed
in prior amendments, the GHGRP is also intended to supplement and
complement the U.S. GHG Inventory and other EPA programs by advancing
the understanding of emission processes and monitoring methodologies
for particular source categories or sectors. The GHGRP also provides
data from individual facilities and suppliers above certain thresholds,
which can additionally be used to improve the assumptions and emissions
values used in the U.S. GHG Inventory (see 81 FR 2546, January 15,
2016). The facility, unit, and process level GHG emissions data for
industrial sources collected under the GHGRP does not replace the
system in place to produce the top-down U.S. GHG Inventory, but can be
additionally used to improve the accuracy of the U.S. GHG Inventory by
confirming the national statistics and emission estimation
methodologies. Therefore, the EPA periodically reviews the data from
the GHGRP to consider whether there are data that are useful to the
GHGRP and that would also improve the accuracy of the data included in
the U.S. GHG Inventory or improve our ability to inform the development
of GHG policies and programs. We are proposing several amendments that
would improve the data collected by the GHGRP, and subsequently, would
provide data that would benefit and support the U.S. GHG Inventory. For
example, we are proposing to revise the current requirements for
subpart N (Glass Production) facilities to require reporting the annual
quantities of glass produced by glass type. In general, the emissions
profile of a specific glass type is relatively consistent with the
composition of the glass, based on the major raw materials (limestone,
dolomite, and soda ash). Collecting data on annual production by glass
type would improve verification for the GHGRP by allowing the EPA to
compare emissions by glass types produced and would also provide useful
information to improve analysis of this sector in the U.S. GHG
Inventory.
5. 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 electronic Greenhouse Gas Reporting Tool (e-GGRT)
and are intended to resolve uncertainties in the regulatory text. For
example, we are proposing amendments in several subparts that would
clarify requirements that have led to reporter uncertainty, such as
reported data elements that may be unclear and misread by reporters. In
several cases, these provisions may have introduced uncertainty into
the rule and resulted in reporting that is inconsistent with the rule
requirements. The proposed clarifications would reduce the uncertainty
associated with certain reported data elements and increase the
likelihood that reporters will submit accurate reports the first time.
For example, we are proposing a revision to subpart Y to resolve the
potential discrepancy between the flare emission calculations at 40 CFR
98.253(b), which requires that all gas discharged through the flare
stack must be included in the calculations except for pilot gas, and
the requirements at 40 CFR 98.253(b)(1)(iii), which excludes startup,
shutdown, and malfunction (SSM) events less than 500,000 standard cubic
feet per day (scf/day) from equation Y-3. As another example, under
subpart W, the EPA is proposing to clarify the calculation of emissions
from open thief hatches on atmospheric storage tanks that use vapor
recovery systems and flares, by revising 40 CFR 98.233(j)(4) and (5) to
specify how to account for those emissions. The EPA's intent is that
reporters should be including emissions from open thief hatches, but
the current rule does not provide explicit provisions for them. We are
also proposing to revise 40 CFR 98.236(j)(1) to clarify reporting of
emissions from atmospheric storage tanks with vapor recovery systems
and flares. 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.
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-2019-0424).
B. Revisions To Streamline and Improve Implementation of 40 CFR Part 98
Since 2010, the EPA has collected data through the GHGRP to assess
industry emissions, and has, through review of annually submitted data,
gained substantial knowledge of the types, quantities, and distribution
of emissions across industry sectors. Through this process, the EPA has
engaged in stakeholder outreach, solicited feedback, responded to
questions from reporters, and identified site specific scenarios or
issues that could impact the quality of the data reported. In a recent
review of the requirements of the program, we have identified several
areas of part 98 that could be revised or simplified to reduce
technical challenges associated with implementation or improve the
[[Page 36930]]
efficiency of the requirements, while maintaining the quality of the
data collected. We are subsequently proposing several revisions that
would streamline the calculation, monitoring, and reporting burden
associated with the rule. These revisions would revise applicability
estimation methodologies, provide flexibility for or simplifying
calculation and monitoring methodologies, streamline recordkeeping and
reporting, and other minor technical corrections or clarifications.
The specific changes that we are proposing that are intended to
streamline part 98, as described in this section, are described in
detail for each subpart in sections III.A through III.W of this
preamble.
1. Revisions To Applicability for Certain Industry Sectors
We are proposing to change the applicability criteria for three
subparts to account for changes in usage of certain GHGs, or where the
current applicability estimation methodology may overestimate
emissions. The proposed changes would improve the estimation
methodologies used to determine applicability for specific subparts and
more accurately focus GHGRP and reporter resources on coverage of large
industrial emitters within these sectors; such changes are in keeping
with our goal to maximize coverage and collection of GHG emissions data
from each sector while excluding small emitters.
Currently, any facility that contains a source category listed in
Table A-3 of subpart A of part 98 (General Provisions) is subject to
reporting under part 98 (referred to as ``all-in'' source categories
because reporting applies regardless of other source category or
stationary fuel combustion emissions at the facility). Table A-3
defines a few of the ``all-in'' source categories using thresholds that
use metrics other than mtCO2e of emissions. A facility that
contains a source category listed in Table A-4 of subpart A of part 98
must report only if estimated annual emissions from all applicable
source categories in Tables A-3 and Table A-4 of part 98 are 25,000
mtCO2e or more (referred to as ``threshold'' source
categories). The EPA has used the ``threshold'' approach where a source
category contains emitters with a range in emissions quantity and the
EPA wants to capture those facilities within the source category with
larger total emissions from multiple process units or collocated source
categories that emit significant levels of GHGs collectively, and not
burden smaller emitters with a reporting obligation. The EPA has used
the ``all-in'' approach for industries for which all facilities are
emitters of a similar quantity or to gather data on certain industries
to identify the parameters that influence GHG emissions from the source
category.
The EPA used alternative metrics for some subparts in Table A-3 for
a variety of reasons. In some cases, the metric provides a more
straightforward way for facilities within that source category to
evaluate their applicability. For example, for subpart DD (Electrical
Transmission and Distribution Equipment), the metric is based on the
total nameplate capacity of SF6 and PFC-containing equipment
and was approximated as equivalent to the 25,000 metric tons of
CO2 threshold. To ensure that the GHGRP data collected
better reflects the current electrical power system industry, we are
proposing to remove the existing nameplate capacity threshold, and
instead provide a calculation method for facilities to estimate total
annual GHG emissions for comparison to the 25,000 metric tons of
CO2 threshold. These changes align with proposed changes to
redefine the source category to include equipment containing
``fluorinated GHGs (F-GHGs), including but not limited to sulfur-
hexafluoride (SF6) or and perfluorocarbons (PFCs)'', and
reflect that some facilities within the industry sector have begun to
use lower GWP F-GHGs, which is not reflected when using only the
nameplate capacity of the equipment to determine applicability. The
proposed changes would establish an updated comparison to the threshold
and would account for additional fluorinated gases (including F-GHG
mixtures) used in industry. The proposed changes to the threshold would
decrease the number of facilities with annual emissions less than
25,000 metric tons CO2e that would be required to report.
The proposed changes would require tracking of additional fluorinated
gases and the equipment they are contained in; however, this additional
burden is expected to be small as these gases are not yet widely used.
Similarly, we are proposing to revise the threshold for subpart SS
(Electrical Equipment Manufacture or Refurbishment), which is based on
total annual purchases of SF6 and PFCs. As with subpart DD,
we are proposing to revise the existing requirements of subpart SS to
require reporting of additional F-GHGs beyond SF6 and PFCs,
and we are proposing to revise the subpart SS threshold to align with
these changes. The proposed changes would continue to be based on the
total annual purchases of F-GHGs but would establish a calculation
method for comparison to the 25,000 metric tons of CO2
threshold, and would better account for the additional fluorinated
gases (including F-GHG mixtures) reported by industry. The proposed
changes would require tracking of additional fluorinated gases and the
equipment they are contained in; however, this additional burden is
expected to be small as these gases are not yet widely used.
We are also proposing revisions to provide a second option for an
alternative calculation methodology, that is consumption-based, that
reporters subject to subpart I (Electronics Manufacturing) could use to
determine whether they meet the emissions threshold for reporting
applicability. For subpart I (Electronics Manufacturing), the current
provisions of 40 CFR 98.91 require facilities to estimate whether the
25,000 metric tons of CO2e threshold is met based on
emissions estimates assuming the facility operates at its annual
manufacturing capacity, which may result in significant over-estimation
of emissions. The capacity-based methodology has required reporting by
some electronics manufacturing facilities that use smaller amounts of
F-GHGs. For subpart I, the method for determining the applicability was
chosen to reduce the burden on low-emitting facilities by providing a
simplified method to estimate emissions for the purpose of assessing
applicability. However, for subpart I, the applicability threshold
provisions may currently require certain lower-emitting facilities to
report where the capacity-based estimation methodology overestimates
emissions. We are proposing to revise the applicability estimation
methodology in subpart I to provide a second option for an alternative
calculation method using a gas-consumption basis, and to use updated
emission factors, so that facilities may choose instead to use a
separate method that more accurately calculates potential facility
emissions. This may result in fewer facilities reporting under subpart
I, but these facilities are expected to have annual emissions that are
lower than 25,000 metric tons of CO2e. The gas consumption-
based approach to determining applicability would require tracking gas
consumption, which is not required by the production capacity-based
threshold when determining applicability; however, this option to
determine applicability is less burdensome than reporting to subpart I,
[[Page 36931]]
which a facility would be required to do under the current rule if
their capacity were above the capacity-based threshold. Under the
current rule, facilities reporting under subpart I must collect gas
consumption data to complete their subpart I report. Thus, overall, the
burden for potential new entrants to the program would decrease.
We are proposing to revise the applicability of these subparts to
more accurately estimate facility emissions and to more accurately
focus GHGRP and reporter resources on the collection of data for the
larger industrial emitters within these sectors. These changes would
continue to maximize coverage of GHG emissions data from the sector
while excluding small emitters. The proposed revisions would also
adjust the applicability provisions for each of these subparts for
consistency across part 98. The proposed changes to subparts I, DD, and
SS are described in sections III.E, III.N, and III.U of this preamble.
2. Revisions To Streamline Monitoring and Calculation Methodologies
We are proposing revisions to provide flexibility for or simplify
some calculation methods or monitoring requirements. We are proposing
options to revise monitoring requirements in instances where we
currently allow a less burdensome methodology for similar emissions
sources; or where continuing to collect the data on the same frequency
would be unlikely to provide significantly different values.
In some cases, we are proposing amendments that would add
flexibility to the calculation methods to add less burdensome options
that would correspond with a decrease in actual data collection. These
types of proposed changes would simplify monitoring for reporters
without impacting the quality of the data reported. For example, for
subpart Y (Petroleum Refineries), we are proposing to allow the use of
mass spectrometer analyzers to determine gas composition and molecular
weight without the use of a gas chromatograph. The proposed revisions
would allow reporters to use the same analyzers used for process
control or for compliance with continuous sampling required under the
National Emissions Standards for Hazardous Air Pollutants from
Petroleum Refineries (40 CFR part 63, subpart CC) to comply with the
GHGRP requirements in subpart Y. Currently, these reporters must
conduct separate periodic sampling of these gas streams for analysis
using gas chromatography to comply with GHGRP requirements in subpart
Y, and the proposed revisions would provide flexibility for and reduce
burden for these reporters.
We are also proposing to clarify applicability provisions to reduce
uncertainty regarding which calculation method should be used. For
example, for subpart W (Petroleum and Natural Gas Systems), we are
proposing to revise the definition of the Onshore Natural Gas
Processing industry segment so that reporters have more certainty
regarding the industry segment and calculation methods that are
applicable 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. The two potentially applicable
segments report emissions from different sources and with different
calculation methods. For example, facilities in the Onshore Natural Gas
Processing industry segment are not required to report emissions from
atmospheric storage tanks and are required to measure leaks from
individual compressors, while facilities in the Onshore Petroleum and
Natural Gas Gathering and Boosting industry segment are required to
report emissions from atmospheric storage tanks but may use emission
factors to calculate emissions from compressors rather than conducting
measurements. Therefore, 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., 40
CFR part 60, subpart OOOOa). This proposed revision to the Onshore
Natural Gas Processing industry segment definition would make it clear
to reporters 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. As discussed in
greater detail in section III.J.2.h of this preamble, we are also
proposing several other changes to the Onshore Natural Gas Processing
industry segment definition. Collectively, these proposed amendments
are not expected to significantly affect the overall coverage of the
GHGRP for the petroleum and natural gas systems industry, although we
anticipate that some facilities would report under a different industry
segment going forward.
Additional details of these types of proposed changes may be found
in section III of this preamble.
3. Revisions To Streamline or Revise Recordkeeping and Reporting
Requirements
Other proposed revisions to the rule include changes that would
streamline the rule, such as revising certain reporting and
recordkeeping requirements that are redundant or no longer being used,
or that would remove duplicative reporting across EPA programs. For
example, for subpart C (General Stationary Fuel Combustion Sources), we
are proposing to amend certain provisions in 40 CFR 98.36 that require
facilities with the aggregation of units or common pipe configuration
types to report the total annual CO2 mass emissions from the
combustion of all fossil fuels combined. In this case, the reported
configuration-level annual CO2 emissions from all fossil
fuels does not factor into any subpart- or facility-level total
CO2 emission calculations and is not integrated into e-
GGRT's programmed ``roll up'' of emissions. Because we can adequately
verify reports and interpret and analyze the reported data without
these data elements, they are currently redundant and would not likely
provide new insights or knowledge of the industry sector, emissions, or
trends at this time.
In some cases, we are proposing to correct inconsistencies in the
current rule. Under subpart Y, we are proposing a change to correct an
inconsistency introduced by the amendments to the DCU calculations
published on December 9, 2016 (81 FR 89188). Although the prior
amendments removed the option to calculate CH4 emissions
from DCUs using the process vent method, the associated recordkeeping
requirements for the process vent method were inadvertently not removed
from the rule. Therefore, we are therefore proposing to remove the
associated recordkeeping requirements.
[[Page 36932]]
For subpart W, 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 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 40 CFR 98.236(j)(2)(i)(E) through (F) require
reporters to delineate the counts used in equation W-15. Based on
feedback from reporters, the EPA has determined 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 streamlining reporting by removing
duplicative reporting elements within or across GHGRP subparts. 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 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 will streamline reporting and reduce the burden on
reporters.
We are also proposing to reduce the frequency of reporting
information that we anticipate will not change on a frequent basis,
such as the data collected for technology assessment reports under
subpart I (Electronics Manufacturing). Based on the data collected in
the initial technology assessment reports (currently required by 40 CFR
98.96(y)), we do not anticipate significant variations in these data
elements within a three-year period going forward, as discussed in
section III.E.2 of this preamble. Further, we are proposing several
significant improvements to the technology assessment reports that will
improve the usefulness and quality of the data provided in the reports.
The proposed improvements would allow the EPA to collect these data
less frequently while continuing to provide the EPA with updates to the
gases and technologies used in semiconductor manufacturing.
Additional details of these types of proposed changes may be found
in section III of this preamble.
C. Revisions to 40 CFR Part 9
The EPA is proposing a related change to update 40 CFR part 9 to
include the OMB control number issued under the PRA for the ICR for the
GHGRP. The OMB control numbers for EPA regulations in Title 40 of the
CFR (after appearing in the Federal Register) are listed in 40 CFR part
9 and are included on the related collection instrument or form, if
applicable. The EPA is proposing to amend the table in 40 CFR part 9 to
list the OMB approval number under which the ICR for activities in the
existing part 98 regulations that were previously approved by OMB have
been consolidated. The prior approvals are included in OMB No. 2060-
0629; OMB No. 2060-0629 has not previously been added to 40 CFR part 9
due to an oversight. This listing of the OMB control number and the
subsequent codification in the CFR would correct this oversight and
satisfy the display requirements of the PRA and OMB's implementing
regulations at 5 CFR part 1320.
III. Proposed Amendments to 40 CFR Part 98
This section summarizes the specific substantive amendments
proposed for each subpart, as generally described in section II of this
preamble. The impacts of the proposed revisions are summarized in
section VII 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-2019-0424.
A. Subpart A--General Provisions
1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart A
In this action, we are proposing several clarifying revisions to
subpart A of part 98 (General Provisions). For the reasons described in
section II.A.5 of this preamble, we are proposing to clarify in 40 CFR
98.2(i)(1) and (2) that the provision to allow cessation of reporting
or ``off-ramping,'' due to meeting either the 15,000 mtCO2e
level or the 25,000 mtCO2e level for the number of years
specified in 40 CFR 98.2(i), is based on the CO2e reported,
calculated in accordance with 40 CFR 98.3(c)(4)(i) (i.e., the annual
emissions report value as specified in that provision). The proposed
changes clarify that reporters must rely on the emissions estimation
methodologies used to report emissions and their annual emissions
report totals to determine their ability to off-ramp. We are also
proposing to clarify the off-ramp provisions at 40 CFR 98.2(i)(1) and
(2) to specify that after an owner or operator off-ramps, the owner or
operator must use equation A-1 and follow the requirements of 40 CFR
98.2(b)(4) in subsequent years to determine if emissions exceed the
25,000 mtCO2e applicability threshold and whether the
facility or supplier must resume reporting. The requirements of 40 CFR
98.2(b) are different from the requirements of 40 CFR 98.3(c) in that
the applicability determination requires more flexible calculation
methods (e.g., facilities may use any subpart C tier to estimate
combustion emissions on 40 CFR 98.2(b), whereas they must follow the
applicable subpart C tier to calculate combustion emissions under 40
CFR 98.3(c)). The proposed revisions make clear that reporters who have
previously off-ramped would continue to follow the emission estimation
methods used for determination of applicability to determine if they
must resume reporting.
We are also proposing to revise 40 CFR 98.2(f)(1) to clarify how to
calculate GHG quantities for comparison to the 25,000 mtCO2e
threshold for importers and exporters of industrial greenhouse gases;
the proposed changes specify that the calculation must include the
fluorinated heat transfer fluids (F-HTFs) that are imported or exported
during the year. In the December 9, 2016 final rule, 2015 Revisions and
Confidentiality Determinations for Data Elements Under the Greenhouse
Gas Reporting Rule (81 FR 89234), the EPA expanded the definition of
the source category for importers and exporters of industrial
greenhouse gases to include facilities that destroy 25,000
mtCO2e or more of industrial F-GHGs or F-HTFs annually, and
entities that produce, import, or export F-HTFs that are not also F-
GHGs. It was our intent that suppliers of F-HTFs be subject to the same
[[Page 36933]]
thresholds.\4\ However, we inadvertently neglected to update 40 CFR
98.2(f) to include F-HTFs in the calculation requirements. Similarly,
we are proposing to add a new paragraph (k) to 40 CFR 98.2, specifying
how to calculate the quantities of F-GHGs and F-HTFs destroyed for
purposes of comparing them to the 25,000 mtCO2e threshold
for stand-alone industrial F-GHG or F-HTF destruction facilities. This
paragraph was inadvertently omitted when the rule was revised to cover
stand-alone destruction facilities in 2016. The proposed changes would
clarify that imported, exported, and destroyed F-HTFs and F-GHGs must
be calculated and included when determining applicability.
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\4\ In the 2016 proposed rule, we specified ``Suppliers of
fluorinated HTFs would be subject to the same thresholds as
suppliers of fluorinated GHGs. That is, there would be no threshold
for producers of fluorinated HTFs, but the threshold for importers,
exporters, and destroyers of fluorinated HTFs would be 25,000
mtCO2e of fluorinated HTFs or GHGs.'' (81 FR 2572,
January 15, 2016).
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We are also proposing new paragraph 40 CFR 98.4(n) that would apply
in lieu of 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: Onshore
Petroleum and Natural Gas Production; Onshore Petroleum and Natural Gas
Gathering and Boosting; Natural Gas Distribution; and Onshore Natural
Gas Transmission Pipeline. For these industry segments, particularly
Onshore Petroleum and Natural Gas Production and Onshore Petroleum and
Natural Gas Gathering and Boosting, asset transactions between owners
and operators can involve only some emission sources at the facility
rather than the entire facility. In those cases, reporters have
submitted numerous questions to the e-GGRT 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 address some of these
questions, the EPA previously developed Frequently Asked Questions
(FAQ) Q749.\5\ However, neither the FAQ nor the existing requirements
in subpart A explicitly explain the responsibilities for the situations
for which reporters have requested guidance.
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\5\ 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 that 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 RY2023 reports. The provisions would also
specify when an owner or operator should submit an annual report using
an e-GGRT identifier assigned to an existing facility and when an owner
or operator should 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 will 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). The proposed
provisions would apply in lieu of 40 CFR 98.4(h) for these industry
segments. These proposed revisions are expected to improve data quality
as described in section II.A.4 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.A.5 of
this preamble.
We expect all the transactions will 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 previously
owned applicable emission sources in the same geographic area as part
of the purchased facility beginning with the reporting year in which
the acquisition occurred.
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.
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
[[Page 36934]]
sources. 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 begin
reporting their acquired applicable emission sources as a new facility
or add the acquired applicable emission sources to their existing
facility.
Finally, for all of these 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, 2023, as described in section V of this preamble, then for ownership
transactions that occur on or after January 1, 2023, 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, 2025, then the selling owner or operator
and purchasing owner or operator would follow the applicable provisions
previously described in this section for the RY2025 report and for
future reporting years. We are also proposing that the provisions
described in the next paragraph would apply for RY2024 and prior years'
reports.
Specifically, we are proposing that as part of each ownership
transaction described previously in this section, the selling owner or
operator and purchasing owner or operator would agree upon the entity
that would be responsible for revisions to annual GHG reports for
previous reporting years. That entity would then select a
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. If that individual is not the designated representative for
the facility, the individual would need to be appointed as the
alternate designated representative or an agent for the facility. In
many situations, particularly for the first two categories of
transactions described in this section, the EPA expects that the
purchaser would agree to select a representative to address revisions
to previous years' annual GHG reports. In addition, 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 representative. In
other situations, the parties may determine that it is appropriate for
the seller to select the representative to address revisions to annual
GHG reports for reporting years prior to the reporting year in which
the acquisition occurred. Alternatively, parties to the transaction may
agree on another independent party that would act as the representative
regarding annual GHG reports for previous reporting years, such as a
consultant. The EPA expects that the decision regarding the responsible
entity would be made as part of the acquisition agreement or ownership
transfer contract between the selling owner or operator and purchasing
owner or operator and that if the entity responsible for revisions to
annual GHG reports is not 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 responsible entity at that time.
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.
In addition, we are proposing to revise 40 CFR 98.3(h)(4) to limit
the total number of days a reporter can request to extend the time
period for resolving a substantive error either by submitting a revised
report or providing information demonstrating that the previously
submitted report does not contain the substantive error. According to
40 CFR 98.3(h) a substantive error may either be identified by the EPA
or discovered by the facility itself. If discovered by the facility, a
revised report correcting the error must be submitted within 45 days.
If identified by the EPA, once the facility is notified of the error,
the facility must either resubmit the corrected report or provide
information demonstrating that the previously submitted report does not
contain the identified substantive error within 45 days. The rule also
states that if requested in either case, the EPA may provide reasonable
extensions to the 45-day period, including an automatically granted
extension of 30 days. Additional extensions may be granted if the
facility submits a request that is received prior to the expiration of
the automatic 30-day extension. The current rule states that the
Administrator will approve the additional extension request if the
request demonstrates that it is not practicable to collect and process
the data needed to resolve potential reporting errors within 75 days.
However, since the GHGRP was implemented, we have encountered instances
where a facility has repeatedly requested an extension of the time
period by which they must either submit a revised report or provide
information that the previously submitted report does not contain a
substantive error. As such, the EPA cannot verify the facility's report
in a timely manner. To avoid such instances in the future, we are
proposing to add to 40 CFR 98.3(h)(4) that the Administrator will only
approve extension requests for a total of 180 days from the initial
notification of a substantive error. We expect that 180 days is a
reasonable amount of time for a facility to examine company records,
gather additional data, and/or perform recalculations to submit a
revised report or provide the necessary information such that the
report may be verified.
[[Page 36935]]
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 described in section III.J of this preamble. 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. Additionally, 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 vent to
the regenerator firebox/fire tubes does not qualify as vapor recovery.
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 making these clarifying
edits, the EPA expects to improve the quality of the emissions data
reported and alleviate any confusion surrounding the applicability of
these terms.
As a corollary to proposed amendments to subpart W to remove
desiccant dehydrators as an emissions source, we are proposing to
remove the definition of ``desiccant'' and to revise the definition of
``dehydrator'' in 40 CFR 98.6. The definition of ``desiccant'' would no
longer be needed if the emission calculation and reporting requirements
for desiccant dehydrators are removed from subpart W, as discussed in
section III.J of this preamble. Similarly, the definition of
``dehydrator'' would no longer need to include a reference to
desiccant. Thus, we are proposing to revise the definition of
``dehydrator'' to indicate that a dehydrator is ``a device in which a
liquid absorbent (e.g., ethylene glycol, diethylene glycol, or
triethylene glycol) directly contacts a natural gas stream to absorb
water vapor.''
We are proposing revisions to 40 CFR 98.6 to add a definition for
``Direct air capture'' and amend the definition of ``Carbon dioxide
stream''. These proposed changes are being made in conjunction with
other proposed revisions to subpart PP of part 98 (Suppliers of Carbon
Dioxide) and are discussed in section III.T of this preamble.
In addition, we are proposing two harmonizing changes to 40 CFR
98.7 to incorporate by reference ASTM International (ASTM) E415-17,
Standard Test Method for Analysis of Carbon and Low-Alloy Steel by
Spark Atomic Emission Spectrometry (2017) for subpart Q (Iron and Steel
Production) and CSA/ANSI ISO 27916:2019, Carbon Dioxide Capture,
Transportation and Geological Storage--Carbon Dioxide Storage Using
Enhanced Oil Recovery (CO2-EOR) for proposed subpart VV (Geologic
Sequestration of Carbon Dioxide with Enhanced Oil Recovery Using ISO
27916). These proposed changes are further described in sections III.H
and III.W of this preamble.
Lastly, we are proposing two updates to Table A-1, the list of GWPs
used in the GHGRP, to revise GWPs that, based on recent information,
overestimate the atmospheric impacts of certain compounds by a large
margin (i.e., by factor of 2,000). We are not proposing any other
updates to the Table A-1 GWPs. First, we are proposing to adopt a
chemical-specific GWP for carbonic difluoride (COF2).
Emissions of COF2 of 1-2 metric tons per year have been
reported under the GHGRP from fluorinated gas production. (Carbonic
difluoride is also used in the electronics industry as an etching agent
and surface treatment, although emissions of COF2 from
electronics manufacturing have not been reported under the GHGRP). No
peer-reviewed, chemical-specific GWP was available for COF2
in 2014, when we last updated the set of GWPs in Table A-1 (79 FR
73750, December 11, 2014). It is therefore currently classified as an
``Other fluorinated GHG'' and is assigned a default GWP of 2,000 under
the GHGRP. However, the World Meteorological Organization (WMO)
recently published an atmospheric lifetime, radiative efficiency, and
GWP for COF2 in its Scientific Assessment of Ozone Depletion
6 (2018). Like the IPCC Assessment Reports upon which the
GWPs in Table A-1 are based, the WMO Scientific Assessments include
regularly updated international reviews of the scientific findings on
the impacts of trace gases in the atmosphere, including their
atmospheric lifetimes and radiative efficiencies. According to the 2018
WMO Scientific Assessment, COF2 has a lifetime of
approximately seven days, and 20-year and 100-year GWPs of less than
one. The 2018 WMO Scientific Assessment listed the 100-year GWP of
COF2 as ``<1,'' so we calculated and are proposing a precise
GWP for COF2 of 0.14 using the atmospheric lifetime and
radiative efficiency provided in the 2018 WMO Scientific Assessment.
(The method we used to calculate the GWP of COF2 was the
method we used to calculate precise GWPs for low-GWP compounds in the
most recent update to GHGRP GWPs (79 FR 73750, December 11, 2014)).
This recent information supports that including a chemical-specific GWP
for COF2 of 0.14 would reflect its atmospheric impacts far
more accurately than the currently applied GHGRP default GWP of 2,000.
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\6\ WMO. Scientific Assessment of Ozone Depletion: 2018, Global
Ozone Research and Monitoring Project-Report No. 58, 588 pp.,
Geneva, Switzerland, 2018. https://www.esrl.noaa.gov/csd/assessments/ozone/2018/downloads/2018OzoneAssessment.pdf. Retrieved
July 29, 2019. Available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2019-0424.
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Second, we are proposing to expand one of the F-GHG groups to which
a default GWP of 1 is applied to include additional unsaturated
fluorocarbons. The ninth F-GHG group in Table A-1 to subpart A
currently includes unsaturated PFCs, unsaturated HFCs, unsaturated
hydrochlorofluorocarbons (HCFCs), unsaturated halogenated ethers,
unsaturated halogenated esters, fluorinated aldehydes, and fluorinated
ketones. We are proposing to add unsaturated bromofluorocarbons,
unsaturated chlorofluorocarbons, unsaturated bromochlorofluorocarbons,
unsaturated hydrobromofluorocarbons, and unsaturated
hydrobromochlorofluorocarbons to this set. These F-GHGs do not have
chemical-specific GWPs in Table A-1, and facilities and suppliers that
currently report these F-GHGs generally classify them as ``Other
fluorinated GHGs,'' which are assigned a default GWP of 2,000. However,
two lines of evidence indicate that unsaturated bromofluorocarbons,
unsaturated chlorofluorocarbons, unsaturated bromochlorofluorocarbons,
unsaturated hydrobromofluorocarbons, and unsaturated
hydrobromochlorofluorocarbons are likely to have GWPs near 1. First,
like many of the types of compounds currently included in the ninth F-
GHG group, they are unsaturated (i.e., they include double and triple
bonds between carbon atoms), and unsaturated GHGs in general tend to
have very short atmospheric lifetimes and GWPs near or below 1. Second,
evaluations of individual unsaturated chlorofluorocarbons and
unsaturated bromofluorocarbons have all found very short atmospheric
lifetimes and (where assessed) low GWPs for these compounds. The 2018
WMO Scientific Assessment provides atmospheric lifetimes for three
unsaturated chlorofluorocarbons and four unsaturated
bromofluorocarbons, and it provides an atmospheric lifetime and a 100-
year GWP for one unsaturated
[[Page 36936]]
bromochlorofluorocarbon (4-bromo-3-chloro-3,4,4-trifluoro-1-butene).
All of the atmospheric lifetimes are under 8 days,\7\ and the 100-year
GWP is listed as ``<1.'' Therefore, the EPA's assessment is that, due
to their short atmospheric lifetimes, unsaturated bromofluorocarbons,
unsaturated chlorofluorocarbons, unsaturated bromochlorofluorocarbons,
unsaturated hydrobromofluorocarbons, and unsaturated
hydrobromochlorofluorocarbons are likely to have a GWP near 1 (the
default GWP for the ninth F-GHG group) rather than 2,000 (the default
GWP for ``Other Fluorinated GHGs''). The EPA is proposing to add these
additional unsaturated fluorocarbons to the ninth F-GHG group to result
in more accurate estimation of the reported mtCO2e.
---------------------------------------------------------------------------
\7\ The IPCC Fifth Assessment Report lists 100-year GWPs of less
than one for all the compounds for which the report lists an
atmospheric lifetime of less than 8 days. The IPCC Fifth Assessment
Report is the source of the chemical-specific GWPs for the compounds
in the ninth F-GHG group in Table A-1. See 2013: Anthropogenic and
Natural Radiative Forcing. In: Climate Change 2013: The Physical
Science Basis. Contribution of Working Group I to the Fifth
Assessment Report of the Intergovernmental Panel on Climate Change.
https://www.ipcc.ch/site/assets/uploads/2018/02/WG1AR5_Chapter08_FINAL.pdf.
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We are proposing to incorporate a harmonizing change based on the
addition of a new source category for quantifying geologic
sequestration in association with EOR operations. Specifically, we are
proposing to add the new subpart, subpart VV (Geologic Sequestration of
Carbon Dioxide with Enhanced Oil Recovery Using ISO 27916), in Table A-
3 to subpart A.
As discussed in section III.W of this preamble, facilities that
conduct EOR currently have the option to either report basic
information on CO2 received under subpart UU (Injection of
Carbon Dioxide), or report CO2 sequestered under subpart RR
(Geologic Sequestration of Carbon Dioxide). Facilities that conduct EOR
are not required to report under subpart RR unless the owner or
operator chooses to opt-in to subpart RR, or the well is permitted as
an Underground Injection Control (UIC) Class VI well. We are proposing
that facilities that use the standard Carbon Dioxide Capture,
Transportation and Geological Storage--Carbon Dioxide Storage Using
Enhanced Oil Recovery (CO2-EOR) (CSA/ANSI ISO 27916:2019) for
quantifying geologic sequestration of CO2 in association
with EOR operations would similarly have the option to report under the
proposed subpart VV instead of subpart UU. Facilities that conduct EOR
would therefore have two options to report amounts of CO2
that are geologically sequestered: subpart RR or subpart VV.
We are proposing to include the new subpart VV in Table A-3 to
subpart A. In addition, we are proposing that this new subpart would
not include a reporting threshold for applicability. The EPA previously
promulgated subparts RR and UU with no threshold (i.e., as ``all-in''
source categories in Table A-3 to subpart A) due to variability in
CO2 injection amounts from year to year and based on limited
knowledge of which EOR reporters that are not required to report under
subpart RR would choose to report geologic sequestration (see 75 FR
18454, April 10, 2010 and 75 FR 75070, December 1, 2010). The
facilities affected by the proposed subpart include facilities that are
currently reporting under subpart UU and that do not currently report
amounts of CO2 sequestered. The EPA is proposing no
threshold for the proposed subpart VV so that all EOR facilities that
quantify CO2 sequestration using the CSA/ANSI ISO 27916:2019
standard and that do not report under subpart RR would have the option
to either report under the proposed subpart VV, or would otherwise
continue to report under subpart UU. For these reasons, we do not
anticipate that the new subpart would increase the number of facilities
subject to the GHGRP. Further, it is difficult to predict how many
injection facilities would choose to report using the ISO standard in
lieu of continuing to report under subpart UU. Therefore, we are
proposing that subpart VV would be an ``all-in'' reporting subpart in
order to allow the Agency to continue to comprehensively track all
CO2 that is injected underground, and to remain consistent
with the ``all-in'' requirements for EOR or injection facilities that
currently report under subparts RR or UU. Reporters who choose to
report under this subpart would be required to meet the requirements of
40 CFR 98.2(a)(1). However, as proposed in new 40 CFR 98.480(c),
facilities subject only to new subpart VV would not be required to
report emissions under subpart C or any other subpart listed in 40 CFR
98.2(a)(1) or (2), consistent with the requirements for the existing
facilities under subpart UU.
Additionally, we are proposing that facilities subject to proposed
subpart VV would not be required to meet the off-ramp requirements of
40 CFR 98.2(i). Instead, once a facility opts-in to proposed subpart
VV, the owner or operator must continue for each year thereafter to
comply with all requirements of the subpart, including the requirement
to submit annual reports, until the facility demonstrates termination
of the CO2-EOR project following the requirements of CSA/
ANSI ISO 27916:2019. The EPA is proposing that the operator notify the
Administrator of its intent to cease reporting and provide a copy of
the CO2-EOR project termination documentation prepared for
CSA/ANSI ISO 27916:2019. See section III.W of this preamble for
additional details on the proposed revisions.
2. Proposed Amendments To Streamline and Improve Implementation for
Subpart A
For the reasons described in sections II.B.1, III.N, and III.U of
this preamble, we are proposing harmonizing edits in subpart A of part
98 to revise the rule applicability for subparts DD (Electrical
Transmission and Distribution Equipment Use) and subpart SS (Electrical
Equipment Manufacture or Refurbishment). The proposed applicability
threshold for subparts DD and SS would be based on total emissions
equivalent to the 25,000 mtCO2e or more per year, rather
than the current threshold levels that are based on the total nameplate
capacity of the equipment or the annual consumption, respectively. For
subpart DD, we are proposing to revise Table A-3 such that the
threshold is based on total estimated emissions from F-GHGs, as
determined under 40 CFR 98.301 (subpart DD), that are equivalent to
25,000 mtCO2e or more per year. For subpart SS, we are
proposing to revise Tables A-3 and Tables A-4 such that: (1) subpart SS
would be removed from Table A-3; and (2) Table A-4 would be revised to
specify that subpart SS facilities would be included in 40 CFR
98.2(a)(2) and Table A-4, as determined under the requirements of 40
CFR 98.451 (subpart SS), which provide estimation methods for total
estimated emissions from F-GHGs for comparison to a threshold
equivalent to 25,000 mtCO2e or more per year. Refer to
sections III.N and III.U of this preamble for a detailed discussion of
these proposed changes and how the proposed new thresholds would be
implemented. The proposed revisions are intended to harmonize Tables A-
3 and A-4 with the proposed changes described in sections II.B.1,
III.N, and III.U of this preamble, which would update the threshold to
be consistent with the threshold set for the majority of subparts and
would account for additional fluorinated gases (including F-GHG
mixtures) reported by industry, and for subpart DD, would also
streamline the reporting requirements to
[[Page 36937]]
focus Agency resources on the substantial emission sources within the
sector by excluding facilities or operations that may report emissions
that are consistently and substantially below 25,000 mtCO2e
per year (see section IV.C (``Rationale for Selection of Thresholds'')
of the preamble to the 2009 Proposed Rule (74 FR 16467, April 10,
2009)).
B. Subpart C--General Stationary Fuel Combustion Sources
1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart C
We are proposing several amendments to improve the quality of the
data collected under subpart C of part 98 (General Stationary Fuel
Combustion Sources). This section describes the specific changes
proposed.
First, for the reasons provided in section II.A.2 of this preamble,
we are proposing to modify the Tier 3 calculation methodology in
subpart C. Reporters to subpart C may use the Tier 3 methodology
provided in 40 CFR 98.33(a)(3) for determining annual CO2
emissions from combustion units. The Tier 3 methodology requires a
calculation based on annual fuel use, measured carbon content, and for
gaseous fuels, measured molecular weight. For gaseous fuels, equation
C-5 at 40 CFR 98.33(a)(3)(iii) requires that the carbon content and
molecular weight be in units of kilogram (kg) C/kg fuel and kg/kg-mole,
respectively, and be determined using the same procedures as specified
for high heating value (HHV) at 40 CFR 98.33(a)(2)(ii). However, when
using equation C-2b at 40 CFR 98.33(a)(2)(ii)(A) in this manner, the
fuel carbon content is on a mass basis (i.e., kg C/kg fuel) while the
fuel flow is on a volumetric basis (i.e., scf), resulting in a
weighting factor that is potentially problematic because the units of
measure are not in equivalent terms, i.e., the average annual carbon
content should be in mass terms (i.e., kg C/kg fuel). When using
equation C-2b for calculating an annual flow-weighted molecular weight,
a similar situation occurs. This has been the case since the 2009 Final
Rule (74 FR 56397).
To address this matter, the EPA is proposing to modify the Tier 3
calculation methodology in 40 CFR 98.33(a)(3)(iii) to provide new
equations C-5a and C-5b for calculating a weighted annual average
carbon content and a weighted annual average molecular weight.
respectively. These new proposed equations incorporate the molar volume
conversion factor at standard conditions (as defined at 40 CFR 98.6)
and for annual average carbon content, the measured molecular weight of
the fuel, in order to convert the fuel flow to the appropriate units of
measure. This proposed change will correct the calculation method for
Tier 3 gaseous fuels. The EPA does not expect a significant change in
reported emissions because the change to the values for carbon content
and molecular weight is expected to be minimal under the proposed
calculation methods. Additionally, some reporters have previously
exercised the option to manually override the calculated emission
values with their own calculated values to address this issue when it
has been identified.
We are also proposing several revisions to rule provisions
pertaining to the calculation of biogenic emissions from tire
combustion to improve the existing calculation methodology. First, for
the reasons described in section II.A.2 of this preamble, the EPA is
proposing to revise the calculation methods that must be used to
determine the total annual CO2 emissions under 40 CFR
98.33(e)(3)(iv)(A) when determining the biogenic CO2
emissions of MSW or tires under 40 CFR 98.33(e)(3)(iv). Currently, 40
CFR 98.33(e)(3)(iv) provides procedures in certain circumstances to
estimate the annual biogenic CO2 emissions in the combustion
of MSW or tires, which start with requiring that the Tier 1 calculation
method be used to determine the total annual CO2 emissions
from MSW or tires under 40 CFR 98.33(e)(3)(iv)(A). The value determined
under 40 CFR 98.33(e)(3)(iv)(A) is then multiplied by the applicable
default biogenic fraction specified at 40 CFR 98.33(e)(3)(iv)(B) to
determine the total biogenic CO2 emissions. At the same
time, 40 CFR 98.33(a) provides four calculation methodologies, Tier 1
through 4, and an alternative methodology for certain units subject to
40 CFR part 75, for calculating CO2 emission for fuel
combustion. In certain circumstances, a reporter may be required under
40 CFR 98.33(a) to calculate CO2 emissions from combustion
of MSW or tires using Tiers 2 or 3 for the purposes of annual
reporting, but then must also calculate the total CO2
emissions using Tier 1 under 40 CFR 98.33(e)(3)(iv)(A) for the purpose
of determining and reporting the biogenic CO2 emissions from
combustion of MSW or tires under 40 CFR 98.33(e)(3)(iv). This has
previously resulted in some confusion for reporters where total
CO2 emissions are calculated twice using different tiers,
one tier for one aspect of annual reporting and another tier for
biogenic calculation and reporting, and a redundancy in calculation of
total CO2 emissions by reporters. This has also resulted in
some confusion when comparing the calculated total CO2
emissions under 40 CFR 98.33(a) to the estimated total biogenic
CO2 emissions under 40 CFR 98.33(e)(3)(iv), since they are
based on different calculation methodologies. The EPA is proposing to
revise 40 CFR 98.33(e)(3)(iv)(A) so that total annual CO2
emissions will be calculated using the applicable methodology in
paragraphs 40 CFR 98.33(a)(1) through (3) for units using Tier 1
through 3 for purposes of 40 CFR 98.33(a), and using the Tier 1
calculation methodology in paragraph 40 CFR 98.33(a)(1) for units using
the Tier 4 or part 75 for purposes of 40 CFR 98.33(a), when determining
the biogenic component of MSW or tires under 40 CFR 98.33(e)(3)(iv).
The EPA is proposing two additional substantive revisions to the
procedures for calculating and reporting emissions of biogenic
CO2 from the combustion of tires. First, for the reasons
discussed in section II.A.1 of this preamble, we are proposing to
update a default factor that is used to determine biogenic
CO2 emissions from the combustion of tires. Separately
reporting the biogenic CO2 emissions (i.e., specifying which
emissions are biogenic) from the combustion of tires is currently
optional, but if a reporter elects to do so, then 40 CFR 98.33(e)(3)
specifies the calculation procedure. Under 40 CFR 98.33(e)(3), if tires
provide more than 10 percent of the annual heat input to a unit and the
owner or operator elects to separately report the biogenic
CO2 emissions from the combustion of tires, then the owner
or operator must conduct testing using ASTM method D6866-16, Standard
Test Methods for Determining the Biobased Content of Solid, Liquid, and
Gaseous Samples Using Radiocarbon Analysis (2016) and ASTM method
D7459-08, Standard Practice for Collection of Integrated Samples for
the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide
Emitted from Stationary Emissions Sources (2016) to determine the
biogenic fraction of CO2.\8\ But if tires provide 10 percent
or less of the annual heat input, then reporters have the option to
separately report the biogenic CO2 emissions by multiplying
the total CO2 emissions by a default factor of 0.20. The
0.20 factor is based on
[[Page 36938]]
information from the Rubber Manufacturers Association (RMA) that was
based on most current data available at the time of the publication of
the GHG Reporting Rule revisions in the Federal Register on December
17, 2010 (75 FR 79092) (hereafter referred to as the 2010 Final
Revisions Rule) and represented an arithmetic average of the natural
rubber content (i.e., composition) of passenger and commercial tires
sold and thus available for combustion.\9\ Since publication of the
2010 Final Revisions Rule, we have received a memorandum from the U.S.
Tire Manufacturers Association (USTMA, formerly RMA) that based on
updated data, the weighted average composition of natural rubber in
tires is now 24 percent.10 11 The proposed default value was
calculated by weighting the average rubber content, average weight, and
shipment percentage of both light duty vehicle and commercial vehicle
scrap tires, which is more accurate than would result from using the
arithmetic average. In addition to the comments and information
provided by the USTMA, the Portland Cement Association (PCA) provided
supporting information from one of its member companies, Mitsubishi
Cement. Operational data (total count and weight of tires combusted)
and analytical data (percent of biogenic carbon based on ASTM D6866-20)
from 2020 was provided.\12\ The EPA reviewed these data and determined
that they support the USTMA's recommended 0.24 default biogenic
fraction for tires.\13\ We are therefore proposing to revise 40 CFR
98.33(e)(3)(iv)(B) to update the default biogenic fraction to 0.24.\14\
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\8\ ASTM D7459-08 was approved for use in the October 30, 2009
final rule (74 FR 56291), see Docket Id. No. EPA-HQ-OAR-2008-0508.
ASTM D6866-16 was approved for use in the December 9, 2016 final
rule (81 FR 89196), see Docket Id. No. EPA-HQ-OAR-2015-0526.
\9\ Please refer to the memorandum, Natural Rubber Fraction in
Tire Derived Fuel by Matt Hakos and Cassy Becker, RTI International
to Michael Hannan, EPA (August 2021), available in the docket for
this rulemaking, Docket Id. No EPA-HQ-OAR-2019-0424, for more
detail.
\10\ See the memorandum, Methodology for Determining the Natural
Rubber Fraction in Tire Derived Fuel, by Sarah Amick and Jesse
Levine, USTMA to U.S. EPA (April 11, 2019), available in Docket Id.
EPA-HQ-OAR-2019-0424.
\11\ Supra note 9.
\12\ See ``Tire Biogenic Content Data Provided by the Portland
Cement Association'' (August 2021), available in Docket Id. EPA-HQ-
OAR-2019-0434.
\13\ Supra note 9.
\14\ Supra note 9.
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Second, for the reasons described in section II.A.3 of this
preamble, we are proposing that all units that combust tires must
separately report biogenic CO2 emissions. The separate
reporting of biogenic CO2 from tires was made optional in a
2010 final rule (75 FR 79100, December 17, 2010). For that rulemaking,
we received no public comments on the proposal to make separate
biogenic CO2 emissions reporting optional for the combustion
of tires, and the proposal was finalized without modification. In the
final rule preamble, however, we stated: ``No comments were received on
the proposal to make biogenic CO2 emissions reporting
optional for the combustion of tires, and the proposal has been
finalized without modification. However, tire-derived fuel has a
biomass component, and perhaps it should be treated in the same manner
as MSW, which is also partly biogenic. A number of units that are
subject to part 98 combust tires as the primary fuel or as a secondary
fuel. Therefore, we are considering whether these units should be
required to separately account for their biogenic CO2
emissions. However, before making this mandatory we intend to open it
to notice and comment in a future rulemaking'' (75 FR 79109). In
conjunction with this change, we are proposing to remove the
restriction in 40 CFR 98.33(e)(3)(iv) that the default factor may only
be used to estimate the annual biogenic CO2 emissions from
the combustion of tires if the combustion of tires represents ``no more
than 10 percent annual heat input to a unit.'' Following the 2010 Final
Revisions Rule, reporters that chose to optionally report biogenic
CO2 emissions from tire combustion were required to use
quarterly flue-gas testing using ASTM methods, except that small units
(i.e., units in which tires provide no more than 10 percent of the
annual heat input to a unit) could alternatively use the default
factor. The proposal to remove the current restriction allowing only
small units to use the default factor (i.e., allowing the use of the
default factor for all units that combust tires), when combined with
the proposed requirement to report biogenic CO2 emissions
from tire combustion, would result in a more accurate characterization
of emissions from larger units since no units that combust tires alone
or in conjunction with fossil fuels have reported, for RY2015 through
RY2018, biogenic CO2 emissions that were calculated using
the quarterly flue-gas testing results. Therefore, the proposed
addition of reporting of biogenic CO2 emissions for tire
combustion should require no additional monitoring or data collection
and could be reported with minimal additional reporting burden. The EPA
is proposing that this change would only be finalized if the proposed
requirement to report biogenic CO2 emissions from tire
combustion is also finalized. Additionally, we are proposing another
change that would only be finalized if the proposed requirement to
report biogenic CO2 emissions from tire combustion is also
finalized. Specifically, 40 CFR 98.33(b)(1)(vii) currently allows units
that combust MSW and/or tires to use Tier 1 if the combined heat input
from both fuels is not greater than 10 percent of the heat input to the
unit but also provides that, if a reporter choose the option to not
report biogenic CO2 from tire combustion, the 10 percent
threshold applies only to the MSW fuel. If the proposed mandatory
reporting of biogenic CO2 from tire combustion is finalized,
we are proposing that the additional provision in 40 CFR
98.33(b)(1)(vii) on how to apply the threshold to only MSW fuel would
be deleted, since it would no longer be applicable. This may result in
fewer facilities being able to use Tier 1 to calculate MSW and/or tire
CO2 emissions since the tire heat input would now always be
included in conjunction with the MSW heat input to compare to the 10
percent threshold.
In conjunction with these proposed revisions, we are also proposing
to remove the language in 40 CFR 98.33(e) and 40 CFR 98.36(e)(2)(xi)
referring to optional biogenic CO2 emissions reporting from
tire combustion, and to revise 40 CFR 98.34(d) to reference 40 CFR
98.33(e)(3)(iv) instead of 40 CFR 98.33(b)(1)(vi) and (vii). We are
proposing the latter change because 40 CFR 98.34(d) incorrectly
references 40 CFR 98.33(b)(1)(vi) and (vii), which specify certain
provisions when Tier 1 can be used, whereas 40 CFR 98.33(e)(3)(iv)
specifies when the default biogenic factor for MSW can be used (i.e.,
in cases where combustion of MSW provides no more than 10 percent of
the annual heat input to the unit or if a small, batch incinerator
combusts no more than 1,000 tons per year of MSW) and is the correct
reference for 40 CFR 98.34(d). This revision is being proposed to
correct this reference in accordance with other proposed changes.
Additionally, we are proposing a clarifying correction to 40 CFR
98.33(e), Biogenic CO2 emissions from combustion of biomass with other
fuels. Section 98.33(e)(1) specifies that equation C-1 of subpart C can
be used to calculate the annual CO2 mass emissions from the
combustion of the biomass fuels listed in Table C-1 of this subpart
(except MSW and tires). We are proposing to delete the parenthetical
clause ``(except MSW and tires)'' in 40 CFR 98.33(e)(1) because,
although MSW and tires are partially biogenic, they were never
categorized as biomass fuels
[[Page 36939]]
in Table C-1 of subpart C and thus no aspect of Table C-1 was excepted
by this parenthetical clause. This deletion would correct the drafting
oversight and will not result in any change to the reporting
requirements.
Next, for the reasons discussed in section II.A.5 of this preamble,
we are proposing to correct the equation C-11 term definition for the
variable ``R''. Equation C-11 is used to calculate the CO2
emissions from sorbent use when the chemical reaction between the acid
gas and sorbent produces CO2 emissions and when these
emissions are not monitored with a CEMS. The term ``R'' is currently
defined as the number of moles of CO2 released upon capture
of one mole of the acid gas species being removed (R = 1.00 when the
sorbent is CaCO3 and the targeted acid gas species is
SO2). However, the units of measure for the equation as
presented do not currently result in metric tons CO2
emitted. We are proposing to revise the definition of the term ``R'' as
``the number of moles of CO2 released per mole of sorbent
used (R = 1.00 when the sorbent is CaCO3 and the targeted
acid gas species is SO2)'' so that the equation is
dimensionally correct (i.e., results in metric tons CO2
emitted).
We are also proposing to amend 40 CFR 98.33(c)(6)(i), (ii),
(ii)(A), and (iii)(C), and delete (ii)(B) to clarify the methods used
to calculate CH4 and N2O emissions for blended
fuels when heat input is determined after the fuels are mixed and
combusted. There would be no new reporting requirements because of this
proposed clarification.
For the reasons described in section II.A.4 of this preamble, we
are proposing a substantive revision to rule provisions pertaining to
the reporting of unit level information for the aggregation of units
and common pipe configurations. Currently, subpart C allows facilities
to report data using six different configurations. These configurations
are:
Individual unit using Tiers 1, 2, or 3 to calculate
emissions.
Individual unit using Tier 4 to calculate emissions.
Group of units using the aggregation of units reporting
alternative with Tiers 1, 2 or 3.
Group of units using the common pipe configuration
reporting alternative with Tiers 1, 2, or 3.
Group of units using Tier 4 to calculate emissions and
reporting under the monitored common stack or duct configuration
reporting alternative.
Part 75 units using the alternative CO2 mass
emissions calculation methods.
For RY2019, the approximate use of reporting
configurations and the percent of emissions for each is summarized:
----------------------------------------------------------------------------------------------------------------
Percent of Percent of
Number of total Subpart total Subpart
Configuration type Subpart C C C CO2
configurations configurations emissions
----------------------------------------------------------------------------------------------------------------
Individual Unit (Tiers 1-3)..................................... 9,185 58 36
Individual Unit (Tier 4)........................................ 208 1 9
Aggregation of Units (Tiers 1-3)................................ 4,362 27 24
Common Pipe (Tiers 1-3)......................................... 1,905 12 26
Common Stack (Tier 4)........................................... 21 0.1 2
Alternative Part 75............................................. 192 1 2
----------------------------------------------------------------------------------------------------------------
Individual unit information (i.e., the unit type and the maximum
rated heat input capacity) is currently only required to be reported
for the individual unit (Tiers 1-3 and Tier 4) reporting
configurations. The individual unit information allows the EPA to
aggregate emissions according to unit type and size and provides a
better understanding of the emissions from specific unit types.
Individual unit information is not reported for the aggregation of
units, common pipe, common stack, or alternative part 75 reporting
configurations. As such, the EPA is currently unable to aggregate
emissions by unit type and size for these reporting configurations,
which represent 40 percent of the configurations used and 54 percent of
the emissions reported in subpart C.
The aggregation of units and common pipe configurations are the
second and third most used configurations and together, they represent
approximately 39 percent of the configurations and 50 percent of the
emissions reported to subpart C. Both of these reporting alternatives
allow multiple units to be reported under one configuration group.
Because the unit type and maximum rated heat input capacity are
currently not reported for the individual units within these two
configurations, there is a significant gap in the EPA's ability to
aggregate subpart C emissions data by unit type and size.
To better analyze reported data by unit type and size, the EPA is
proposing to revise 40 CFR 98.36(c)(1) and (3) (by adding 40 CFR
98.36(c)(1)(ii) and (c)(3)(xi)) to require reporting for each unit in
either an aggregation of units or common pipe configuration, excluding
units less than 10 mmBtu/hr from both, of the unit type, maximum rated
heat input capacity, and an estimate of the fraction of the total
annual heat input. Under the proposed amendments, unit level
information would be reported for four of the six configuration types.
This would allow the EPA to aggregate data according to unit type and
size for approximately 98 percent of the configurations and 95 percent
of the emissions in subpart C (the actual percent of emissions that
could be aggregated by unit type would be somewhat lower than 95
percent because units less than 10 would be excluded from the
additional reporting requirements) to provide unit level information
for the aggregated unit and common pipe configurations. We expect the
percent of emissions to be only somewhat lower than 95 percent because
units less than 10 mmBtu/hr are estimated to have minor emissions
contributions in aggregated unit and common pipe configurations, as
previously described in the 2016 final rulemaking (81 FR 89203,
December 9, 2016). Given the relatively low emissions from the common
stack (Tier 4) and part 75 configurations, the EPA is not proposing to
require reporting of individual unit information for these
configurations at this time. The EPA seeks comment on whether to
propose these requirements for the common stack (Tier 4) and part 75
configurations.
The proposed reporting requirements are not expected to
significantly increase burden for reporters. The requirement to report
the cumulative maximum rated heat input capacity for the aggregation of
units or common pipe configurations began with the 2017 reporting year
(81 FR 89188). Accordingly, facilities have been reporting cumulative
maximum rated heat input capacity for four years. To determine this
value, facilities must know the maximum rated heat input capacity of
all units in each aggregation
[[Page 36940]]
of units or common pipe configuration (greater than or equal to 10
mmBtu/hr), because these values are summed to determine the cumulative
value. The EPA expects that the other requirements (i.e., unit type and
estimate of the fraction of annual heat input) can be determined from
existing company records. The total fraction of annual heat input for
each unit in the group will be determined by dividing the estimated
actual heat input for that unit by the sum of the estimated actual heat
input for all units in the group. Accordingly, any new burden incurred
from this proposed requirement is expected to be minimal and associated
with calculating the fraction of the total annual heat input and
entering data into the e-GGRT software. To minimize the burden of
reporting these data in e-GGRT, the EPA intends to evaluate developing
a bulk unit details reporting form similar to the existing bulk
equation input reporting forms for Tiers 2 and 3.
For the reasons described, the EPA has proposed these new reporting
requirements under 40 CFR 98.36(c)(1)(ii) (aggregation of units) and 40
CFR 98.36(c)(3)(xi) (common pipe). These proposed amendments will
better inform future policy and programs by addressing a data gap in
unit information that currently exists for these two reporting
configurations. We are proposing related confidentiality determinations
for the additional data elements, as discussed in section VI of this
preamble.
As a corollary to proposed amendments to subpart W (Petroleum and
Natural Gas Systems) to address uncombusted methane emissions from
compressor drivers (see section III.J.1.n of this preamble), we are
proposing that natural gas-fired compressor drivers located at
facilities that are subject to subpart W would be required to use the
CH4 emission factors in Table W-9 to subpart W rather than
the default CH4 emission factor for natural gas in Table C-2
to subpart C. 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 CH4 emission
factors in Table W-9 to subpart W for natural gas compressor drivers.
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 for natural gas may only be used for natural gas-fired
combustion units that are not compressor drivers. Finally, we are
proposing to amend 40 CFR 98.36(c)(1) and (c)(3). Under the proposed
amendments, reporters may not report a combination of one design class
of compressor driver (using one Table W-9 CH4 emission
factor) and other combustion units (e.g., using a Table C-2
CH4 emission factor or another Table W-9 CH4
emission factor) in the same aggregation of units or common pipe
configuration. This change would ensure that all units in an
aggregation of units or common pipe configuration are using the same
CH4 emission factor for each fuel combusted in the unit.
We are proposing two additional clarifications to existing
reporting and record keeping requirements, for the reasons described in
section II.A.5 of this preamble. First, we are proposing to revise the
first sentence of 40 CFR 98.36(e)(2)(ii)(C) to clarify that both the
annual average, and, where applicable, monthly high heat values are
required to be reported. The monthly HHV reporting requirement was
always clear based on the language in this provision and the proposed
clarification plainly states that the annual average high heat value is
also a reporting requirement (for reporters who do not use the
electronic inputs verification tool (IVT) within e-GGRT). There are no
new reporting requirements because of this proposed clarification.
Second, we are proposing to revise 40 CFR 98.37(b)(9), (10), (11),
(14), (18), (20), (22), and (23) to specify recordkeeping data that is
currently contained in the file generated by the verification software
that is already required to be retained by reporters under 40 CFR
98.37(b) but was inadvertently omitted from being specified in those
subparagraphs. These proposed revisions correct omissions that
currently exist in the verification software recordkeeping requirements
specific to equations C-2a, C-2b, C-3, C-4, and C-5. They also align
the verification software recordkeeping requirements with the proposed
revisions to equation C-5 at 40 CFR 98.33(a)(3)(iii), as noted above.
These proposed revisions do not require any new action from affected
reporters, as all new recordkeeping data proposed is already contained
in the file generated by the verification software.
2. Proposed Revisions To Streamline Implementation and Reduce Burden
for Subpart C
We are proposing several revisions to subpart C to streamline
requirements and to adopt minor revisions to improve implementation of
the rule.
For the reasons described in section II.B.2 of this preamble, the
EPA is proposing to amend 40 CFR 98.34(c)(6). In the 2010 Final
Revisions Rule (75 FR 79092), the EPA added 40 CFR 98.34(c)(6), which
allowed cylinder gas audits (CGAs) of the CO2 monitor to be
performed using calibration gas concentrations of 40-60 percent and 80-
100 percent of CO2 span, when the CO2 span value
is set higher than 20 percent CO2. Under appendix F of 40
CFR part 60, CGAs of the CO2 analyzer are required at two
calibration gas concentrations (i.e., 5-8 percent and 10-14 percent
CO2 by volume). These CO2 concentration levels
are appropriate for certain stationary combustion applications (e.g., a
typical span value for a CO2 monitor installed on a coal-
fired boiler is 20 percent CO2). These CGA concentrations
represent 25-40 percent and 50-70 percent of the CO2 span
value, when the CO2 span is at 20 percent CO2.
When the CO2 span exceeds the typical span value of the fuel
being evaluated (e.g., 20 percent CO2 on a coal-fired
boiler), the CGA concentrations specified in part 60 are no longer
representative, as they only evaluate the lower portion of the
measurement scale. Since the EPA had information indicating that there
were cases when the CO2 span was set greater than 20 percent
CO2 (e.g., process and combustion emissions from cement
manufacturing may require 30 percent CO2 span), 40 CFR
98.34(c)(6) was added so that CGAs could be conducted at two separate
portions of the measurement scale, as opposed to just the lower portion
(see 75 FR 79111, December 17, 2010).
Since 2010, the EPA has received questions through GHGRP Help Desk
indicating that industrial flue gases also occur where the measured
CO2 concentration is very low (e.g., natural gas turbines
typically have about 5 percent CO2 in flue gas). In this
case, the required calibration gas concentrations (i.e., 5-8 percent
and 10-14 percent CO2 by volume) under appendix F of 40 CFR
part 60 would not be appropriate because they may be above the
CO2 span value and so would not provide information
regarding accuracy of the monitor at actual representative stack gas
concentrations. Accordingly, the EPA is proposing to amend 40 CFR
98.34(c)(6) to allow CGAs to be performed using calibration gas
concentrations of 40-60 percent and 80-100 percent of CO2
span, whenever the required CO2 span value for a flue gas
does is not appropriate for the prescribed audit ranges in appendix F
of 40 CFR part 60. This will allow CGAs to check the response of the
CO2 analyzer at two calibration gas concentrations,
representing separate portions of the measurement scale,
[[Page 36941]]
when the CO2 span is significantly lower or higher than 20
percent CO2.
For the reasons described in section II.B.3 of this preamble, the
EPA is proposing to amend certain provisions in 40 CFR 98.36 that
require facilities with the aggregation of units or common pipe
configuration types to report the annual CO2 mass emissions
from the combustion of all fossil fuels, per the requirements in 40 CFR
98.36(c)(1)(vi) and 40 CFR 98.36(c)(3)(vi). The EPA has reviewed the
data provided under these reporting requirements and has tentatively
concluded that they are no longer required for the verification or
analysis of subpart C annual reports. In addition, the reporting of
this data for the aggregation of units or common pipe configuration
types has caused confusion for reporters because they mistakenly
believe that the value is used in subpart C total CO2
emission calculations. Therefore, we are proposing to revise the
provisions in 40 CFR 98.36(c)(1)(vi) and 40 CFR 98.36(c)(3)(vi) to
remove the language requiring reporting of the total annual
CO2 mass emissions from all fossil fuels combined.
For these two configuration types (aggregation of units and common
pipe), the reported configuration-level annual CO2 emissions
from all fossil fuels does not factor into any subpart- or facility-
level total CO2 emission calculations. The e-GGRT calculates
the subpart-level non-biogenic CO2 emissions for these two
configuration types by summing the reported fuel-level CO2
emissions values from each fuel, regardless of whether it is biogenic
or not, then subtracting the reported configuration-level biogenic
CO2 emissions values. For the aggregation of units
configuration type, the reported configuration-level sorbent
CO2 emissions value, which is typically zero, is also added
into this ``rolled-up'' non-biogenic CO2 emissions total.
The calculation was specifically designed in this manner because the
reported fuel-level information for Table C-1 partially biogenic fuels
(i.e., tires, MSW) and some ``other'' or ``blend'' fuels that contain
biogenic material is not sufficient to allow the calculation of
biogenic CO2 emissions for each fuel such that it could be
accurately subtracted from the fuel-level CO2 emissions
values. Thus, the reported configuration-level biogenic CO2
emissions must be used in the subpart total calculations. Many
reporters then assume that the configuration-level annual
CO2 emissions from all fossil fuels is also used in the
subpart total calculations, which creates confusion for reporters and
has resulted in GHGRP Help Desk submissions stating that these
requirements are redundant and confusing. By proposing to revise the
provisions in 40 CFR 98.36(c)(1)(vi) and 40 CFR 98.36(c)(3)(vi) to
remove the language requiring reporting of the total annual
CO2 mass emissions from all fossil fuels combined, we would
remove this unnecessary confusion for reporters with aggregation of
units and common pipe configuration types.
C. Subpart G--Ammonia Manufacturing
For the reasons discussed in section II.A.2 of this preamble, we
are proposing several revisions to subpart G of part 98 (Ammonia
Manufacturing) to improve the quality of the data collected from this
subpart. Subpart G estimates CO2 emissions from ammonia
manufacturing based on a carbon mass balance, which assumes that all
carbon contained in feedstocks is transformed to CO2 and all
CO2 is emitted from the ammonia manufacturing process. The
EPA has received numerous comments from The Fertilizer Institute (TFI)
related to the calculation of CO2 emissions from the
production of ammonia in subpart G. Most comments from TFI were related
to the carbon mass balance methodology, especially with regard to other
products that could be produced using the CO2 emissions from
ammonia production. TFI has asserted that most ammonia manufacturing
facilities capture and use the CO2 resulting from the
ammonia manufacturing process to produce urea. Subpart G does not
currently allow the subtraction of the CO2 that is bound in
urea from calculated and reported emissions or otherwise allow separate
reporting of that CO2.
In response to the 2009 Proposed Rule, TFI submitted a comment
letter dated June 9, 2009, and provided comments via a public hearing
on April 6, 2009, stating that the CO2 produced through
ammonia manufacturing is often utilized in the manufacturing of urea
and that the EPA mistakenly assumed that all CO2 in urea
will be released into the atmosphere.\15\ \16\ In response, in the 2009
Final Rule, the EPA changed the rule requirements to collect
information on urea production and uses of the urea if known, stating
``Collecting information on urea production and its uses will help
[the] EPA to improve methodologies for estimating emissions from
ammonia manufacturing, urea production and urea consumption in the
future.''
---------------------------------------------------------------------------
\15\ TFI's Comments on the ``Proposed Mandatory Reporting of
Greenhouse Gases Rule'' Docket Id. No. EPA-HQ-OAR-2008-0508-2376,
June 9, 2009. Also available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424.
\16\ USEPA Public Hearing for Proposed Rulemaking for Mandatory
Reporting of Greenhouse Gases. Transcript Day One of Two. April 6,
2009. Docket Id. No. EPA-HQ-OAR-2008-0508-0212. Also available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
The EPA next revised 40 CFR 98.72(a) and 40 CFR 98.73(b)(5) in
subpart G (75 FR 79092, December 17, 2010) to explain that the
``CO2 process emissions reported under this subpart may
include CO2 that is later consumed on site for urea
production, and therefore is not released to the ambient air from the
ammonia manufacturing process unit.'' This revision was proposed
pursuant to a settlement agreement with TFI, after TFI challenged the
2009 rulemaking.\17\
---------------------------------------------------------------------------
\17\ The Fertilizer Institute v. EPA, Docket Id. No. 09-1329
(D.C. Circuit), 2010. Also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
In response to an April 2, 2013 EPA-proposed rule (78 FR 19802),
TFI submitted a comment letter dated May 2, 2013, requesting that the
EPA revise subpart G to require only the reporting of CO2
emitted directly to the atmosphere from the synthetic ammonia
production process instead of continuing to include the CO2
captured during ammonia production and used to produce urea, noting its
view that the captured CO2 ``does not contribute to the
CO2 emission estimates for ammonia production.'' \18\ TFI
further argued the existing methodology is inconsistent with other
source categories covered by the rule (namely subpart P (Hydrogen
Production) and subpart X (Petrochemical Production)) and is contrary
to the EPA's methodology used in the U.S. GHG Inventory. TFI pointed to
similarities between the structure of subpart G and subpart P, and
argued that the structure of subpart G be revised to be more consistent
with subpart X, which allows sources to account for carbon (i.e.,
subtract from direct facility emissions) that is being shipped off-site
in products. In response, the EPA responded that TFI had raised a
consistency issue within part 98 that ``merits evaluation and requires
further analysis by the EPA.'' However, the EPA explained that no
changes were made at that time because TFI's comment was outside of the
scope of the rulemaking.\19\
---------------------------------------------------------------------------
\18\ TFI's Comments on the Proposed ``2013 Revisions to the
Greenhouse Gas Reporting Rule and Proposed Confidentiality
Determinations for New or Substantially Revised Data Elements,''
Docket Id. No. EPA-HQ-OAR-2012-0934-0036, May 2, 2013. Also
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424.
\19\ Summary of Public Comments and Responses for Greenhouse Gas
Reporting Rule: 2013 Revisions to the Greenhouse Gas Reporting Rule
and Confidentiality Determinations for New or Substantially Revised
Data Elements. Docket Id. No. EPA-HQ-OAR-2012-0934-0127, November
2013. Also available in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
[[Page 36942]]
In response to a January 15, 2016 EPA-proposed rule (81 FR 2536),
TFI submitted a comment letter dated March 30, 2016, again requesting
that part 98 be made consistent with the methodology used in the U.S.
GHG Inventory, such that CO2 bound in urea would not be
considered an emission from the ammonia manufacturing process.\20\
Also, TFI asked for clarification regarding a new requirement in
subpart G to report the amount of methanol produced at the ammonia
manufacturing facility. In response, the EPA noted the potential of
using a future rulemaking to address TFI's suggested revisions ``to
require reporting only CO2 that is emitted directly to the
atmosphere from ammonia manufacturing, rather than reporting
CO2 that is bound in the urea that is produced from ammonia
at some facilities,'' but explained that the comment was outside the
scope of that rulemaking. The EPA clarified in the preamble and in the
final rule (81 FR 89188, December 9, 2016) that the quantity of
methanol being reported only includes methanol that is ``intentionally
produced as a desired product'' and does not include the quantity of
methanol that is vented or destroyed.
---------------------------------------------------------------------------
\20\ TFI's Comments on the Proposed ``2015 Revisions and
Confidentiality Determinations for Data Elements under the
Greenhouse Gas Reporting Rule,'' Docket Id. No. EPA-HQ-OAR-2015-
0526-0064, March 30, 2016. Also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
TFI submitted two other comment letters in 2017. The letter dated
March 31, 2017 was submitted to the Department of Commerce as part of a
request for information ``Impact of Federal Regulations on Domestic
Manufacturing'' (82 FR 12786, March 7, 2017).\21\ The letter dated May
15, 2017 was submitted to the EPA's request for comment on ``Evaluation
of Existing Regulations'' (82 FR 17793, April 13, 2017).\22\ Both
letters contained similar language asking that the GHGRP be amended to
``report the quantity of GHG that is actually emitted to the atmosphere
as part of the manufacturing processes'' instead of ``GHG emissions
that are captured and either sold or used in other industrial
processes.''
---------------------------------------------------------------------------
\21\ TFI, Impact of Federal Regulations on Domestic
Manufacturing, Docket Id. No. DOC-2017-0001-0064, March 31, 2017,
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-2019-0424.
\22\ TFI, Comments on ``Evaluation of Existing Regulations,''
Docket Id. No. EPA-HQ-OA-2017-0190-40791, May 15, 2017, 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-2019-0424.
---------------------------------------------------------------------------
After consideration of the comments from TFI summarized above, the
EPA has tentatively concluded that requiring reporters subject to
subpart G to report the GHG emissions that occur directly from the
ammonia manufacturing process (i.e., net CO2 process
emissions) after subtracting out carbon or CO2 captured and
used in other products would provide a more accurate estimate of the
emissions and would provide consistency in our approach across the
GHGRP. Therefore, for the reasons described in this section and in
section II.A.2 of this preamble, we are proposing multiple amendments
to subpart G. Under the proposed rule, equation G-4 and equation G-5
would be combined into a new equation G-4 and paragraph 98.73(b)(5)
would be deleted. The reporting requirement in paragraph 98.76(b)(1)
specifies emissions for each individual ammonia manufacturing
processing unit, so determining the combined CO2 emissions
from all ammonia manufacturing processing units using equation G-5 is
not necessary for reporting. The new equation G-4 would allow reporters
to subtract CO2 used in the production of urea and carbon
bound in methanol that is intentionally produced as a desired product
instead of assuming that the CO2 bound in urea is emitted or
that the carbon contained in methanol is converted to CO2
and emitted, resulting in the calculation of net CO2
emissions that occur directly from ammonia manufacturing. We are also
proposing a harmonizing revision to the introductory paragraph of 40
CFR 98.73. These proposed changes are not expected to result in an
increase in burden because the monthly equation inputs for the new
equation G-4 would already be available to calculate the annual values
of CO2 collected from ammonia production and consumed on-
site for urea production and the quantity of intentionally produced
methanol, both of which are already reported. Similarly, for reporters
that do not produce urea or methanol, the burden under the new equation
to calculate CO2 emissions remains unchanged. Further,
because we are retaining the requirement to report the CO2
collected from ammonia for urea production and methanol production, the
proposed amendments would not result in any negative impacts to the
quality of the data collected under the GHGRP and such data would
remain available for potential policy evaluation.
As a result of the new proposed equation G-4, two new monthly
recordkeeping data elements are being proposed as part of the
verification software records required in 40 CFR 98.77(c), including:
(1) quantity of CO2 collected from ammonia production and
consumed on site for urea production each month; and (2) quantity of
methanol intentionally produced as a desired product each month. These
recordkeeping changes are not expected to result in a significant
increase in burden because both elements are already being reported on
an annual basis (40 CFR 98.76(b)(13) and (15)). For reporters that do
not produce urea or methanol, the requirements for recordkeeping remain
unchanged. We are proposing harmonizing revisions to the introductory
paragraph of 40 CFR 98.76 and to the reported data elements at 40 CFR
98.76(b)(1) to clarify that reporters must provide the ``annual net
CO2 process emissions'' for each ammonia manufacturing unit,
and at 40 CFR 98.76(b)(13) to clarify that reports must provide the
``annual amount of CO2 collected from ammonia production
(metric tons) and consumed on site for urea production and the method
used to determine the CO2 consumed in urea production.'' The
proposed revision to the reported emissions value excludes any
CO2 used in the production of urea and carbon bound in
methanol that is intentionally produced as a desired product. We are
proposing related confidentiality determinations for the revised data
elements, as discussed in section VI of this preamble.
Finally, corresponding amendments are being proposed to remove the
language specified above that was added in the 2010 Final Revisions
Rule (75 FR 79092), described above. Paragraph 98.72(a) will be amended
to read, ``CO2 process emissions from steam reforming of a
hydrocarbon or the gasification of solid and liquid raw material,
reported for each ammonia manufacturing unit following the requirements
of this subpart.''
In addition, minor amendments to equation G-1, equation G-2, and
equation G-3 are being proposed to simplify the equations by removing
the process unit ``k'' designation in the terms ``CO2,G,k,''
``CO2,L,k,'' and ``CO2,S,k.'' The introductory
paragraph to each of these equations already specifies that emissions
must be calculated for each ammonia manufacturing unit. Removing the
extra subscript will
[[Page 36943]]
clarify the equations. No changes to burden are expected from these
changes.
D. Subpart H--Cement Production
For the reasons described in section II.A.4 of this preamble, we
are proposing to add new data elements to the data reporting
requirements for subpart H of part 98 (Cement Production) to enhance
the quality and accuracy of the data collected. Specifically, we are
proposing to collect new data elements under 40 CFR 98.86(a) and 40 CFR
98.86(b). Subpart H currently requires calculation of CO2
emissions using one of two methodologies, either direct measurement
using CEMS, or a mass balance (non-CEMS) methodology based on mass,
carbonate content, and fraction of calcination for each carbonate-based
material. For the mass balance method, facilities enter input data that
is used to calculate emissions factors for produced materials. These
inputs include, for example, monthly measurements of calcium oxide
content and magnesium oxide content. Subpart H emission equations
inputs are not collected under the GHGRP, and so the EPA has little
data on which to build verification checks for these inputs in the
reporting system. In order to improve the data verification process, we
are proposing to collect annual averages for these chemical composition
input data on a facility-basis. The proposed data elements (for both
facilities that report CEMS data and those that report using a mass-
balance method) include the annual arithmetic average weight fraction
of: total CaO content, non-calcined CaO content, total MgO content, and
non-calcined MgO content of clinker at the facility; and total CaO
content of cement kiln dust (CKD) not recycled to the kiln(s), non-
calcined CaO content of CKD not recycled to the kiln(s), total MgO
content of CKD not recycled to the kiln(s), and non-calcined MgO
content of CKD not recycled to the kiln(s) at the facility. The
proposed data elements would rely on an arithmetic average of the
measurements rather than requiring reporters to weigh by quantity
produced in each month. CEMS facility emissions calculations are
importantly different from non-CEMS emissions calculations because
combustion and process emissions are typically vented through the same
stack, causing process and combustion emissions to be mixed and
indifferentiable. Therefore, in addition to improving the input
verification process, collecting average chemical composition data for
CEMS facilities will provide the EPA the ability to check the reported
CEMS emission data for accuracy by creating the ability to back-
estimate process emissions. In order to be able to estimate and check
the accuracy of process emissions, we are also proposing to collect
other data elements for both facilities using CEMS and those that
report using the mass-balance method, including annual facility CKD not
recycled to the kiln(s) in tons and raw kiln feed consumed annually at
the facility in tons (dry basis). Facilities are already required to
report or maintain records of other production data that would be
needed to perform these estimates. Facilities using the mass-balance
method currently collect CKD not recycled to the kiln(s) on a quarterly
basis to estimate CO2 emissions from clinker production.
Similarly, facilities also record the annual raw kiln feed for each
kiln, which is used to determine the CO2 emissions from raw
materials for each kiln in equation H-5. The proposed data elements
would instead sum the CKD not recycled and raw kiln feed quantity
across all kilns at a facility. The proposed data elements will allow
us to estimate process emissions for comparison to facility reported
emissions estimates as a verification check. In addition to improving
verification and data quality for cement emissions, the proposed data
elements will also improve the U.S. GHG Inventory. The U.S. GHG
Inventory can use the proposed data elements to internally disaggregate
process and combustion emissions that are reported by facilities using
CEMS, and create more accurate national-level cement emissions profile.
In general, we do not anticipate that the proposed data elements
would require any additional monitoring or data collection by
reporters, as these data are likely already available in existing
company records. These additions would result in especially minimal
reporting changes for non-CEMS facilities, as the chemical composition
averages can be calculated using the input data that is already
required to be entered in the reporting system. However, we are
requesting comment on whether any of the above listed data elements
would not be readily available to reporters. We are proposing related
confidentiality determinations for the additional data elements, as
discussed in section VI of this preamble.
Finally, for the reasons described in section II.A.5 of this
preamble, we are proposing to clarify equations H-1 and H-5. We are
proposing to clarify that equation H-5 calculates the CO2
emissions from raw materials on a per kiln basis. Facilities currently
maintain records of the amount and organic carbon content of raw
materials and raw kiln feed consumed annually per kiln, and enter this
data into the e-GGRT verification software during submission of their
annual reports. The verification software collects the kiln-level data
to verify the inputs and generates a file containing the records, which
are specified in 40 CFR 98.87(c)(14) through (17). The CO2
emissions for the facility are then summed for all kilns at the
facility-level using equation H-1, which sums the annual CO2
emissions from clinker production (from equation H-2) and the annual
emissions from raw materials for each kiln (from equation H-5). We are
proposing revisions to the inputs ``rm,'' ``CO2 rm,'' and
``TOCrm'' in equation H-5 to clarify that the data elements
are input on a per-kiln basis, and to add brackets to clarify that
emissions are calculated as the sum of emissions from all raw materials
or raw kiln feed used in the kiln. Similarly, we are proposing to
revise equation H-1 to add brackets to clarify the summation of clinker
and raw material emissions for each kiln, and updating the definition
of ``CO2 rm'' to clarify the raw material input is on a per-
kiln basis. The proposed revisions are corrections that would harmonize
equations H-1 and H-5 with the existing recordkeeping requirements and
align the calculation methodology in the rule and e-GGRT. We are also
proposing minor corrections to the parameters of equation H-4 for
quarterly non-calcined CaO content of CKD not recycled to the kiln and
quarterly non-calcined MgO content of CKD not recycled to the kiln. The
2009 final rule inadvertently defined the equation parameters for both
quarterly non-calcined CaO content and quarterly non-calcined MgO
content as ``CKDCaO'' and ``CKDMgO'',
respectively, while equation H-4 defines these parameters as
``CKDncCaO'' and ``CKDncMgO''. To remove any
confusion for reporters, we are proposing to correct the defined
parameters for quarterly non-calcined CaO content and quarterly non-
calcined MgO content of CKD not recycled to ``CKDncCaO'' and
``CKDncMgO'', respectively. These clarifications would not
require any changes to the monitoring, recordkeeping, or reporting
provisions, or impact how reporters currently collect or enter data for
their annual reports.
E. Subpart I--Electronics Manufacturing
Under subpart I of part 98 (Electronics Manufacturing), electronics
manufacturing facilities must report F-GHG and F-HTF emissions from
electronic manufacturing production processes and N2O
emissions from chemical vapor deposition (CVD) and
[[Page 36944]]
other electronics manufacturing processes. Facilities must also report
CO2, CH4, and N2O emissions from each
stationary combustion unit by following the requirements of subpart C
(General Stationary Combustion Sources).
We are proposing several amendments and clarifications to the
calculation methodologies requirements in subpart I. In addition, the
EPA is proposing conforming changes to the reporting and recordkeeping
requirements of subpart I. Changes include updating existing default
emission factors and destruction or removal efficiencies (DREs) based
on new data, revising certain calculation methods, adding a calculation
method for calculating by-products produced in abatement systems,
amending data reporting requirements, and providing clarification on
reporting requirements. We are proposing revisions that will better
reflect new industry data and current practice, improve the quality of
the data collected, and streamline the reporting requirements. We are
also proposing related confidentiality determinations for the proposed
new or revised data elements, as discussed in section VI of this
preamble.
1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart I
a. Revisions To Improve the Calculation Methodology for Stack Testing
We are proposing to revise 40 CFR 98.93(i), which specifies how to
calculate GHG emissions based on stack testing, in order to improve,
simplify, and correct the calculation method. As discussed in section
II.A.2 of this preamble, the proposed edits would improve the quality
of the data collection and calculation requirements associated with
stack testing. First, we are proposing to add new equations I-24C and
I-24D and a table of default weighting factors (new Table I-18) to
calculate the fraction of fluorinated input gases exhausted from tools
with abatement systems, ai,f, for use in equations I-19A
through I-19C and I-21, and the fraction of by-products exhausted from
tools with abatement systems, ak,i,f, for use in equations
I-20 and I-22. Second, we are proposing to revise equations I-24A and
I-24B, which calculate the weighted average DREs for individual F-GHGs
across process types in each fab.\23\ Third, we are proposing at 40 CFR
98.93(i)(3) to require that all stacks be tested if the stack test
method is used. Finally, we are proposing to replace equation I-19 with
a set of equations (i.e., equations I-19A, I-19B, and I-19C) that will
more accurately account for emissions when pre-control emissions of an
F-GHG come close to or exceed the consumption of that F-GHG during the
stack testing period.
---------------------------------------------------------------------------
\23\ Fab is defined in 40 CFR 98.98 as ``the portion of an
electronics manufacturing facility located in a separate physical
structure that began manufacturing on a certain date.''
---------------------------------------------------------------------------
The first three changes to the stack test method would remove the
requirements to apportion gas consumption to different process types,
to manufacturing tools equipped versus not equipped with abatement
systems, and to tested versus untested stacks. Currently, the fractions
of fluorinated input gases and by-product gases exhausted from
manufacturing tools with abatement systems, used in equations 1-19a
through I-22, must be estimated by apportioning gas consumption to
these tools. The proposed equations I-24C and I-24D would add the
option to calculate the fraction of each input gas ``i'' and by-product
gas ``k'' exhausted from tools with abatement systems based on the
number of tools that are equipped versus not equipped with abatement
systems, along with weighting factors that account for the different
per-tool emission rates that apply to different process types.
Facilities would continue to have the option to apportion gas
consumption to tools with and without abatement systems by using
paragraph 98.93(e). They would also have the option to apportion gas
consumption to the different process types and sub-types, calculating
ai,f and ak,i,f based on the numbers of tools
with and without abatement systems within each process type or sub-
type.
Weighting factors are necessary when: (1) per-tool pre-control
emission rates differ between different process types; (2) an input gas
is consumed by more than one process type; (3) the use of the input gas
is not apportioned between the process types; and (4) the fractions of
tools equipped with emissions control technologies differ between
process types. The weighting factors ([gamma]i,p for input
gases and [gamma]k,i,p for by-product gases, provided in
Table I-18) are based on data submitted by semiconductor manufacturers
during the process of developing the 2019 Refinement.\24\ This data
source was used in lieu of subpart I data, as the EPA does not collect
data on gas consumption or gas consumption per tool. The calculated
weighting factors were within the expected range, considering the
differences between the emission factors used and the expected per-tool
gas consumption for the different process types. For
microelectromechanical systems (MEMS) or PV manufacturing that uses
semiconductor tools and processes, the weighting factors in Table I-18
can be used. For processes without a weighting factor in Table I-18, a
default of 10 must be used. More information on the data used to
develop the weighting factors in Table I-18 can be found in the
document, Technical Support for Proposed Revisions to Subpart I (2021)
(hereafter referred to as ``subpart I TSD''), available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
\24\ The data used to develop the gamma weighting factors are
also available in the IPCC workbook, ``Gamma Data Submitted by
Industry.xlsx,'' (2019), available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
Equations I-24A and I-24B, which calculate the weighted average
DREs for individual F-GHGs across process types, would rarely be used
if the EPA adopts the same default DREs for all process types as
discussed in section III.E.1.b of this preamble, because there will
rarely be any need to calculate weighted average DREs across process
types in that case. The sole exception may occur when a facility uses
one or more abatement systems with a certified DRE value that is
different from the default to calculate and report controlled
emissions. To accommodate this situation and to simplify equations I-
24A and I-24B, we are proposing to modify equations I-24A and I-24B to
calculate the average DRE for each input gas ``i'' and by-product gas
``k'' based on tool counts and the same weighting factors that would be
used in equations I-24C and I-24D. This would eliminate the requirement
to apportion gas consumption by process type when using the stack test
method, even for those facilities that use abatement systems with
different DREs for the same input gas ``i'' or by-product gas ``k''.
Requiring that all stacks be tested (if the stack test method is
used) would remove not only the need to apportion gas usage to tested
versus untested stacks, but also the requirement to perform a
preliminary calculation of the emissions from each stack system (we are
proposing to remove the requirements at 40 CFR 98.93(i)(1)). The EPA
expects that the data received would be more accurate due to requiring
testing of all stacks. The EPA also expects that the revision to
measure all stacks instead of apportioning gas usage between process
type and subtype and between tested and untested stacks would
streamline the implementation of the stack testing method at facilities
and increase the likelihood of this method being used instead of the
emission factor approach. Currently, to account
[[Page 36945]]
for emissions from untested stacks, facilities must calculate gas
consumption of each F-GHG used in tools that are vented from untested
stacks by apportioning gas between untested and tested stacks. When
abatement is used, facilities also currently need to apportion by
process type. Apportioning gas requires using a fab-specific
engineering model that must be based on a quantifiable metric, such as
wafer passes or wafer starts, or direct measurement of input gas
consumption and must be verified by demonstrating its precision and
accuracy as described in 40 CFR 98.94(c)(1). As the number of stacks at
each fab is expected to be small (e.g., one to two), the EPA expects
that measuring all stacks would be more accurate and less burdensome
than developing and verifying an apportioning model.
We also seek comment on whether stack testing should also be used
to estimate N2O emissions if stack testing is the
calculation method elected. Currently, the stack testing option in
subpart I is limited to estimating emissions from F-GHGs;
N2O emissions must be estimated using the default emission
factors in Table I-8. The use of the stack testing method for
N2O was not previously recommended by industry due to: (1)
the high monthly and yearly variability in measured N2O
emission factors estimated from stack testing for some fabs; and (2)
the observation that estimated N2O emission factors from
stack testing also often exceeded 1, indicating a second, unidentified,
source of N2O.\25\ No source for the additional
N2O formation or the high variability was identified. The
EPA requests comment on the extent to which the sources of
N2O formation from electronics manufacturing have been
identified. We are also requesting comment on the expected variability
of the estimated N2O emission factor from stack testing if
using the current or revised methods for estimating emissions using
stack testing and whether new data are available. If estimated
N2O emission factors are now expected to be consistent over
time, the use of N2O in stack testing could be re-evaluated
during a future rulemaking.
---------------------------------------------------------------------------
\25\ See Semiconductor Industry Association (SIA) Response to
EPA's Stack Test Question 1, March 7, 2012, and Technical Support
for Other Technical Issues Addressed in Revisions to Subpart I, U.S.
EPA, August 2012, both of which are available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
We are also proposing to replace equation I-19 with a set of
equations that will more accurately account for by-product emissions
when that by-product F-GHG is also an input gas. Specifically, the new
equations will more accurately account for emissions when emissions of
an F-GHG prior to entering any abatement system (i.e., pre-control
emissions) would approach or exceed the consumption of that F-GHG
during the stack testing period. Pre-control emissions of an F-GHG can
approach or exceed consumption of that F-GHG when the F-GHG is
generated as a by-product of other F-GHGs used in the fab. To ensure
that calculated emission factors reflect this physical reality, any
excess pre-control emissions of the F-GHG should be assumed to be
formed as a by-product. Currently, the paragraph containing equation I-
19, 40 CFR 98.93(i)(3)(iii), does not sufficiently account for such by-
product formation, potentially resulting in overestimated input gas
emission factors and underestimated by-product gas emission factors.
This potential inaccuracy arises because 40 CFR 98.93(i)(3)(iii),
in its assignment of portions of the emissions to either input gases or
by-products, does not currently account for the utilization
(dissociation) of the input gas or for any abatement of the input gas.
Instead, the provision compares the total measured emissions of the F-
GHG, which may have passed through abatement systems prior to
measurement, to the consumption (termed ``activity'' in equation I-19)
of that F-GHG during the stack testing period. If the measured
emissions equal or exceed consumption, the term for total emissions in
equation I-19, [sum]sEi,s, is equated to
consumption to calculate the input gas emission factor, and any
difference between the measured emissions of the F-GHG and the
consumption of the F-GHG is treated as by-product emissions and used to
calculate a by-product emission factor (BEF) in equation I-20. While
this approach avoids assigning a controlled emission factor greater
than 1.0 to the input gas, in cases where the measured emissions are
greater than consumption, the corresponding pre-control emission factor
is either equal to 1.0 (if the measured emissions are uncontrolled) or
greater than 1.0 (if the measured emissions are controlled). In the
first case, the pre-control emission factor fails to account for any
utilization of the input gas. In the second case, the pre-control
emission factor both fails to account for any utilization of the input
gas and attributes emissions to the input gas for which the input gas
cannot possibly be the source (because that would violate conservation
of mass).
To more accurately assign emissions of the gas to by-product or
input gas emissions, a better methodology is to compare the measured
emissions to the maximum expected controlled emissions of the input gas
during the stack testing period, rather than to the consumption during
that period. To make this change, we are proposing to remove equation
I-19 and replace that equation with equations I-19A, I-19B, and I-19C,
making corresponding changes to 40 CFR 98.93(i)(3)(iii). Equation I-19A
estimates the maximum expected controlled emissions for each F-GHG from
the fab during the stack testing period at a utilization rate (U) equal
to 0.2 (i.e., a 1-U or input gas emission factor of 0.8) and at the
levels of abatement and abatement system uptime observed during the
stack testing period. If the total emissions measured during the stack
testing period are less than the maximum expected controlled emissions
calculated using I-19A, then all emissions of gas i are attributed to
the consumption of gas ``i'' and equation I-19B is used to calculate
the input gas emission factor for gas ``i''. Equation I-19B is similar
to equation I-19 in the current rule, but with an updated process-
independent variable for the DRE. However, if the total measured
emissions are greater than the estimate of the maximum controlled
emissions, then the input gas emission factor is assumed to be equal to
the maximum controlled emission rate at an uptime equal to 1, as
calculated in equation I-19C. The remaining emissions (the difference
between the measured emissions and the value calculated in equation I-
19A) are used to calculate the BEF for that gas from other input gases
in equation I-20.
The revised equations improve upon the current equations because
they account both for any control of the emissions and for some
utilization of the input gas. The input gas emission factor (1-U) of
0.8 used in equations I-19A and I-19C is the same as the default 1-U
factor that would be assigned where a default is not available in
Tables I-3 and I-4, as discussed in III.E.2.b of this preamble. Using a
value of 0.8 as a maximum input gas emission factor (1-U) would be
consistent with the other proposed changes and is expected to increase
the accuracy of the stack testing method, as some utilization of the
input gas is expected. These changes to the stack testing equations
would improve the quality of the stack testing method by more
accurately assigning emissions to their source.
In addition to the substantive changes to equation I-19, the EPA is
proposing to clarify the definitions of the variables
[[Page 36946]]
dif and dkif, the average DREs for input gases
and by-product gases respectively, in equations I-19A, I-19B, I-19C,
and I-19D, in equations I-20 through I-22, in equations I-24A and B,
and in equation I-28 of subpart I. Currently, the definition for the
variable dif reads ``Fraction of fluorinated GHG input gas i
destroyed or removed in abatement systems connected to process tools in
fab f,'' which could be interpreted to reflect both the fraction of
emissions of gas i that is fed into abatement systems and the fraction
of gas i that is destroyed once gas i is fed into abatement systems.
However, dif (and dkif) are only intended to
reflect the fraction of gas i (or by-product gas k) that is destroyed
once gas i (or by-product gas k) is fed into abatement systems. To make
this clear, we are proposing to change the definition of dif
to read ``Fraction of fluorinated GHG input gas i destroyed or removed
when fed into abatement systems by process tools in fab f,'' and we are
proposing a parallel change to the definition of dkif.
b. Revisions To Clarify and Revise Calculation Methodologies and
Required Data Elements for Data Submitted in the Technology Assessment
Report
For the reasons described in section II.A.1 of this preamble, we
are proposing to require that three emission factor calculation
methods, specified in this section and described in the subpart I TSD
(available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424), be used when calculating utilization and by-product
emission rates submitted in technology assessment reports. These three
methods would be used to report the results of each emissions test.
Based on a comparison among the results of the three methods, we may
ultimately require use of a single method through a future rulemaking.
As stated in the preamble to the 2013 final rule that established
the requirement to submit technology assessment reports (78 FR 68175,
November 13, 2013), one of the EPA's goals in collecting emission
factor data through the reports is to better understand how emission
factors may be changing as a result of technological changes in the
semiconductor industry, and whether the changes to the emission factors
may justify further data collection to comprehensively update the
default emission factors in Tables I-3 and I-4. To meet this goal, the
emission factors submitted in the technology assessment reports should
be calculated the same way as the emission factors already in the EPA's
database were calculated; otherwise, differences attributable to
differences in calculation methods may amplify or obscure differences
attributable to technology changes. To date, the EPA has not initiated
a broad data collection to comprehensively update the default emission
factors, but the EPA is now proposing to use the emission factor data
submitted in the 2017 and 2020 technology assessment reports to make
minor updates to the default emission factors, and the EPA may continue
this practice in the future. This introduces a second goal for the
emission factors submitted in the technology assessment report, which
is that they be robust to ensure that the resulting updated default
emission factors are robust. To meet this goal, the reported emission
factors should be broadly applicable because they reflect physical
reality as much as possible and are not unduly affected by changing
proportions of input gases. In addition, the reported emission factors
should be consistently calculated across facilities and processes to
ensure that the resulting defaults are not biased by ``cherry-picking''
of methods to achieve a desired result for a given process or facility
(or set of processes or facilities). Requiring facilities to (1) use
specified methods to calculate emission factors and (2) use all three
methods for each test meets these goals to different extents and in
different ways.
Requiring facilities to use specified emission factor calculation
methods would ensure that the emission factors are robust insofar as
the calculation methods are designed to yield robust factors. It would
also help ensure that the emission factors are developed in a
reasonably, though not perfectly, consistent manner across processes
and facilities and over time, given that the proposed calculation
methods are similar but not identical. (As discussed in this section,
two of the proposed emission factor calculation methods are based
closely on the emission factor calculation methods used for the
emission factors already in the EPA's database.) The EPA has previously
received emission factors calculated via a variety of methods, as
described further in this section. This has sometimes made it difficult
to determine whether changes in calculated emission factors are due to
changes in technology or to changes in the emission factor calculation
method. In some cases, we have not been able to use submitted emission
factor data because it was found to be calculated using a method that
was significantly different from previous methods and that appeared
unlikely to represent actual gas behavior. (The lead authors of the
Electronics chapter of the 2019 Refinement declined to use this data
for similar reasons.) \26\ Specifying emission factor calculation
methods would at least partially address these problems.
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\26\ See Volume 3, Chapter 6. Electronics Industry Emissions to
the 2019 Refinement to the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, as cited above in this document.
---------------------------------------------------------------------------
Requiring facilities to submit three sets of emission factors for
each test would more fully address these problems by enabling us: (1)
to directly compare the new emission factor data to the emission factor
data that is already in the EPA's database and that was calculated
using the same method; and (2) to compare the results across the
available emission factor calculation methods and to identify any
systematic differences in the results of the different methods for each
gas and process type. By identifying and quantifying systematic
differences in the results of the different methods, we would be better
able to distinguish these differences from differences attributable to
technology changes. This would enable us to build a bridge between the
data sets resulting from the different methods, which would be useful
in the event that we ultimately required facilities to submit emission
factors using one method only, particularly if that method was not one
of the methods used historically. We would also be able to evaluate how
much the results of each method varied for each gas and process type;
high variability may indicate that the results of a method are being
affected by varying input gas proportions rather than differences in
gas behavior, as discussed further in this section. Ultimately, these
analyses would enable us to more accurately characterize emissions from
semiconductor manufacturing by selecting the most robust emission
factor data for updating the default emission factors in Tables I-3 and
I-4. Because we plan to incorporate the three methods into spreadsheets
that would calculate three sets of emission factors based on a single
set of entered data, we do not anticipate that requiring reporting of
the results of the three methods would significantly increase burden.
We are proposing the three emission factor calculation methods in 40
CFR 98.96(y)(2)(iv)(A) through (C).
Two of the proposed methods are closely based on the methods that
have been used historically to calculate emission factors for processes
that use multiple gases: ``all-input gas method''
[[Page 36947]]
and the ``dominant gas method''.\27\ \28\ Consequently, the emission
factors calculated using these methods are generally expected to be
comparable to the emission factors calculated and submitted to the EPA
in the past. The emission factors calculated using these methods are
also expected to be reasonably robust except under certain
circumstances discussed further in this section. To increase the
robustness of the emission factors calculated using these methods under
those circumstances, we are proposing to modify the methods to avoid
input gas emission factors greater than 0.8 for processes that use
multiple gases.
---------------------------------------------------------------------------
\27\ See section 2.0 of the document, Technical Support for
Modifications to the Fluorinated Greenhouse Gas Emission Estimation
Method Option for Semiconductor Facilities under Subpart I (2012),
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424).
\28\ Previously, the EPA had suggested that the all-input gas
method be used for etch emission factors (Ibid.), and most of the
etch data in the data set used to develop the current emission
factors used this method (see 78 FR 68185 and previously submitted
data sets Etch Process Equipment Emissions Characterization Data and
International SEMATECH Manufacturing Initiative Environmental Safety
and Health Technology Center, February 2012, and the document Draft
Emission Factors for Refined Semiconductor Manufacturing Process
Categories (2010), all available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424). However, some of this data was
calculated using the dominant gas method.
---------------------------------------------------------------------------
Historically, both the all-input gas and dominant gas methods have
calculated the input gas emission rate in the same way: all emissions
of each F-GHG that is an input gas have been attributed to the 1-U
factor for that gas (kg of input gas emitted/kg of input gas used);
that is, both methods imply that if an F-GHG is used as an input gas,
that F-GHG is not also formed as a by-product. However, the two methods
treat by-product F-GHGs that are not used as input gases differently.
The dominant gas convention assigns all emissions of F-GHG by-products
to the carbon-containing F-GHG input gas accounting for the largest
share by mass of the input gases (kg of by-product emitted/kg of
dominant gas used), while the all-input gas convention assigns
emissions of F-GHG by-products to all F-GHG input gases (kg of by-
product emitted/kg of all F-GHGs used). With a slight modification, the
all-input convention has also been used to assign emissions of F-GHG
by-products to only all carbon-containing F-GHG input gases, i.e., not
to SF6 or NF3 input gases (kg of by-product
emitted/kg of all F-GHGs used).
Due to the complex set of chemical reactions necessary to describe
plasma etching by multiple input gas processes, it is not generally
known what fractions of a by-product gas are produced by each input
gases, or what fractions of an emitted input gas consist of unreacted
residual gas versus newly formed by-products of other gases. Both
methods of assigning emission factors described above have historically
been based on the assumption that the emissions of each input gas (1-U)
are much larger than the emissions of the same gas as a by-product of
the other input gases (e.g., CF4 produced from
C2F6) and thus, the BEF can be approximated as
zero. However, as stated in section III.E.1.c of this preamble on
updates to the default emission factors, it has been well established
that most input gases produce CF4 and
C2F6 in significant quantities. Thus, in cases
where C2F6 or CF4 is an input gas (and
possibly for some additional cases), assigning all of the emissions of
C2F6 or CF4 to the
C2F6 or CF4 input gas, respectively,
may not be a good approximation and can lead to cases where the
reported emission factor is greater than 1, which violates conservation
of mass. This is most likely to happen when an input gas such as
CF4 makes up a relatively small share of the total input gas
mass and is also generated in significant quantities as a by-product by
the other input gases.
To address this issue, our proposed methods include a modification
to both of the historically recommended methods to avoid an input gas
emission factor greater than 0.8 when multiple gases are used, and we
are also proposing to introduce an additional calculation method. The
modified methods would attribute emissions of each F-GHG used as an
input gas to that input gas until the mass emitted equaled 80 percent
of the mass fed into the process, that is, until the 1-U factor equaled
0.8. The methods would then assign the remaining emissions of the F-GHG
either to the dominant input gas as a by-product (in the dominant gas
method) or to the other input gases as a by-product in proportion to
the quantity of each input gas used in the process (in the all-input
gas method). This approach avoids violating conservation of mass and
better reflects the expectation that at least a small portion of the
input gas will be utilized in the process. Nevertheless, because 0.8
represents an upper bound for input gas emission factors, even the
modified methods have the potential to significantly overestimate input
gas emission factors. To the extent that these factors are later
applied to processes where the input gas accounts for a larger share of
the total input gas mass (e.g., because they are used to calculate
default factors), they will overestimate emissions of the input gas.
A third convention, the reference emission factor method, is likely
to provide more robust, realistic results, although it represents a
somewhat larger change from the emission factor calculation conventions
historically used. The reference emission factor method begins with the
average input gas utilizations (1-U factors) and/or BEFs observed based
on single gas recipes. In single-gas recipes, all emissions of an input
gas clearly originate from its use as an input gas, and all emissions
of a by-product clearly originate from its generation as a by-product;
thus, the 1-U factor and BEFs based on single-gas recipes are not
affected by the uncertainties regarding the origins of the emissions
that can affect these factors for multi-gas recipes.
Since it is not known whether the 1-U factor or BEFs are more
likely to change in moving from single- to multiple-gas recipes, the
reference emission factor method calculates emissions using the 1-U and
the BEFs that are observed in single gas recipes and then adjusts both
factors based on the ratio between the emissions calculated based on
the factors and the emissions actually observed in the multi-gas
process. This approach uses all the information available on
utilization and by-product generation rates from single-gas recipes
while avoiding assumptions about which of these are changing in the
multi-gas recipe.
In summary, the chief advantage of the dominant gas method proposed
at 40 CFR 98.96(y)(2)(iv)(A) and the all-input gas method proposed at
40 CFR 98.96(y)(2)(iv)(B) is that they are the methods used previously
to calculate the emission factors that are already in the EPA's
database and that form the basis of the current subpart I default 1-U
and BEFs. Therefore, new emission factors calculated using these
methods are expected to be comparable \29\ to the emission factors
already in the EPA's database, facilitating efforts to identify changes
in emission factors that are attributable to technology changes. The
chief disadvantage of these two methods is that they can result in a
significantly overestimated 1-U value when the share of an input gas
such as CF4 declines.
[[Page 36948]]
This disadvantage is mitigated partly, but not completely, by capping
1-U values at 0.8. At the same time, however, capping 1-U values at 0.8
decreases the comparability of these methods with those previously used
to calculate and report emission factors. The EPA requests comment on
whether the gain in robustness achieved by capping 1-U values at 0.8
justifies the accompanying loss in comparability to previously
submitted data, particularly given that we are proposing to require
submission of results using both the historically used methods and the
new, likely more robust, reference emission factor method. The
reference emission factor method is being proposed at 40 CFR
98.96(y)(2)(iv)(C). The advantages and disadvantages of the three
methods are described further in the document Technical Support for
Modifications to the Fluorinated Greenhouse Gas Emission Estimation
Method Option for Semiconductor Facilities under Subpart I, cited above
in this section. The EPA also considered requiring use of one specific
method for the data submitted in future technology assessment reports.
This would allow all future reports to have comparable data. However,
if one of the historically used methods were specified, the resulting
emission factors might not be as robust as they would be if the
reference emission factor method were specified. On the other hand, if
the reference emission factor method were specified, the resulting
emission factors would not be fully consistent with previously
submitted emission factors, and this inconsistency would be difficult
to address without having seen the results of the different methods
side-by-side at least once. Another option would be to let the reporter
choose one of three methods in 40 CFR 98.96(y)(2)(iv)(A) through (C)
for subsequent reports. This option would result in a loss of
comparability between tests. The EPA is requesting comment on these
alternatives.
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\29\ As discussed further in the document Technical Support for
Modifications to the Fluorinated Greenhouse Gas Emission Estimation
Method Option for Semiconductor Facilities under Subpart I, cited
above in this section, trends in gas usage, such as the use of more
and more individual input gases, may introduce apparent, but not
real, trends in the 1-U values calculated using these methods.
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We request comment on the methods proposed at 40 CFR
98.96(y)(2)(iv)(A) through (C) for calculating emission factors for
multi-gas recipes, particularly concerning their reliability as
indicators of actual emission rates and emission rate trends. In
addition, the EPA requests comment on the use of 0.8 as the maximum 1-U
value in the modified dominant-gas and all-input gas methods.
We also request comment on the reference emission factor method
proposed at 40 CFR 98.96(y)(2)(iv)(C). While this method differs from
the historically used methods, the differences are not expected to
become important except where CF4 or
C2F6 make up a small share of the input gas mass,
that is, where the historically used methods are known to yield
inaccurate results. The EPA believes that the increase in accuracy
gained through the new method justifies some loss of time series
consistency (i.e., comparability between newly submitted emission
factor data and previously submitted emission factor data). Moreover,
because we are proposing to require reporting of the results of each
test using all three calculation methods, we can compensate for the
loss of time series consistency between the historically used methods
and the reference emission factor method by: (1) comparing the emission
factors already in the EPA's database to the versions of the new
emission factors calculated using the historically used methods (i.e.,
the all-input gas and dominant gas methods); and (2) analyzing
systematic differences that occur between the results of the
historically used methods and of the reference emission factor method
so that these can be considered in future comparisons between new and
existing data. We also request comment on whether BEFs based on multi-
gas recipes should be included in the reference BEFs for the reference
emission factor method. The benefit of including BEFs based on multi-
gas recipes in the reference BEFs is that this would increase the
number of data points used as a basis for those BEFs, in some cases
providing reference BEFs where none are available from the single gas
data set (due to a lack of data). The drawback of including BEFs based
on multi-gas recipes is that these BEFs are subject to some
uncertainty. BEFs measured for multi-gas recipes where the by-product
F-GHG is not also used as an input gas are less uncertain than BEFs
where the by-product F-GHG is also an input gas. However, uncertainty
remains regarding which of the multiple input gases are primarily
responsible for the formation of that by-product and whether all input
gases contribute to the formation of each by-product. For more
information on the advantages and disadvantages of using only single-
gas measurements or all measurement to determine reference emission
factors see the subpart I TSD, cited above in this section.
We also seek comment on whether there are alternative methods for
calculating utilization and by-product formation rates that the EPA
should consider in the future. To enable us to evaluate any suggested
methods, we request that commenters suggesting an alternative method
also provide information on the rationale for using the alternative
method instead of one of the methods described above and a comparison
between a representative group of emission factors (both 1-U and BEFs)
calculated using the alternative method and a group of emission factors
based on the same data but calculated using the all-input gas method,
the dominant gas method, and the reference emission factor method. The
EPA may evaluate, at a future date, such alternative methods based, for
example, on the likely accuracy of the alternative calculation method
and its consistency with previously used calculation methods.\30\
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\30\ See document Technical Support for Proposed Revisions to
Subpart I (2021), available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424.
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We are also proposing that where reporters provide any data on
utilization and by-product formation rates in the technology assessment
report, they must also specify the method used to calculate the
reported utilization and by-product formation rates and assign and
provide an identifying record number for each data set. This
information allows the EPA to better understand the data being
submitted. For example, this information helps the EPA identify all the
gases used in a multi-gas test and understand the influence of the
calculation method and gas mixtures on the resulting emission factors.
This detailed understanding may help us to develop new or revised
emission factors that are representative of the industry. Without
collecting these data, the EPA may not be able to effectively evaluate
the influence of different emission factor calculation methods or gas
combinations on the resulting emission factors.
We are also proposing at 40 CFR 98.96(y)(2)(iv) that for any
destruction or removal efficiency (DRE) data submitted, the report must
include whether the abatement system used for the measurement is
specifically designed to abate the gas measured under the operating
condition used for the measurement. This information will help the EPA
understand whether the submitted data should be considered to be a
result for a certified abatement system for the gas being measured. The
efficacy of abatement systems generally depends on both whether it is
designed to abate the F-GHG and whether it is installed, operated, and
maintained according to the manufacturer's specifications. Abatement
systems are known to have reduced efficacy when the individual process
gas and total gas flow rates (including any added purge
[[Page 36949]]
gases) as specified by the abatement system supplier are exceeded.
c. Updates to Default Emission Factors and Destruction or Removal
Efficiencies To Improve the Accuracy of Emissions Estimates
The EPA is proposing to update the default emission factors and
destruction or removal efficiencies (DREs) in subpart I based on new
data submitted as part of the 2017 technology assessment report
(submitted with the RY2016 annual report) and the 2020 technology
assessment report (submitted with the RY2019 annual report).\31\ First,
we are proposing to update the utilization rates and BEFs for F-GHGs
used in semiconductor manufacturing in Tables I-3, I-4, I-11 and I-12
to reflect new data received in the 2017 and 2020 technology assessment
reports, to correct errors identified in the data set on which the
current default emission factors are based, and to remove BEFs where
both the emission factor and the GWP of the emitted by-product are very
low. Second, we are also proposing to update and expand the default
emission factors for N2O used in all electronics
manufacturing in Table I-8 based on both new data from the 2017 and
2020 technology assessment reports and new emission factors available
in the 2019 Refinement. Third, we are proposing at 40 CFR 98.93(a)(6)
to revise the utilization rate and BEF values assigned to gas/process
combinations where no default utilization rate is available. Finally,
we are proposing to update the default DREs in Table I-16 to reflect
the incorporation of new data from the 2017 and 2020 technology
assessment reports and a new approach to abatement system
certification. These updates are expected to increase the accuracy of
the emissions reported by facilities under subpart I.
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\31\ Available in ``UPDATED Appendix A Process Emissions
Characterization Data,'' Semiconductor Industry Association, April
2018, and ``2020 Subpart I Consolidated Triennial Report, Appendices
A-B,'' Semiconductor Industry Association, March 2020, available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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The proposed emission factors for Tables I-3, I-4, I-11, and I-12
were calculated from measured data submitted by U.S. semiconductor
manufacturers as part of the 2020 technology assessment report, 2017
technology assessment report, and data collected in previous years.\32\
The total data set contains 4,358 input gas and BEFs across all
commonly used gas and process type combinations, with 1,506 of these
data points newly available via the 2020 and 2017 triennial technology
assessment report. All the data submitted via the 2020 and 2017
triennial technology assessment report were applicable to the 300-mm
wafer size. All data sets were reviewed for errors, including, but not
limited to, transcription errors and violations of the fluorine
balance. Calculated emission factors (1-U or BEFs) greater than 1.00 (a
total of 18 data points) were excluded from the calculation of the
proposed default emission factors (EFs). Input gas and by-product gas
emission factors were also analyzed for each test to see whether the
fluorine balance was violated. This resulted in the exclusion of 40
data points from the calculation of the proposed default emission
factors. There were also a small number of transcription or other
errors, including duplicate rows of data, that were corrected or
excluded prior to calculating the proposed emission factors.
Transcription and other errors resulted in the exclusion of 33 data
points. A single reported by-product value for SF6 was also
excluded from the calculation, as there was no source of sulfur. Four
emission factors for NF3 in remote plasma cleaning (RPC)
processes that were previously excluded \33\ were re-included in the
data set, as discussed in the subpart I TSD, available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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\32\ The data submitted in previous years can be found in
Semiconductor Industry Association; Etch Process Equipment Emissions
Characterization Data, International SEMATECH Manufacturing
Initiative Environmental Safety and Health Technology Center,
February 2012, and Draft Emission Factors for Refined Semiconductor
Manufacturing Process Categories, Office of Air and Radiation, May
2010, each of which is available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424.
\33\ See Technical Support Document for Process Emissions from
Electronics Manufacture (e.g., Micro-Electro-Mechanical Systems,
Liquid Crystal Displays, Photovoltaics, and Semiconductors):
Proposed Rule for Mandatory Reporting of Greenhouse Gases, Revised,
November 2010, available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2019-0424.
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Submitted data were also reviewed for methodological consistency
with previously submitted data. As discussed earlier in III.E.1.b of
the preamble, data submitted to the EPA prior to 2017 used either the
dominant gas or all-input gas convention. However, many of the data
points for etching submitted as part of the 2020 and 2017 technology
assessment report used an alternative convention that had not been
previously used. This new ``multi-gas'' convention differed in how it
assigned emissions of input gases. Instead of assigning measured
emissions of an input gas entirely to the input gas, emissions of an
input gas were assigned to all input F-GHGs used in the process by
dividing the measured mass emitted of a specific input gas by the total
mass of all input F-GHGs and assigning this emission factor to each
input F-GHG as either the 1-U factor or the by-product factor, i.e.,
all input F-GHGs were considered to equally contribute to the emissions
of each input gas. This method was inconsistent with the methods of the
previous data set, and the alternative method often resulted in large
increases to the reported BEFs and concurrently large decreases to the
reported 1-U. This change appeared to be largely a result of the change
in methodology; however, it was not possible, based on the data
received, to fully assess the effect of the new methodology as the data
were not directly comparable to previously submitted data. The data
points that were affected by the change in convention were excluded
from the calculation of the proposed default EFs, resulting in the
exclusion of 338 data points. This left a total of 3,951 data points in
the combined data set that were included in the calculations of the
proposed default emission factors in Tables I-3 and I-4.
The proposed default EFs for Tables I-3 and I-4 were calculated
using a simple arithmetic mean of all EF data that used either the all-
input gas or the dominant gas convention. The technology assessment
reports reported no major changes to semiconductor production
technology, and the differences between the average emission rates
calculated based on the new and previously submitted data,
respectively, are generally small (i.e., less than 20
percent for most commonly used input gases). Therefore, it is assumed
in most cases that the proposed default emission factors for F-GHGs
reflect increased and/or improved data rather than changes in actual
emission or utilization rates. This means that for each wafer size
(<200 mm and 300 mm), the proposed emission factors are generally
likely to represent emission rates over all the years of the GHGRP.
However, for a few gas and process type combinations for the 300-mm
wafer size, the differences between the averages calculated based on
the new and previously submitted data are more significant and could
have an appreciable impact on the overall calculated CO2e
emissions. More information on the differences between the data
contained in the two technology assessment reports received to-date and
the previously submitted data is available in the subpart I TSD,
[[Page 36950]]
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-
2019-0424. In light of these findings, we request comment on whether
the new data reflect recent technology changes or simply better
represent technologies that have been in use over the long term (i.e.,
at least since 2011, the first year of reporting under the GHGRP). This
is important for understanding the time period to which the new data
for these four factors are applicable.
We are also proposing to update the calculation methodology for
MEMs and PV manufacturing to allow use of 40 CFR 98.3(a)(1), the
current methodology for semiconductor manufacturing, in lieu of using
40 CFR 98.3(a)(2) for manufacture of MEMs and PV using semiconductor
tools and processes. This would have the effect of applying the default
emission factors in Tables I-3 and I-4 to these processes. In the 2019
Refinement, use of semiconductor default emission factors for MEMs
manufacturing is recommended when using semiconductor tools to
manufacture MEMs. Similarly, we are also proposing the use of
semiconductor emission factors for PV manufacturing that uses
semiconductor manufacturing tools. It is expected that the use of
semiconductor emission factors will result in more accurate emissions
estimates when semiconductor manufacturing tools and processes are
used.
The current Table I-8 does not distinguish N2O emission
factors either by the type of electronic device manufactured
(semiconductor versus LCD) or by wafer size. Due to the increased
availability of N2O emission factor data, we are proposing
to update Table I-8 to include distinct utilization rates for
N2O for semiconductor manufacturing and LCD manufacturing
and, for semiconductor manufacturing, utilization rates by wafer size
(<200 mm and 300 mm) and by process type.\34\ The proposed emission
factor for N2O used in CVD thin film deposition for LCD
manufacturing can be found in the 2019 Refinement.\35\ Currently there
is no LCD manufacturing in the United States and thus, no U.S. data is
available for LCD manufacturing.
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\34\ More information regarding the development of the proposed
default emission factors can be found in the workbook titled, ``Data
sets Supporting Revised Emission Factors.xlsx,'' (U.S. EPA, April
2020) and in the subpart I TSD, available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
\35\ See Volume 3, Chapter 6. Electronics Industry Emissions to
the 2019 Refinement to the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, as cited above in this document.
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We are also proposing to remove BEFs from Tables I-3 and I-4 where
there is a combination of both a low BEF and a low GWP, resulting in
very low reported emissions per metric ton of input gas used (<0.03
mtCO2e and less than 0.0002 percent of emissions (in
CO2e) per metric ton of input gas consumed). This would
result in: (1) removing the BEFs for C4F6 and
C5F8 for all input gases used in wafer cleaning
or plasma etching processes due to the combination of a low GWP (0.003
and 1.97, respectively) and low BEFs (less than 0.009); and (2) not
adding BEFs for COF2 and C2F4 for any
input gas/process combination from the new data received in the 2020 or
2017 technology assessment reports because these BEFs are less than 0.2
and COF2 and C2F4 have low GWPs (0.14
and 0.004, respectively). COF2 does not have a chemical
specific GWP in Table A-1 (it is currently assigned a default GWP of
2000 as an ``Other Fluorinated GHG''), but the 2018 WMO Scientific
Assessment listed the 100-year GWP of COF2 as ``<1.'' We
calculated a precise GWP for COF2 of 0.14 using the
atmospheric lifetime and radiative efficiency provided in the 2018 WMO
Scientific Assessment. (The method we used to calculate the GWP of
COF2 was the method we used to calculate precise GWPs for
low-GWP compounds in the most recent update to GHGRP GWPs (79 FR 73750,
December 11, 2014)). Currently, Table I-3 lists the BEF for
C4F6 from all input gases as `NA'. Similarly,
Table I-4 currently lists the BEF for C5F8 from
all input gases as `NA'. Thus, for these two cases, there will be no
change in reported emissions. Data reported to the GHGRP in 2013 \36\
indicates that, in total, for all semiconductor manufacturers reporting
to the GHGRP in 2013, by-product emissions of
C5F8 and C4F6 totaled 0.27
and 0.0004 mtCO2e, respectively. Similarly, it is estimated
that based on 2013 gas consumption COF2 and
C2F4 by-product emissions for the semiconductor
fabs reporting to the GHGRP in 2013 would have been 0.43
mtCO2e and 0.005 mtCO2e, respectively, if
COF2 and C2F4 emission factors were
adopted. For the largest fabs, generation of all by-products listed
above whose emission factors are being proposed for removal or
exclusion from Tables I-3 and I-4 would result in less than 0.6
mtCO2e in combined emissions per fab and significantly less
for smaller fabs. We are also proposing to modify the applicability of
carbon-containing BEFs to chamber cleaning process subtypes where
neither the input gas(es) nor the films being processed by the chamber
contain carbon. In the emission factor tables in subpart I (e.g., Table
I-3 and I-4), there are cases where a perfluorocarbon BEF is provided
even when the input gas i does not contain carbon (e.g.,
NF3). However, when none of the input gases contain carbon
(e.g., NF3 or SF6), and when the chamber being
cleaned does not process films that contain carbon, then neither
CF4 nor other carbon-containing gases are expected to be
formed during the process.\37\ Thus, we are proposing that in cases
where neither the input gas nor the films being processed in the tool
contain carbon, the BEF for the carbon-containing by-products be set to
zero (refer to variable ``Bkij'' in proposed equation I-8B).
We are proposing to apply this provision at the process subtype level;
a BEF of zero would only be used for a combination of input gas and
chamber cleaning process subtype (e.g., NF3 in RPC) if no
carbon-containing materials were removed using that combination of
input gas and chamber cleaning process subtype during the year and no
carbon-containing input gases were used on those tools. Otherwise, the
default BEF would be used for that combination of input gas and chamber
cleaning process subtype for all of that gas consumed for that subtype
in the fab for the year. An alternative approach would be to implement
this change at the individual process or tool level, tracking gas
consumption used in processes and tools that deposit films that contain
carbon. This would lead to a more precise estimate of carbon-containing
by-product emissions but may require
[[Page 36951]]
greater apportioning than is otherwise required by the rule. We request
comment on this alternative approach. Whether this revision was
implemented at the process subtype or process level, it would improve
the accuracy of the emissions estimate compared to the current rule by
differentiating between process subtypes (or processes) where there is
a source of carbon from which carbon-containing by-products may be
generated and process subtypes (or processes) where there is no source
of carbon from which carbon-containing by-products may be generated.
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\36\ GHGRP data from RY2013 was used for this analysis as it is
the last year for which it is was relatively simple to estimate gas
consumption due to revisions to the default emission factors applied
in 2014 and later. For more information on how gas consumption was
estimated, see U.S. EPA. Inventory of Greenhouse Gas Emissions and
Sinks:1990-2017 (2019). https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2017.
\37\ Chamber cleaning processes, which typically use only one
input gas, are not expected to generate carbon-containing byproducts
from that input gas unless either the input gas or the film being
removed contains carbon. The situation with etching and wafer
cleaning processes, where multiple input gases are often used, is
more complex. This is because input gases that do not contain carbon
can still contribute fluorine to carbon-containing F-GHG by-products
that obtain their carbon from other input gases, particularly if
relatively fluorine-rich and carbon-poor by-products such as
CF4 predominate. The data set supporting the default
emission factors proposed in this action includes by-product
emission factors that have sometimes been calculated assuming that
carbon-containing by-products are attributable to all input gases
(including those lacking carbon) and that have other times been
calculated assuming that carbon-containing by-products are only
attributable to input gases that contain carbon.
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In addition, we are proposing to update the default emission
factors for semiconductor manufacturing for use with the stack test
method (Tables I-11 and I-12). These tables will continue to be needed
to calculate emissions from consumption of each intermittent low-use F-
GHG as defined in 40 CFR 98.98. The proposed default emission factors
for Tables I-11 and I-12 were developed using the same data used to
calculate revised emissions factors for Tables I-3 and I-4, as
discussed above. To calculate the proposed default emission factors for
Tables I-11 and I-12, which are process-independent, gas consumption by
process type and wafer size was first estimated from emissions data
reported under subpart I for RY2013. Gas consumption by process type
was then used to weight the process-dependent emission factors from
Tables I-3 and I-4 to arrive at the proposed default emission factors
for Tables I-11 and I-12, respectively. Gas consumption by process type
was used as a weighting factor to arrive at process-independent
emission factors in order to have default emission factors that
represent the average emission factor over total gas consumption by the
industry for each wafer size.\38\ Although the proposed emission
factors proposed in this rulemaking differ slightly from the 2019
Refinement due to the inclusion of newly available data, the
methodology for developing Tables I-11 and I-12 are the same as those
used to develop the Tier 2b tables in the 2019 Refinement. For more
information on the EPA's method for estimating gas consumption from
emission data reported under subpart I for RY2013, which was used in
the 2019 Refinement, see the Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2017.\39\ The workbook ``Data Sets Supporting Revised
Emission Factors'' also shows the calculations for deriving the
emissions factors in Tables I-11 and I-12 from Tables I-3 and I-4
(available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424).
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\38\ For more information on the development of the proposed
emission factors for Tables I-11 and I-12, see the explanation for
the equivalent Tier 2b tables in the subpart I TSD in the docket for
this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424).
\39\ U.S. EPA 2019. Available at https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2017.
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We are requesting comment on three options regarding default
emission factors for MEMS and PV manufacturing. One option is to allow
MEMS and/or PV manufacturers to use either the current default emission
factors for those sub-sectors in Tables I-5 (MEMS) and I-7 (PV) or the
default emission factors for semiconductor manufacturing in Tables I-3
and I-4, as applicable. The second option is to remove Tables I-5 and
I-7 from subpart I and to require MEMS and/or PV manufacturers to use
the default emission factors in Tables I-3 and I-4, as applicable. The
third option is to continue to require MEMS and PV manufacturers to use
the default factors in Tables I-5 and I-7, respectively. Information
gathered during the development of the 2019 Refinement and through the
GHGRP indicates that the emission factors for semiconductor
manufacturing in Tables I-3 and I-4, as applicable, are often, and
perhaps always, applicable to MEMS and PV manufacturing. (In the 2019
Refinement, semiconductor default emission factors are applied to MEMS
manufacturing that is ``carried out using tools and processes similar
to those used to manufacture semiconductors.'') However, we request
comment on the extent to which semiconductor manufacturing default
emission factors are applicable to MEMS and PV manufacturing. We also
request comment on whether the distinction between different wafer
sizes that separates Table I-3 from Table I-4 is applicable to MEMS
and/or PV manufacturing.
We are also proposing to revise the input gas and BEF values
assigned to gas/process combinations where no default input gas
emission factor is available (due to a lack of data) in 40 CFR
98.93(a)(6). Currently, if no default input gas emission factor is
available for a particular gas/process combination, reporters must use
a general default value of one for the input gas emission factor (i.e.,
a utilization rate of zero) and a general default value of zero for the
BEFs. This assumes that emissions equal consumption, i.e., all gas used
in a process is emitted, without any utilization or conversion into
other gases. However, in the majority of cases where emission factor
data are available, both CF4 and C2F6
are emitted as by-products, and both CF4 and
C2F6 are long-lived GHGs with very high GWPs (see
Table A-1). Where the input gas has a GWP similar to those of PFCs,
accounting for the generation of CF4 and
C2F6 by-products is not expected to significantly
change the GWP-weighted emissions calculated for the process compared
to the current method, but where the input gas has a GWP significantly
lower than those of PFCs, accounting for the generation of the by-
products would considerably improve the estimate of GWP-weighted
emissions compared to the current method. In both cases, accounting for
the likely emissions of CF4 and C2F6
would also lead to a better estimate of each species emitted. Thus, we
propose to revise the general defaults where no default input gas
emission factor is available to account for the likely partial
conversion of the input gas into CF4 and
C2F6. Specifically, for a gas/process combination
where no default input gas emission factor is available in Tables I-3,
I-4, I-5, I-6, and I-7, we are proposing at 40 CFR 98.93(a)(6) that
reporters would use an input gas emission factor (1-U) equal to 0.8
(i.e., a default utilization rate or U equal to 0.2) with BEFs of 0.15
for CF4 and 0.05 for C2F6. It is
assumed here in cases where data do not exist, that the input gas is
partially converted into CF4 and C2F6
during the process and the remainder is emitted. The default input gas
emission factor is conservatively based on the least efficient gas in
Table I-4 for etch processes (C2F6 in the revised
Table I-4). The remainder of the input gas is assigned to
CF4 and C2F6. Due to a generally
higher CF4 BEF for most input gas/process combinations, the
majority (75 percent) of the remaining mass is assigned to
CF4.
Additionally, we are proposing to update the default DREs in Table
I-16 to reflect the incorporation of new data from the 2017 and 2020
technology assessment reports and a new approach to abatement system
certification. Currently, Table I-16 to subpart I lists default DREs by
gas and process type. Where data were unavailable for some gas and
chamber cleaning process combinations, DRE values were set to a
conservative value of 60 percent in the current tables.\40\ Commenters
have
[[Page 36952]]
previously noted that where exceptionally conservative DREs exist,
there is a large incentive to invest in measuring site-specific DREs.
Based on the measured data received by the EPA, the EPA is proposing to
assign chemical-specific DREs to all commonly used F-GHGs for the
semiconductor manufacturing sub-sector without distinguishing between
process types.\41\
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\40\ For more information, see ``Technical Support for
Accounting for Destruction or Removal Efficiency for Electronics
Manufacturing Facilities under subpart I,'' (August 2012) prepared
for the Final Amendments and Confidentiality Determination for
Electronics Manufacturing Final Rule (78 FR 68162, November 13,
2013), available in the docket for this rulemaking, Docket Id. No.
EPA-HQ-OAR-2019-0424.
\41\ See data sets ``UPDATED-04-02-2018-Triennial Report Data
for EPA,'' ``Attachment B. New and Revised DRE Test Used in SIA
Analysis of Alternative Default DREs'' from Comments of the SIA on
the Greenhouse Gas Reporting Program: Proposed Amendments and
Confidentiality Determinations for Subpart I (Docket Id. No EPA-HQ-
OAR-2011-0028-0095), and ``Etch DRE Testing With Flow Data, March 6,
2012,'' [2020 Triennial Data set]. All are available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
We are proposing to revise the default DREs in Table I-16 by
incorporating new data received via the 2017 and 2020 technology
assessment reports. The proposed DREs were calculated using a simple
arithmetic mean of all DRE data by gas. The DRE data sets submitted to
the EPA by the U.S. electronics manufacturing industry, including both
data received via the technology assessment reports and previously
submitted data, contains 1,353 data points for DREs of F-GHGs (for a
discussion on DREs for N2O, see the subpart I TSD, available
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-
0424). Of these, 58 of the data points corresponded to gases that are
not known to be input gases or significant by-products
(C2F4 and COF2, see previous
discussion on emission factors excluded from Tables I-3 and I-4). Thus,
we are not proposing default DREs in Table I-16 for these gases. Data
points were not included in the calculations of the proposed DREs if
the data points were reported as corresponding to emissions control
systems that were not certified to abate that particular gas.
Additional data points were excluded from the calculations of the
proposed DREs if an accurate DRE could not be measured due to detection
limits. Negative DREs were also excluded from the calculation for all
F-GHGs. All but two of the negative DREs submitted for F-GHGs were on
emissions control devices that were not designed to abate that
particular gas. For the two cases where the system was designed to
abate the gas, the testers noted either low gas inlet or inherent noise
in the measurement (e.g., due to low inlet). For the DREs from systems
recorded as not designed or certified to abate the input gas, the
negative DREs were reported only for CF4 and
COF2. Results from literature \42\ indicate that
CF4 can be formed within some emission control systems that
use hydrocarbon fuels by reaction between the fuel and fluorinated
species (e.g., F2) emitted from a NF3 remote
plasma chamber clean. All but one of the negative CF4 DREs
are from remote plasma chamber cleaning processes. However, since not
all abatement systems form CF4, these data points were
excluded from this analysis and this formation of CF4 is
accounted for separately in the proposed rule. Data points were also
excluded from the calculation if the gas being measured was noted as
being less than two percent of the total inlet fluoride to the
abatement system during testing, as the error in measuring DREs for
such low inlet concentrations may have biased the DREs low. It is also
known in the industry that when extremely low concentrations (e.g., 100
ppm) of F-GHGs in the abatement system are present, the system is less
efficient at destroying the F-GHG. Including these DREs in an
unweighted average would have a disproportionate effect on the
estimated emissions. Lastly, additional data points were excluded if
the abatement system required maintenance or repair (e.g., due to
fouling of the system due to poor water quality), or the abatement
system was operated in a manner inconsistent with the manufacturer's
recommendations (e.g., using clean dry air (CDA) instead of
O2 as the oxidant, as is recommended by the manufacturer).
The data sets include data for most gas-process combinations. The EPA
also considered using the DREs published in the 2019 Refinement.\43\
However, some of the data included in the 2019 Refinement are not
available to the EPA due to confidentiality concerns. Thus, the EPA was
only able to determine how this subset differed on average to the EPA
data sets. The confidential data set had higher average DREs for most
F-GHGs. This may be due to fact that this subset contained DREs as
measured by abatement system manufacturers and may not be
representative of actual fab conditions. The EPA has also received
additional data via the 2020 technology assessment report that was not
available during the development of the 2019 Refinement. The most
recent data set received from industry via the 2020 technology
assessment report included a significant number of DRE values that were
significant outliers. Many of these outliers were excluded due to the
reasons discussed above. The EPA considered excluding additional data
points from the DRE calculations for Table I-16 but did not have enough
information to determine whether the data points were representative of
fab operating conditions, due to abnormal conditions, or due to
operating the abatement system outside of manufacturer specifications.
The EPA is requesting comment on the conditions under which data points
were measured and whether any correspond to conditions that were
atypical or outside of the manufacturer's recommendation for operation
of the abatement system. The DREs in the proposed rule include data
from the 2020 and 2017 technology assessment reports and earlier data
sets. As discussed above, all DRE data points from the technology
assessment reports from abatement systems designed to abate the F-GHG
input gas were included in the calculations of the proposed default
DREs except in cases where: (1) the DRE was negative; (2) there were
detection limit issues; (3) the inlet gas flow of the F-GHG measured
was less than 2 percent of the inlet gas; (4) the abatement system
required maintenance or repair; or (5) the abatement system was
operated in manner inconsistent with the manufacturer's specifications.
The subpart I TSD, available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2019-0424, describes the full data set and the
default DREs considered, including the option of excluding significant
outliers. Where data for gas-process combinations still do not exist
(or there were less than 5 data points), there are sufficient data
across the various gas/process combinations to assign DREs based on
analogy with gases with similar chemical structures. The revised Table
I-16 also includes proposed DREs for C2HF5,
C5F8, and C4F8O based on
their similarity to CHF3 (for C2HF5
and C5F8) and c-C4F8 (for
C4F8O). This results in
C2HF5 and C5F8 being
assigned a default DRE of 97 percent. Based on its similarity to c-
C4F8, C4F8O is assigned a
default DRE of 93 percent. The EPA is proposing to base the DRE for
C3F8 on the DREs for a chemically similar F-GHG
for which the EPA does have data.
[[Page 36953]]
C3F8 is expected to be no more difficult to abate
than C2F6. Thus, the EPA is proposing to apply
the DRE value for C2F6 (98 percent) to
C3F8. A value of 98 is slightly higher than the
DRE for C3F8 in the current rule (97
percent).44 45
---------------------------------------------------------------------------
\42\ S.N. Li, et al. ``FTIR spectrometers measure scrubber
abatement efficiencies,'' Solid State Technology, Vol. 45. (2002);
Gray, Fraser, and Afroza Banu, ``Influence of CH4-
F2 mixing on CF4 by-product formation in the
combustive abatement of F2,'' Research Disclosure, Sept.
2018, both available in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2019-0424.
\43\ See Volume 3, Chapter 6. Electronics Industry Emissions to
the 2019 Refinement to the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, as cited above in this document.
\44\ The 98-percent DRE for C3F8 in the
current rule was assigned by analogy with
C2F6, which also has an assigned DRE of 97
percent in the current rule (78 FR 68192, November 13, 2013).
\45\ More information on the EPA's analysis of the DRE data can
be found in the subpart I TSD and supporting documents (``Combined
DRE data sets.xlsx'') in the docket for this rulemaking (Docket Id.
No. EPA-HQ-OAR-2019-0424).
---------------------------------------------------------------------------
Since the data does not show statistically significant differences
between process types,\46\ we are proposing to remove the distinction
by process type from Table I-16. In addition, we are proposing to
equate the default DRE for each F-GHG to the straight average of the
measured DREs for that F-GHG rather than setting the default DRE
slightly below the average. The DREs currently in Table I-16 were
developed using analysis of variance (ANOVA), which took into account
the likely variations in abatement device performance across fabs and
within a single fab (see the memorandum, Final Technical
Documentation--Revision of Default Utilization Rates and By-Product
Formation Rates; Revision of Default Destruction and Removal
Efficiencies for Semiconductor Facilities under subpart I; and Revision
of Maximum Field Detection Limits for the Stack Test Method (Alexis
McKittrick, U.S. EPA, August 16, 2013), which was used in the
development of the 2013 Final Rule (78 FR 68182, November 13, 2013) and
is available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424). A conservative approach was used because the DRE
performance of abatement equipment can vary depending on the specific
design of each manufacturer, which is often proprietary, and the actual
conditions in the fab. However, here, we are proposing a more refined
method for estimating controlled emissions that would still account for
variability across manufacturers.
---------------------------------------------------------------------------
\46\ Id.
---------------------------------------------------------------------------
To account for the variations in device performance, we are
proposing to modify the conditions under which the default DRE can be
claimed. Currently, in 40 CFR 98.94(f), in order to claim the defaults
provided in Table I-16, abatement equipment must be certified as
specifically designed for F-GHG or N2O abatement, and the
abatement system must be certified as being properly installed,
operated, and maintained according to the site maintenance plan for
abatement systems. Site maintenance plans must also be based on the
manufacturer's recommendations and specifications. The EPA is proposing
to clarify the definition of operational mode in 40 CFR 98.98 to
specify that operational mode means that the system is operated within
the range of parameters as specified in the DRE certification
documentation. Thus, the abatement system should only be considered
operational and the default or certified lower DRE claimed when the
system is operated within the range of parameters for which the system
is certified to meet or exceed the claimed DRE. The specified
parameters must include a range of total F-GHG or N2O flows
and total gas flows (with N2 dilution accounted for) through
the emissions control systems. For systems operated outside the range
of parameters specified in the documentation supporting the DRE
certification (e.g., with total flows exceeding the original equipment
manufacturer (OEM) specifications), a site-specific DRE could be
measured and claimed. The system could then be considered operational
within the range of parameters used to develop a site-specific DRE. We
are also proposing to modify the conditions in 40 CFR 98.94(f) under
which the default DRE may be claimed to require that the reporter, in
order to claim the default value for that abatement system and gas,
must: (1) certify that the abatement device is able to achieve a value
equal to or greater than the default DRE value under the worst-case
flow conditions during which the facility is claiming that the system
is operational; and (2) provide supporting documentation. Worst-case
flow conditions would be defined as the highest total F-GHG or
N2O flows through each model of emissions control systems
(gas by gas and process type by process type across the facility) and
the highest total flow scenarios (with N2 dilution accounted
for) across the facility during which the emission control system is
claimed to be operational. The certification would be based on testing
of the abatement system model by the abatement system manufacturer
using a scientifically sound, industry-accepted measurement methodology
that accounts for dilution through the abatement system, such as the
Protocol for Measuring Destruction or Removal Efficiency (DRE) of
Fluorinated Greenhouse Gas Abatement Equipment in Electronics
Manufacturing (March 2010) (EPA 430-R-10-003, hereinafter ``EPA DRE
Protocol,'' available in the docket for this rulemaking, Docket Id. No.
EPA-HQ-OAR-2019-0424). If the equipment is certified to abate the F-GHG
or N2O but at a value lower than the default DRE, facilities
would not be able to claim the default; however, facilities would be
allowed to claim the lower manufacturer verified value. Site-specific
measurements by the electronics manufacturer would still be required to
claim a higher DRE than the default. The updated DREs reflect increased
data and a refined approach rather than changes in the actual
destruction rates. The updates to the DREs in Table I-16 would increase
the accuracy of emissions reported by facilities and would be expected
to reduce the number of facilities that choose to measure site-specific
DREs.
d. Calculation of By-Products Produced in Hydrocarbon Fueled Abatement
Systems To Improve the Accuracy of Emissions Estimates
We are proposing to add a calculation methodology that would
estimate the emissions of CF4 produced in hydrocarbon-fuel
based emissions control systems that are not certified not to generate
CF4. (In this section III.E.1.d, all references to
``uncertified hydrocarbon-fuel based emission control systems'' refer
to hydrocarbon-fuel based emissions control systems that are not
certified not to generate CF4.) The proposed calculation
would be codified in equation I-9; we are proposing to renumber the
previous equation I-9 as equation I-8b. Hydrocarbon-fuel based emission
control systems are hydrocarbon-fuel based combustion devices that are
designed to reduce emissions from exhaust streams from electronics
manufacturing processes and include, but are not limited to, abatement
systems that are designed to abate F-GHGs or N2O. Studies
have shown that direct reaction between molecular fluorine
(F2) and hydrocarbons (e.g., CH4) to form
CF4 can occur in hydrocarbon-fueled combustion emissions
control systems, and the 2019 Refinement includes calculations to
account for the formation and emission of CF4 from this
source.\47\ Where emissions control systems that generate
CF4 are used to abate NF3 from RPC processes, the
CF4 is expected to account for 1.5 times the emissions of
NF3 (in CO2e) that would have occurred with no
abatement (see the subpart I
[[Page 36954]]
TSD available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424).
---------------------------------------------------------------------------
\47\ S.N. Li, et al. ``FTIR spectrometers measure scrubber
abatement efficiencies,'' Solid State Technology, Vol. 45. (2002);
Gray, Fraser, and Afroza Banu, ``Influence of CH4-
F2 mixing on CF4 by-product formation in the
combustive abatement of F2,'' Research Disclosure, Sept.
2018, both available in this docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
Equation I-9 would be used to estimate the emissions of
CF4 from generation in emissions control systems by
calculating the mass of the fluorine entering uncertified hydrocarbon-
fuel based emissions control systems (the product of the consumption of
the input gas, the emission factor for fluorine, and ai,
where ai is the ratio of the number of tools with
uncertified abatement devices for the gas-process combination to the
total number of process tools for the gas-process combination) and
multiplying that mass by a CF4 emission factor,
ABCF4,F2. The proposed default emission factor for this
reaction (ABCF4,F2) is 0.116.\48\ This reaction is expected
to result in significant emissions only where F2 is used as
an input gas or where large amounts of F2 can be formed as a
by-product of the decomposition of the cleaning gas into atomic
fluorine and subsequent recombination of the unreacted fluorine into
F2. Thus, this equation would only apply to processes that
use F2 as an input gas or to RPC processes that use
NF3 as an input gas. When NF3 is used as a
cleaning gas during the RPC process, the vast majority of the
NF3 molecules (approximately 98 percent, based on the
default values for (1-UNF3,RPC)) are decomposed within the
remote plasma unit to form fluorine and nitrogen radicals, ions, and
excited species. While some of the fluorinated species clean the solid
residues deposited on the chamber walls by combining with the residues
to form gaseous by-products such as SiF4, HF,
COF2, and CF4, some fluorine atoms recombine to
form molecular fluorine (F2). Based on confidential data
received from Edwards, Ltd.,\49\ a manufacturer of abatement equipment,
the proposed BEF for F2 from NF3 used in remote
plasma clean processes is 0.5. This data was also used to update the
2019 Refinement. The proposed by-product is reasonable considering that
emission factor data for NF3 from RPC processes submitted to
the EPA show that emissions of NF3 and CF4
accounted for less than 20 percent of the total mass of fluorine in the
NF3 used in the process in all but one of the 123 processes
measured, and generally significantly less, leaving at least 80 percent
of the fluorine available to form F2, SiF4, and
HF. (The last two compounds are formed when fluorine combines with
solid residue on the chamber walls, but the EPA's emission factor data
do not include specific information on the quantities of those
compounds--or of the fluorine--formed in the process.) No data from
processes that use F2 as an input gas are currently
available for the 1-U of F2; however, data from
NF3-using processes (where most of the NF3 is
dissociated into atomic fluorine during the process) indicate that the
1-U value for F2 may be near 0.7 (Confidential data received
from Edwards, Ltd.,\50\ 2018, available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424).\51\
---------------------------------------------------------------------------
\48\ See Volume 3, Chapter 6. Electronics Industry Emissions to
the 2019 Refinement to the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, as cited above in this document, and the
subpart I TSD (available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2019-0424).
\49\ The by-product emission factor for F2 from
NF3 was calculated from 15 measurements of remote plasma
clean processes following a variety of different Thin Film
Deposition (TFD) processes. F2 generation was estimated
using a mass-balance approach that compared the mass of atomic
fluorine (F) flowing into each process chamber in the form of
NF3 with the mass of fluorine exiting the process
chambers in the form of SiF4, COF2, HF, and
NF3. The mass of fluorine that was not accounted for at
the exhaust of the process chamber was assumed to be in the form of
F2.
\50\ The by-product emission factor for F2 from
NF3 was calculated from 15 measurements of remote plasma
clean processes following a variety of different Thin Film
Deposition (TFD) processes. F2 generation was estimated
using a mass-balance approach that compared the mass of atomic
fluorine (F) flowing into each process chamber in the form of
NF3 with the mass of fluorine exiting the process
chambers in the form of SiF4, COF2, HF, and
NF3. The mass of fluorine that was not accounted for at
the exhaust of the process chamber was assumed to be in the form of
F2.
\51\ All documents in the docket are listed at https://www.regulations.gov. Although listed in the index, some information
is not publicly available, e.g., CBI or other information whose
disclosure is restricted by statute.
---------------------------------------------------------------------------
As for other gas and process combinations where no data is
available (listed as ``NA'' in Tables I-3 and I-4), a 1-U of 0.8 would
be used for F2 in equation I-9 for all process types. The
EPA is seeking comment on whether there is data available to support an
alternative 1-U for F2. The addition of this calculation is
expected to increase the accuracy of emissions estimates from
electronics manufacturers that use emissions control equipment. Along
with the new calculation, we are proposing corresponding monitoring,
reporting, and recordkeeping requirements (see 40 CFR 98.94(e), 40 CFR
98.96(o), and 40 CFR 98.97(b), respectively) for facilities that: (1)
use hydrocarbon-fuel-based emissions control systems to control
emissions from tools that use either NF3 as an input gas in
RPC processes or F2 as an input gas in any process; and (2)
assume in equation I-9 that one or more of those systems do not form
CF4 from F2. These proposed provisions, which are
patterned after the current provisions covering abatement systems from
which facilities quantify emission reductions, would require that the
facility certify and document that the model for each of the systems
that the facility assumes does not form CF4 from
F2 has been tested and verified to produce less than 0.1
percent CF4 from F2, and that each of these
systems is installed, operated, and maintained in accordance with the
directions of the emissions control system manufacturer. The facility
could perform the testing itself, or it could supply documentation from
the emissions control system manufacturer that supports the
certification. If the facility performed the testing, it would be
required to measure the rate of conversion from F2 to
CF4 using a scientifically sound, industry-accepted method
that accounts for dilution through the abatement device, such as the
EPA DRE Protocol, adjusted to calculate the rate of conversion from
F2 to CF4 rather than the DRE. The EPA requests
comment on whether there are other measurement methods that should be
cited as examples or listed as options for this measurement. The EPA
has considered that it may be difficult to adapt the EPA DRE Protocol
to measure the rate of conversion from F2 to CF4
if the analytical methods cited in the Protocol (Fourier Transform
Infrared (FTIR) and Quadrupole Mass Spectroscopy (QMS)) do not work
well to measure F2 flows. Instead, other measuring or
metering methods, such as calibrated mass-flow controllers or
electrochemical cells, may be more effective. The EPA requests comment
on this and any other issues that may arise in adapting the EPA DRE
Protocol to measure the rate of conversion from F2 to
CF4 in hydrocarbon-fuel-based emissions control systems.
These issues and means of handling them could then be specifically
addressed in the final rule.
Given the potential sensitivity of a calculated stack emission
factor to any emissions of CF4 produced in hydrocarbon-fuel
based emissions control systems, we are also proposing to amend
paragraph 40 CFR 98.94(j)(1)(i) to require that the uptime (i.e., the
fraction of time that abatement system is operational and maintained
according to the site maintenance plan for abatement systems) during
the stack testing period average at least 90 percent for uncertified
hydrocarbon-fueled emissions control systems. This would ensure that
the calculated stack emission factor for CF4 will not be
underestimated due to a significant fraction of uncertified systems not
[[Page 36955]]
operating during the stack test. This proposed amendment is similar to
the current requirement in 40 CFR 98.98(j)(1)(i), which requires at
least 90 percent uptime averaged over all abatement systems during the
stack testing period, but would now require that this specific set,
hydrocarbon-fueled abatement systems that are not certified not to
generate CF4, also average at least 90 percent uptime during
the test.
Because CF4 may be formed from F2 in any
hydrocarbon-fuel-based emissions control system, not only abatement
systems from which facilities claim reductions for purposes of
reporting under subpart I, we are proposing to apply these provisions
to all hydrocarbon-fuel-based emissions control systems used in
electronics manufacturing facilities. This includes, but is not limited
to, abatement systems as defined at 40 CFR 98.98. We are proposing to
add a definition of ``hydrocarbon-fuel-based emissions control system''
to clarify the scope of coverage.
e. Revisions to Calibration Requirements for Abatement Systems
We are proposing to modify 40 CFR 98.97(d)(9)(ii) to require that a
vacuum pump's purge flow indicators are calibrated every time a vacuum
pump is serviced or exchanged. Some vacuum pumps' purge flow indicators
are inaccurate and could deliver higher than indicated purge flow,
exceeding the manufacturer's maximum flow specification for an
abatement system.\52\ Requiring calibration of the vacuum pumps would
make it less likely that facilities would unknowingly claim an
abatement system as operational during a time period when the abatement
system is being operated outside of the manufacturer's flow
specifications. Operating outside of the manufacturer's flow
specifications is problematic because abatement systems are generally
certified to meet or exceed the claimed DRE only when operated within a
specified range of flow. We expect that this requirement would require
calibrations every 1 to 6 months, depending on the process. The EPA is
requesting comment on whether this approach and expected frequency is
recommended or an approach that specifies the frequency of calibration,
such as a minimum calibration of twice a year, would be a sufficient
approach to maintain accurate flow rates.
---------------------------------------------------------------------------
\52\ See Volume 3, Chapter 6. Electronics Industry Emissions to
the 2019 Refinement to the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, as cited above in this document.
---------------------------------------------------------------------------
2. Revisions To Streamline and Improve Implementation for Subpart I
a. Revisions to the Applicability Calculations for Subpart I
As discussed in section II.B.1 of this preamble, we are proposing
to revise the applicability of subpart I. We are proposing to do this
by adding a second option in 40 CFR 98.91(a) for estimating GHG
emissions for semiconductor, MEMS, and LCD manufacturers; by revising
the current applicability calculation for PV manufacturers; and by
updating the emission factors used in the current applicability
calculations for MEMS and LCD manufacturers. Currently, semiconductor,
MEMS, and LCD manufacturers that have not previously reported under the
GHGRP are required to calculate the subpart I contribution toward the
25,000 mtCO2e reporting threshold by using a calculation
based on annual manufacturing capacity in substrate area (square
meters, m\2\). The calculation based on manufacturing capacity was
adopted in part to limit the burden required for facilities to estimate
their electronics manufacturing emissions for purposes of assessing the
applicability of the GHGRP, as this method does not require either
tracking gas consumption or apportioning gas consumption by process
type. Instead, it is based on production capacity in terms of substrate
area and default emission factors based on manufacturing type. However,
this method may not be suitable for some facilities that have emissions
per m\2\ rates that are atypical and could consequently require some
facilities that emit considerably less than 25,000 mtCO2e
(unabated) to report under the GHGRP.
We are therefore proposing to add a second option for estimating
emissions in 40 CFR 98.91(a)(1) and (2) that includes two new
equations, I-1B and I-2B (and renumbering equations I-1 and I-2 to I-1A
and I-2A, respectively). Specifically, we are proposing to add an
optional calculation method that uses gas consumption multiplied by a
simple set of emission factors (along with GWPs and a factor to account
for heat transfer fluid) to estimate emissions in 40 CFR 98.91(a)(1)
and (2). To estimate emissions, facilities would, for each F-GHG, apply
an input gas emission factor of 0.8 and by-product gas formation
factors of 0.15 for CF4 and 0.05 for
C2F6. The emission factors we are proposing for
this optional calculation method are included in proposed new Table I-2
of subpart I of part 98 and are the same as the emission factors we are
proposing in this rulemaking for gas and process combinations for which
there is no default in Tables I-3, I-4, or I-5, as applicable; and the
factors are discussed further under the updates to emission factors in
section III.E.1.c of this preamble. As discussed in III.E.1.c of this
preamble, almost all gas and process combinations emit CF4
and C2F6 as by-products. Assigning default values
for these by-products, instead of assuming emissions to be equal to gas
consumption, would result in a more accurate emissions estimate,
especially in cases where the input gas has a significantly lower or
higher GWP than average. An emission factor of 1.0 would be applied to
N2O. Finally, as is currently required for the production-
based method, the calculated emissions of each F-GHG and N2O
would be multiplied by the chemical-specific or default GWP for that
GHG and the resulting CO2e emissions would be summed across
GHGs. The total would continue to be multiplied by a factor to account
for the use of F-HTFs using equation I-4. The result would be the
calculated subpart I contribution toward the 25,000 mtCO2e-
per-year emissions threshold in 40 CFR 98.2(a)(2).
Facilities that choose to use this option for their calculation
method would be required to track annual gas consumption by GHG but
would not be required to apportion consumption by process type for the
purposes of assessing rule applicability. The EPA is proposing a
simplified consumption-based calculation method option for
semiconductor, MEMS, and LCD manufacturing facilities to provide a
calculation method that could appropriately exclude some lower-emitting
facilities that would otherwise be subject to subpart I. Facilities
would continue to have the option to use the manufacturing capacity-
based method for estimating emissions in 40 CFR 98.91(a)(1) and (2).
Facilities using either method would continue to calculate total annual
GHG emissions, including combined emissions from stationary fuel
combustion units and other applicable source categories, for comparison
to the 25,000 mtCO2e per year emission threshold in 40 CFR
98.2(a)(2).
Facilities that manufacture PV already have a consumption-based
method in the current rule. However, currently, the applicability
calculation for PV manufacturing includes only GHGs ``that have listed
GWP values in Table A-1 to subpart A of this part.'' Because default
GWPs are now available for F-GHGs that do not have chemical-specific
GWPs in Table A-1, we are proposing to delete the limiting phrase
``that have listed GWP values in Table A-1.'' We are also proposing to
revise
[[Page 36956]]
equation I-3 to be identical to the new equations I-1B and I-2B and to
also use newly proposed Table I-2. As for semiconductor, MEMS, and LCD
manufacturers, this revision is expected to increase the accuracy of
the estimated emissions for determining applicability.
We are also proposing to revise the emission factors in Table I-1
used for estimating emissions for MEMS and LCD manufacturing when
equation I-1A (based on production in substrate area) is used to assess
the applicability of part 98. The emission factors currently in Table
I-1 include emissions factors for semiconductor, LCD, and MEMS
manufacturing. For semiconductor and LCD manufacturing, the emissions
factors that are currently in Table I-1 are based on the Tier 1 default
emission factors in Vol. 3, Ch. 6 Electronics Industry Emissions in the
2006 IPCC Guidelines for National Greenhouse Gas Inventories.\53\
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\53\ IPCC. Guidelines for National Greenhouse Gas Inventories,
Volume 3, Ch. 6 Electronics Industry Emissions, 2006. https://www.ipcc-nggip.iges.or.jp/public/2006gl/. Available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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For MEMS manufacturing, there were no IPCC Tier 1 factors available
at the time of the 2010 Final Rule for Additional Sources of
Fluorinated GHGs (75 FR 74774), and the emission factors were instead
based on the IPCC Tier 2b SF6 emission factor for
semiconductors.\54\ The 2019 Refinement included an update to the IPCC
Guidelines Tier 1 emission factors using newly available data.\55\ For
LCD and MEMS manufacturing, the EPA has tentatively determined that the
new Tier 1 emission factors in the 2019 Refinement would better reflect
industry-wide technological trends and are expected to improve the
accuracy of the emissions estimated for the GHGRP using Table I-1.
However, for semiconductor manufacturing, emission rates vary
significantly depending on the wafer size used for manufacturing, and
therefore no single set of default emission factors accurately
estimates emissions for all wafer sizes. The Tier 1 emission factors in
the 2019 Refinement are, overall, lower than those in the 2006 IPCC
Guidelines because they reflect the increasing importance of the 300-mm
wafer size technology, which has lower emission rates than the older
but still significant 200-mm (or smaller) wafer size technology. (The
Tier 1 emission factors in the 2019 Refinement were developed assuming
a 50/50 split between 200-mm and 300-mm wafer production.) To estimate
emissions for manufacturing using the 200-mm wafer size, the 2019
Refinement recommends that the Tier 1 emission factors in the 2006 IPCC
Guidelines be used because they more accurately reflect emission rates
for that wafer size than do the Tier 1 emission factors in the 2019
Refinement. Use of the Tier 1 emission factors in the 2019 Refinement
would underestimate emissions from facilities manufacturing on wafers
sized 200 mm or smaller. In addition, our analysis (CBI TSD Comparison
of Subpart I Emissions to New Tier 1 EFs, available in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424 \56\) indicates
that use of these factors would underestimate emissions from a few
facilities manufacturing on wafers sized 300 mm. To maintain the
simplicity of the applicability calculation in equation I-1A for
semiconductors, the EPA prefers to retain a single set of default
emission factors for semiconductors in Table I-1, and to ensure that
facilities manufacturing on the 200-mm wafer size are not improperly
excluded from coverage by the GHGRP, we are not proposing to revise the
emission factors for semiconductor manufacturing in Table I-1. While
this could result in overestimated emissions for some facilities that
manufacture on the 300-mm wafer size, the EPA notes that such
facilities would have the option to use gas consumption data rather
than capacity in square meters to assess applicability, as discussed
above.
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\54\ Refer to Technical Support Document for Process Emissions
from Electronics Manufacture (e.g., Micro-electro-mechanical
Systems, Liquid Crystal Display, Photovoltaics, and Semiconductors),
November 2010, available in the docket for this rulemaking, Docket
Id. No, EPA-HQ-OAR-2019-0424.
\55\ See Volume 3, Chapter 6. Electronics Industry Emissions to
the 2019 Refinement to the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, as cited above in this document.
\56\ Supra note 51.
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There is no expected impact on the number of LCD manufacturing
facilities reporting to the GHGRP due to the proposed update to those
emission factors, as there are currently no known LCD manufacturers in
the United States. For MEMS manufacturers, the proposed update to Table
I-1 could possibly result in one additional facility reporting to the
GHGRP (estimated to have annual emissions greater than or equal to
25,000 mtCO2e). However, due to a lack of actual capacity
data, it is difficult to assess with precision how many facilities, if
any, would be impacted.
b. Revisions to the Frequency and Applicability of the Technology
Assessment Report
For the reasons described in section II.B.3 of this preamble, we
are proposing to revise the frequency and applicability of the
technology assessment report requirements in 40 CFR 98.96(y), which
applies to semiconductor manufacturing facilities with GHG emissions
from subpart I processes greater than 40,000 mtCO2e per
year. (Other proposed changes to 40 CFR 98.96(y) are discussed in
section III.E.1 of this preamble.) The purpose of the technology
assessment report is to provide regular review of technology changes in
the semiconductor manufacturing industry and ensure that default gas
utilization rates, by-product formation rates, and DRE values
accurately reflect changes in the industry's practices, such as the
introduction of manufacturing on 450-mm sized wafers. In the 2012
proposed amendments to subpart I (77 FR 63538, October 16, 2020), we
noted that the semiconductor manufacturing industry had historically
been ``fast-evolving, achieving exponentially increasing processor
speeds and improving manufacturing efficiencies through the rapid
adoption of new manufacturing processes'' (see 77 FR 63565). At that
time the EPA had identified the potential introduction of 450 mm wafer
technology, as well as other new process technologies that could affect
emissions. Therefore, we considered a three-year report appropriate for
collecting information on changes in the semiconductor industry that
would potentially affect emissions. However, following submission and
review of the first three-year reports, we have determined that
industrial advancements are occurring at a slower pace. As such, we are
proposing to amend 40 CFR 98.96(y) to decrease the frequency of
submission of the reports from every three years to every five years.
Under the current rule, semiconductor manufacturing facilities are
required to submit their next technology assessment report by March
31st, 2023 (concurrent with their RY2022 annual report). This proposed
revision would affect the due date for that technology assessment,
moving the due date from March 31, 2023, to March 31, 2025. Our review
of the technology assessment reports submitted for RY2016 and RY2019
did not find significant technology changes within the industry over
the three years the reports covered. Based on an assessment of the
RY2016 and RY2019 reports (CBI memorandum, Review of 2017 Subpart
[[Page 36957]]
I Triennial Reports Submitted by the Electronics Industry (Transcarbon
International, 2017, available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424) \57\ gas emissions and wafer size
data that have been submitted to e-GGRT in annual reports, and
information gathered from outside sources (summarized in a literature
review, Memorandum: Review of trade and scientific publications to
identify significant recent changes in technologies and gas usage in
electronic devices manufacturing, prepared by S[eacute]bastien Raoux,
Transcarbon International, and Brian Palmer, Eastern Research Group,
Inc. (April 3, 2017), available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424), we believe that a five-year
period would provide updates to the EPA more in line with the pace of
technological change within the semiconductor industry. Revising the
frequency of submission to every five years would increase the
likelihood that reports will include updates in technology rather than
conclusions that technology has not changed. Because we have found that
changes within the industry have been incorporated at a slower pace and
do not anticipate significant changes in technology on a three-year
frequency, the proposal to require submission of these reports on a
five-year frequency would likely not significantly affect the quality
of the data available annually in the GHGRP.
---------------------------------------------------------------------------
\57\ Supra note 51.
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Second, we are proposing to revise the applicability of 40 CFR
98.96(y). Currently, any facility with emissions greater than 40,000
mtCO2e in their most recently submitted emissions report
must submit a technology assessment report, including facilities
manufacturing devices only using wafer sizes smaller than 200 mm (e.g.,
150 mm). Because the focus of the technology assessment report is on
semiconductor manufacturing using 200-mm, 300-mm, and potentially 450-
mm wafers (see 40 CFR 98.96(y)(2)(i)-(iii)), we are proposing to
restrict the reporting requirement in 40 CFR 98.96(y) to facilities
that emitted greater than 40,000 mtCO2e and produced wafer
sizes greater than 150 mm (i.e., 200 mm or larger) during the period
covered by the technology assessment report. We are also proposing to
explicitly state that semiconductor manufacturing facilities that
manufacture only 150-mm or smaller wafers are not required to prepare
and submit a technology assessment report. The applicability of 40 CFR
98.96(y) is currently based on the emissions in a facility's most
recently submitted report (typically the emissions occurring in the
second-to-last year covered in the technology assessment report, e.g.,
RY2022 emissions for the technology reports that would be submitted in
2023). However, because facilities that cease all operations related to
subpart I are eligible to discontinue reporting under 40 CFR
98.2(i)(3), we are also proposing to further revise the applicability
of 40 CR 98.96(y) to clarify that a technology assessment report need
not be submitted by a facility that has ceased (and has not resumed)
semiconductor manufacturing before the last reporting year covered by
the technology assessment report (i.e., no manufacturing at the
facility for the entirety of the year immediately before the year
during which the technology assessment report is due). For example, if
a facility manufacturing on 300-mm wafers exceeded the 40,000
mtCO2e threshold in 2023 but ceased operations in December
of that year and has not since then resumed operations, that facility
would not be required to submit a technology assessment report in March
of 2025.
F. Subpart N--Glass Production
For the reasons described in section II.A.4 of this preamble, we
are proposing two revisions to the recordkeeping and reporting
requirements of subpart N of part 98 (Glass Production) to enhance the
quality and accuracy of the data collected under the GHGRP. Subpart N
currently requires calculation of CO2 emissions using one of
two methodologies, either direct measurement using CEMS, or a mass
balance methodology based on mass, carbonate content, and fraction of
calcination for each carbonate-based input material. For each option,
reporters are required to provide the annual quantities of glass
produced from each glass melting furnace, and the annual quantities of
glass produced from all furnaces combined. The annual quantities of
glass produced have been used historically in verification of reported
emissions under the GHGRP for comparison to, and to check for temporal
consistency with, carbonate content data and emissions estimates
provided by facilities. Facilities also maintain records of monthly
glass production rate for each glass furnace. We are proposing to
revise the existing reporting and recordkeeping requirements for both
CEMS and non-CEMS reporters to require that facilities report and
maintain records of annual glass production by glass type.
Specifically, we are proposing to revise 40 CFR 98.146(a)(2) and (b)(3)
to require the annual quantity of glass produced in tons, by glass
type, from each continuous glass melting furnace and from all furnaces
combined, and the annual quantity of glass produced in tons, by glass
type, from each continuous glass melting furnace and from all furnaces
combined. The major raw materials (i.e., fluxes and stabilizers) that
emit process-related CO2 emissions in glass production are
limestone, dolomite, and soda ash, though there are variations in
ingredients and other carbonates may be used in smaller quantities. In
general, the composition profile of raw materials is relatively
consistent among individual glass types (e.g., container, flat glass,
fiber glass, specialty glass), however, some facilities make use of
recycled glass in their production process. Differences in the use of
recycled material, and other factors, lead to differences in emissions
from the production of different glass types. The annual quantities of
glass produced by type would provide a useful metric for understanding
variations and differences in emissions estimates that may not be
apparent in the existing annual production data collected, improve our
understanding of industry trends, and improve verification for the
GHGRP. The proposed data elements would also provide useful information
to improve analysis of this sector in the U.S. GHG Inventory. As noted
in the 2019 U.S. GHG Inventory report,\58\ the EPA reviews the GHGRP
data in the development of inventory estimates for this sector to help
understand the completeness of emission estimates and for quality
control. Including glass product type would increase the transparency
of the data set produced by the Inventory. In addition to the proposed
reporting of these data elements, we are proposing harmonizing
revisions in 40 CFR 98.147(a)(1) and (b)(1), to add that records must
also be kept on the basis of glass type.
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\58\ See U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2019 (EPA 2021), available at: https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2019.
---------------------------------------------------------------------------
We do not anticipate that the proposed data elements would require
any additional monitoring or data collection by reporters, as annual
production data by glass type is likely available in existing company
records. The proposed changes would therefore result in minimal
additional burden to reporters. We are also proposing related
confidentiality determinations for the
[[Page 36958]]
additional data elements, as discussed in section VI of this preamble.
G. Subpart P--Hydrogen Production
1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart P
As discussed in section II.A of this preamble, we are proposing
several amendments to enhance the quality of the data collected under
subpart P of part 98 (Hydrogen Production).
Subpart P estimates CO2 emissions from hydrogen
production units using a carbon mass balance along with an assumption
that all carbon is transformed to CO2 and is emitted from
the hydrogen production process. This assumption is reasonable for the
majority of hydrogen production units because these facilities produce
hydrogen using either steam methane reforming or partial oxidation,
followed by a water-gas-shift reaction. The first step (steam methane
reforming or partial oxidation) produces a mixture of carbon monoxide
(CO) and hydrogen, commonly referred to as syngas. The water gas shift
reaction uses water to react with the CO in the syngas to produce
CO2 and additional hydrogen. While the majority of hydrogen
production units use the water-gas-shift reaction, some facilities only
produce syngas as their product. Some facilities may also intentionally
produce methanol as a product of these reactions. In these cases, the
assumption that 100 percent of the carbon used in the process is
converted to CO2 and thus are direct CO2
emissions from hydrogen production units is inaccurate.
As noted in section III.C of this preamble for subpart G (Ammonia
Manufacturing), TFI has commented numerous times regarding its view of
the lack of a true mass balance for subpart G. In several of their
comments (specifically, TFI's Comments on the Proposed ``2013 Revisions
to the Greenhouse Gas Reporting Rule and Proposed Confidentiality
Determinations for New or Substantially Revised Data Elements,'' May 2,
2013, and Comments on the Proposed ``2015 Revisions and Confidentiality
Determinations for Data Elements under the Greenhouse Gas Reporting
Rule,'' March 30, 2016),59 60 TFI stated that subpart P
lacked a true mass balance because the emissions calculation
methodology in 40 CFR 98.163 does not account for carbon that is bound
in methanol or other by-products of the process and therefore is not
emitted as CO2. TFI pointed out that subpart P requires
reporting of methanol that is intentionally produced and ``carbon other
than CO2'' that is transferred off site, but that the
emissions calculation methodology in 40 CFR 98.163 still assumes that
100 percent of the carbon is emitted as CO2 because the mass
balance equations do not subtract out the carbon that leaves the
facility as methanol or another product.
---------------------------------------------------------------------------
\59\ TFI's Comments on the Proposed ``2013 Revisions to the
Greenhouse Gas Reporting Rule and Proposed Confidentiality
Determinations for New or Substantially Revised Data Elements,''
Docket Id. No. EPA-HQ-OAR-2012-0934, May 2, 2013. Also available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
\60\ TFI's Comments on the Proposed ``2015 Revisions and
Confidentiality Determinations for Data Elements under the
Greenhouse Gas Reporting Rule,'' Docket Id. No. EPA-HQ-OAR-2015-
0526-0064, March 30, 2016. Also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
Syngas is used as a feedstock for chemical production, most
commonly to produce methanol. Carbon transformed into methanol or other
chemicals are not emitted as CO2 unless the syngas is used
directly as fuel. For fuel combustion units other than the hydrogen
process units, and to which subpart C (General Stationary Fuel
Combustion Sources) applies, the CO2 emissions from syngas
combustion would be reported under subpart C of part 98. In considering
TFI comments, as noted in the preamble to the November 2013 amendments
(78 FR 71935, November 29, 2013), we considered both the emissions from
the production processes and consistency with the reporting
requirements for other subparts. We note that subpart X (Petrochemical
Production) uses a more direct mass balance approach in that carbon
contained in produced products (e.g., ethylene) is subtracted from the
carbon contained in feedstocks to calculate CO2 emissions.
The EPA has tentatively concluded that requiring reporters subject to
subpart P to report net CO2 process emissions after
subtracting out carbon contained in other products would provide a more
accurate estimate of the direct GHG emissions from these processes and
would provide consistency in our approach across the GHGRP. Therefore,
the EPA is proposing to amend subpart P to allow the subtraction of
carbon contained in products other than CO2 (excluding
methanol) and the carbon contained in methanol from the carbon mass
balance used to estimate CO2 emissions. The proposed
revisions would add new paragraph 40 CFR 98.163(d) to allow facilities
to adjust the calculated emissions from fuel and feedstock consumption
to subtract the mass of both non-CO2 carbon (excluding
methanol) and carbon contained in the intentionally produced methanol
in order to calculate net CO2 process emissions. We are also
proposing harmonizing revisions to the introductory paragraph of 40 CFR
98.163 and 40 CFR 98.163(b).
In conjunction with adding the new paragraph to 40 CFR 98.163(d),
we are proposing a clarifying revision to the reporting requirements at
40 CFR 98.166(b)(1) to specify that the annual CO2 emissions
may be determined in accordance with either 40 CFR 98.163(b), the
existing equations, or 40 CFR 98.163(d), the revision requiring the
calculation of net CO2 emissions using equation P-4. We are
proposing to revise 40 CFR 98.166(d) to require reporting the mass of
non-CO2 carbon (excluding methanol) collected and
transferred off-site for each process unit rather than for all process
units combined, as currently reported. Reporters are already required
to account for and report under 40 CFR 98.166(d) the mass of non-
CO2 carbon (excluding methanol) collected and transferred
off-site for all process units combined and under 40 CFR 98.166(e) the
mass of methanol produced for each process unit. This proposed revision
would cause a slight increase in reporting burden, but the additional
level of reporting is necessary to implement the requested change in
the calculation method and facilitate report verification. The proposed
revision would provide the same breadth of information that was
previously reported to inform future policy decisions. Additionally,
this data element may be determined using company records, which also
should minimize the increased burden. We are proposing related
confidentiality determinations for the additional data elements, as
discussed in section VI of this preamble.
As a result of the new equation P-4, the EPA is proposing to add
two new monthly recordkeeping elements as part of the verification
software records required in 40 CFR 98.167(e): (1) monthly mass of
carbon other than CO2 or methanol collected and transferred
off site; and (2) monthly mass of methanol intentionally produced as a
desired product. This proposed change is not expected to result in a
significant increase in burden because both elements are already being
reported on an annual basis. For reporters that do not produce carbon
other than CO2 (excluding methanol) or methanol, the
requirements for recordkeeping would remain unchanged. We are also
clarifying that retention of the file required in 40 CFR 98.167(e)
satisfies
[[Page 36959]]
the recordkeeping requirements for each hydrogen production unit.
2. Proposed Revisions To Streamline and Improve Implementation for
Subpart P
We are proposing several revisions to subpart P to streamline the
requirements of this subpart and improve flexibility for reporters.
First, we are proposing several revisions to address unconventional
feedstocks being used for hydrogen production. For example, in RY2017,
a new facility started reporting under subpart P that produced hydrogen
via brine electrolysis. Additionally, we understand facilities are
considering using anhydrous ammonia as a feedstock for hydrogen
production. The test methods included in 40 CFR 98.164(b)(5) are
generally not applicable for these feedstocks. Moreover, the reduced,
annual measurement frequency allowances in 40 CFR 98.164(b)(2) and (3)
are specific to ``hydrocarbon fuels and feedstocks having consistent
composition'' [emphasis added].
To address the recent use of unconventional non-hydrocarbon
feedstocks, and for the reasons described in section II.B.2 of this
preamble, we are proposing to add an allowance in a new paragraph 40
CFR 98.164(b)(5)(xix) to use alternative methods if the methods
currently in 40 CFR 98.164(b)(5) are not appropriate because the
relevant compounds cannot be detected, the quality control requirements
are not technically feasible, or use of the method would be unsafe.
Similar provisions have been provided in other GHGRP subparts, such as
subpart X. This proposed revision will ensure that subpart P will not
mandate the use of inappropriate or unsafe methods for these
unconventional feedstocks.
Additionally, we are proposing revisions to 40 CFR 98.164(b)(2) and
(3) to allow the use of product specification information annually for
non-hydrocarbon gaseous fuels and feedstocks that have carbon content
less than or equal to 20 parts per million by weight (i.e., 0.00002 kg
carbon per kg of gaseous fuel or feedstock) rather than at least weekly
sampling and analysis. Similarly, we are proposing revisions to 40 CFR
98.164(b)(3) to allow the use of product specification information
annually for non-hydrocarbon liquid fuels and feedstocks that have a
carbon content of less than or equal to 0.00006 kg carbon per gallon of
liquid fuel or feedstock rather than monthly sampling and analysis. The
value of 0.0006 kg/gallon was derived using 20 parts per million by
weight and assuming the liquid that has a specific gravity of 0.8
(i.e., a density of approximately 3.0 kg/gal). The current
unconventional non-hydrocarbon fuels and feedstocks utilized in
hydrogen production have very limited GHG emission potential and are
currently an insignificant contribution to the GHG emissions from
hydrogen production. Therefore, we consider it reasonable to provide a
simple alternative of allowing use of product specification information
on an annual basis for determining carbon content for these
unconventional, non-hydrocarbon fuels and feedstocks.
We are also proposing revisions to 40 CFR 98.164(b)(5) to clarify
that the methods in 40 CFR 98.164(b)(5) must be used for determining
carbon content except for the newly proposed provisions for gaseous and
liquid fuels and feedstocks that have a low carbon content as provided
in paragraphs 40 CFR 98.164(b)(2) and (3). Additionally, we are
proposing to revise paragraphs 40 CFR 98.164(b)(2) through (4) to
specifically state that the carbon content must be determined ``. . .
using the applicable methods in paragraph (b)(5) of this section.''
This proposed revision does not alter the existing requirements for
fuels and feedstocks, it simply clarifies the linkage between the
requirements in paragraphs 40 CFR 98.164(b)(2) through (4) and (5) of
the current rule.
These proposed revisions to address unconventional hydrogen
production feedstocks would increase flexibility for reporters and
clarify requirements to reduce the number of reporters performing
monthly sampling and analysis using potentially inappropriate methods.
We expect that the proposed changes would allow reporters using
unconventional non-hydrocarbon fuels and feedstocks to use the proposed
product specifications provisions and reduce the need for sampling and
analysis. Even if the reporter cannot use the product specifications
provisions, the proposed revision to allow the use of modified or
alternative methods would likely reduce the analytical burden of trying
to use hydrocarbon-focused methods for a non-hydrocarbon stream. While
the proposed revisions would provide significant relief for those
reporters using unconventional non-hydrocarbon fuels or feedstocks, the
proposed change is expected to only affect a small number of reporters
due to the limited number of reporters that currently use these types
of feedstocks.
In providing these alternatives, we also evaluated whether
amendments to the recordkeeping and reporting requirements were
necessary. There are no direct reporting requirements for the
analytical method used to determine carbon content. The recordkeeping
requirements are included in 40 CFR 98.167(b), which requires retention
of ``. . . records of all analyses and calculations conducted as listed
in 40 CFR 98.166(b), (c), and (d).'' In reviewing these requirements,
we noted that these recordkeeping requirements were not revised when
the EPA added reporting requirements at 40 CFR 98.166(e) (79 FR 63787,
Oct. 24, 2014). Therefore, we are proposing to revise the recordkeeping
requirements at 40 CFR 98.167(b) to refer to paragraphs (b) through (e)
of 40 CFR 98.166. We note that, for facilities using the proposed
alternatives at 40 CFR 98.164(b)(2), (3) or (5)(xix), these
requirements include retention of product specification sheets, records
of modifications to the methods listed in 40 CFR 98.164(b)(5)(i)
through (xviii) that are used, and records of the alternative methods
used, as applicable.
H. Subpart Q--Iron and Steel Production
1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart Q
For the reasons described in section II.A.4 of this preamble, we
are proposing revisions to the reporting requirements for subpart Q of
part 98 (Iron and Steel Production) to enhance the quality and accuracy
of the data collected. Subpart Q currently requires calculation of
CO2 emissions using one of three methodologies: direct
measurement using CEMS, carbon mass balance methodologies, or site-
specific emission factors. Subpart Q requires that the CO2
emissions be calculated and reported for the following types of units:
taconite indurating furnace, basic oxygen furnace, non-recovery coke
oven battery, sinter process, EAF, decarburization vessel, and direct
reduction furnace. We are proposing to revise the existing reporting
requirements at 40 CFR 98.176(g) for all unit types and all calculation
methods to require that facilities report the type of unit, the annual
production capacity, and the annual operating hours for each unit. The
capacity of the unit as well as the level of operation have a
significant influence on the emissions of that unit. Therefore, the
annual production capacity in combination with annual operating hours
would provide useful information for understanding variations in annual
emissions and would provide useful information to verify reported data.
We often contact facilities seeking to understand yearly variations in
the emissions of a unit, and facilities explain that the variation
[[Page 36960]]
was due to the unit not operating for a particular time period. If data
on the capacity of the unit and the operating hours are included in the
annual report, it could explain the variation and eliminate the need
for correspondence with facilities. In addition, this data would
provide useful information to understand trends across the sector and
support analysis of these sources.
In general, we do not anticipate that the proposed data elements
would require any additional monitoring or data collection by
reporters. For facilities using the carbon mass balance method, this
data is already included in the record keeping requirements described
at 40 CFR 98.177(c) and (d). Although the record keeping requirement at
40 CFR 98.177(d) does not specify whether the data would be retained at
the facility or unit level, we do not anticipate that reporting data at
the unit level would present additional burden. For facilities using
the CEMS method or the site-specific emission factor calculation
method, we anticipate that this data would be readily available in
company records. However, we seek comment on both these assumptions. We
are proposing related confidentiality determinations for the additional
data elements, as discussed in section VI of this preamble.
For the reasons described in section II.A.5 of this preamble, we
are proposing to correct equation Q-5 in 40 CFR 98.173(b)(1)(v). An
error appears to have been introduced in equation Q-5 in revisions to
the equation in a final rule published in 2016 (81 FR 89188, December
9, 2016). Specifically, the final rule inadvertently published the
equation such that it appeared that the total CO2 emissions
from EAFs are determined as a fraction of, rather than the total of,
carbon mass emissions from inputs to the furnace. The proposed
revisions would correct the equation to remove the unnecessary fraction
symbol and would not add additional burden for the calculation or
reporting requirements for subpart Q.
2. Proposed Revisions To Streamline and Improve Implementation for
Subpart Q
For the reasons described in section II.B.2 of this preamble, we
are proposing two revisions to subpart Q to streamline monitoring.
First, we are proposing to revise 40 CFR 98.174(b)(2) to provide a new
option for facilities to determine the carbon content of process inputs
and outputs. Reporters are currently allowed to determine carbon
content either through direct sampling using the methods provided in 40
CFR 98.174(b)(2) or from similar analyses provided by a supplier. We
are proposing to allow reporters an additional third option to use
analyses provided by material recyclers that manage process outputs for
sale or use by other industries. Several of the process output
materials used in iron and steel production are typically sent to
recycling facilities (e.g., secondary zinc recycling facilities), which
process the material for supply to another entity. Such material
recyclers conduct testing on their inputs and products to provide to
entities using the materials downstream, and therefore perform carbon
content analyses using similar test methods and procedures as
suppliers. In the 2009 Final Rule, we determined that the use of carbon
content analyses from a material supplier was appropriate because the
carbon content does not vary widely at a given facility for the
significant process inputs and outputs that contain carbon, and because
the EPA continued to account for variations in emissions due to changes
in production rate, which are more likely to be a significant source of
variability (i.e., the quantity of carbon-containing materials that are
inputs and outputs to the process more directly influence emissions).
For these same reasons, we anticipate that analyses received from a
material recycling entity would be a reliable source of carbon content.
The proposed change would add flexibility for reporters by allowing an
additional option for obtaining measurements, in lieu of direct
sampling. We are proposing a minor harmonizing change to 40 CFR
98.176(e)(2) to require reporters to indicate if the carbon content was
determined from information supplied by a material recycler.
We are also proposing to revise 40 CFR 98.174(b)(2) to incorporate
a new test method for carbon content analysis of low-alloy steel. The
EPA has become aware that an additional method is available for
analysis of carbon content, specifically, ASTM E415-17, Standard Test
Method for Analysis of Carbon and Low-Alloy Steel by Spark Atomic
Emission Spectrometry (2017). We have reviewed the method, which is
targeted to this sector, and have tentatively concluded it is a valid
method for the purposes of subpart Q monitoring and reporting. The EPA
allows for the use of standard methods based on atomic emission
spectrometry in other sections of the rule, including under 40 CFR
98.144(b) where it can be used to determine the composition of coal,
coke, and solid residues from combustion processes by glass production
facilities. Therefore, we are proposing to incorporate the method by
reference in 40 CR 98.7 and cross-reference that incorporation in 40
CFR 98.174(b)(2) for use for steel, as applicable. The proposed test
method would be an alternative method and would provide additional
flexibility for reporters. We are also proposing a harmonizing change
to the reporting requirements of 40 CFR 98.176(e)(2), to clarify that
the carbon content analysis methods available to report are those
methods listed in 40 CFR 98.174(b)(2).
I. Subpart S--Lime Manufacturing
For the reasons discussed in this section and section II.A of this
preamble, we are proposing several revisions to subpart S of part 98
(Lime Manufacturing) to improve the quality of the data collected from
this subpart. First, for the reasons described in this section and in
section II.A.2 of this preamble, we are proposing to amend subpart S to
improve the methodology for calculation of annual CO2
process emissions from lime production. The proposed revisions would
account for CO2 that is captured from lime kilns and used
on-site. Under subpart S, reporters currently calculate CO2
emissions by either operating and maintaining a CEMS as specified in 40
CFR 98.193(a) or (b)(1), or by using the mass balance methodology under
40 CFR 98.193(b)(2). All lime kilns that are subject to 40 CFR
98.193(b) must calculate and report process and combustion
CO2 emissions by using the procedures in either 40 CFR
98.193(b)(1), for estimation of combined process and combustion
emissions from all lime kilns, or 40 CFR 98.193(b)(2), for estimation
of process and combustion CO2 emissions from all lime kilns
separately. For those lime kilns that use 40 CFR 98.193(b)(2),
calculation of annual CO2 process emissions from all lime
kilns is estimated through summing the following three values (per 40
CFR 98.193(b)(2)(iv)): (1) the product of a monthly site-specific
emission factor and weight or mass for each type of lime produced, (2)
the product of a monthly site-specific emission factor and each type of
calcined byproduct or waste that is sold, and (3) the annual
CO2 emissions from each type of calcined byproduct or waste
that is not sold. There is currently no allowance for subtraction of
CO2 that may be captured and used in another process on-site
(e.g., for use in a purification process or the manufacture of another
product such as refined beet sugars, precipitated calcium carbonate,
etc.).
In response to the 2009 Proposed Rule, one subpart S reporter,
Specialty
[[Page 36961]]
Minerals Inc., submitted a comment that stated that subpart S does not
include a ``deduction for the carbon dioxide that is taken up as a raw
material'' for use in another product, resulting in ``an overstatement
of total carbon dioxide emissions'' from lime manufacturing.\61\ In
section III.C of this preamble, we describe similar comments received
from TFI requesting changes that would allow sources to subtract from
direct facility emissions CO2 that is being used in the
manufacturing of other products on-site.
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\61\ Specialty Minerals Inc.'s Comments on the Proposed 2009
Greenhouse Gas Reporting Rule, Docket Id. No. EPA-HQ-OAR-2008-0508-
0907, June 4, 2009. Also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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Following review of these comments, the EPA has tentatively
concluded that allowing reporters subject to subpart S to report net
CO2 process emissions after subtracting out CO2
captured and used in other on-site processes would provide a more
accurate estimate of the direct GHG emissions from the lime
manufacturing process and would provide consistency in our approach
across the GHGRP. Therefore, we are proposing to modify equation S-4 to
subtract the CO2 that is captured and used in on-site
processes, with corresponding proposed revisions to the recordkeeping
requirements in 40 CFR 98.197(c) (to record the monthly amount of
CO2 from the lime manufacturing process that is captured for
use in all on-site processes). We are also proposing minor amendments
to the reporting elements in 40 CFR 98.196(b)(17) to clarify that we
only intend to collect data on CO2 that is captured and used
on-site (i.e., reporters do not need to account for CO2 that
was not captured but was used on-site), and to clarify that reporters
must account for CO2 usage from all on-site processes,
including for manufacture of other products, in the total annual amount
of CO2 captured. The proposed changes would also correct
some instances where reporters have provided values of CO2
used on-site that exceed facility emissions, where they have
inadvertently included CO2 that was not captured on-site
(e.g., CO2 purchased for water treatment), which incorrectly
implied that the facility's emissions were net negative. The proposed
amendments would not change the reporting of emissions from manufacture
of lime products, calcined lime by-products, or waste; this information
would continue to be collected. As such, the proposed amendments would
provide the same breadth of information that was previously reported to
inform future policy decisions.
Second, for the reasons described in section II.A.4 of this
preamble, we are proposing to add reporting requirements for reporters
using the CEMS methodology in order to improve our understanding of
source category emissions and our ability to verify reported data.
Subpart S reporters who use CEMS collect CO2 emissions data
through direct measurement, and no data on the chemical composition of
the products, byproducts, or wastes at CEMS facilities are collected
through the GHGRP.\62\ As such, there is currently limited data
available to the EPA to evaluate process emissions for reporters using
CEMS. As we noted for cement production facilities in section III.D of
this preamble, CEMS facility emissions are different from non-CEMS
emissions because combustion and process emissions are typically vented
through the same stack, causing process and combustion emissions to be
mixed and indifferentiable. In order to be able to differentiate
process emissions, we are proposing to collect other data elements from
CEMS reporters that are not currently reported, including annual
average results of the chemical composition analysis of lime products,
byproducts, or wastes. Collecting average chemical composition data for
CEMS facilities will provide the EPA the ability to develop a process
emission estimation methodology for CEMS reporters, which can be used
to verify the accuracy of the reported CEMS emission data. The EPA is
proposing to add data elements under 40 CFR 98.196(a) to collect annual
averages of the chemical composition input data on a facility-basis.
The proposed data elements include the annual arithmetic average
calcium oxide content (metric tons CaO/metric tons lime) and magnesium
oxide content (metric tons MgO/metric tons lime) for each type of lime
produced, for each type of calcined lime byproduct and waste sold, and
for each type of calcined lime byproduct and waste not sold. The
proposed data elements would rely on an arithmetic average of the
measurements rather than requiring reporters to weight by quantities
produced in each month. In addition to improving verification and data
quality for the GHGRP, the proposed data elements will also improve the
U.S. GHG Inventory, which could use the proposed data elements to
disaggregate process and combustion emissions that are reported by
facilities using CEMS.
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\62\ Subpart S reporters who use the mass balance methodology
under 40 CFR 98.193(b)(2) currently estimate CO2
emissions using monthly chemical composition data as inputs to
calculate emissions factors for the lime produced, calcined
byproducts and wastes sold, and calcined byproducts and wastes not
sold. These data inputs are not collected by the EPA but are only
entered into the EPA's Inputs Verification Tool, which conducts
verification checks at the time of report submission but does not
retain the data entered.
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Similarly, in order to improve verification, we are proposing to
collect additional data elements for reporters using the mass balance
methodology (i.e., reporters that comply using the requirements at 40
CFR 98.193(b)(2)). These proposed amendments would allow the EPA to
build verification checks for the actual inputs entered (e.g., MgO
content). We currently rely on verification checks within the IVT to
check the accuracy of inputs and reported emissions from non-CEMS
reporters, however, these checks are of limited usefulness since we
lack the information to develop specific anticipated ranges or
references for the entered data. Reporters using the mass balance
methodology are currently required to report the annual average results
of chemical composition analysis of each type of lime product produced
and calcined byproduct or waste sold, but do not supply data for
byproducts or wastes not sold. The EPA is proposing to add data
elements under 40 CFR 98.196(b) to collect the annual average results
of the chemical composition analysis of all lime byproducts or wastes
not sold (e.g., a single facility average calcium oxide content
calculated from the calcium oxide content of all lime byproduct types
at the facility), and the annual quantity of all lime byproducts or
wastes not sold (e.g., a single facility total calculated as the sum of
all quantities, in tons, of all lime byproducts at the facility not
sold during the year). Because the proposed data elements rely on
annual averages of the chemical composition measurements and an annual
quantity of all lime byproducts or wastes at the facility, they are
distinct from the data entered into the EPA's IVT. These proposed data
elements would inform and improve the EPA's existing reference checks
and allow the EPA to build additional checks for the data that are
currently verified through IVT. The proposed amendments would improve
the verification of entered data and confirm the veracity of reported
emissions.
We do not anticipate that the proposed data elements would require
any additional monitoring or data collection by reporters, as these
data are likely already available in existing company records. However,
we are requesting comment on whether any of
[[Page 36962]]
the above listed data elements would not be readily available to
reporters. Reporters using the mass balance methodology are expected to
have very minimal changes to reporting, as the chemical composition
averages and quantities we are proposing can be calculated from the
inputs that are currently entered into IVT. Finally, we are proposing
related confidentiality determinations for the additional data
elements, as discussed in section VI of this preamble.
J. Subpart W--Petroleum and Natural Gas Systems
We are proposing several revisions to subpart W (Petroleum and
Natural Gas Systems). Section III.J.1 of this preamble presents
proposed amendments that would improve the quality of data collected,
including new requirements for reporting of additional emission
sources, updated emission factors, new and revised reporting
requirements, and clarification of reporting requirements that
reporters have indicated are unclear, as described in section II.A of
this preamble. We are also proposing revisions described in section
III.J.2 of this preamble that would streamline and improve
implementation, including removing redundant or unnecessary reporting
requirements, and providing additional flexibility in the calculation
methods and monitoring requirements for some emission sources, as
described in section II.B of this preamble. We are proposing the
miscellaneous technical corrections and clarifications described in
section III.J.3 of this preamble. Finally, section III.J.4 of this
preamble describes the provisions for which we propose subpart W
reporters would be able to use best available monitoring methods (BAMM)
for RY2023. We are also proposing related confidentiality
determinations for new or revised data elements that result from these
proposed amendments, as discussed in section VI of this preamble.
In addition, on November 15, 2021 (86 FR 63110), the EPA proposed
under CAA section 111(b) NSPS for new, reconstructed, and modified oil
and natural gas sources, i.e., sources for which owners or operators
commence construction, modification, or reconstruction after November
15, 2021 (40 CFR part 60, subpart OOOOb) (hereafter referred to as
``NSPS OOOOb''), as well as emissions guidelines under CAA section
111(d) for existing oil and natural gas sources, i.e., sources for
which owners or operators commence construction, modification, or
reconstruction on or before November 15, 2021 (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''). While the standards in 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 methane 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 that would apply to existing sources within that state
that are not covered by a state plan. In addition, a Federal plan could
apply to facilities located on tribal land that do 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 codified in 40 CFR part 62 (Approval and Promulgation of State
Plans for Designated Facilities and Pollutants) within the relevant
subpart for that state.\63\ 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.
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\63\ 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 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 the EG OOOOc (which would inform the standards to be
developed and codified under 40 CFR part 62). Specifically, we are
proposing amendments to the subpart W calculation methodologies for
natural gas pneumatic devices 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.J.1.a, k, and
m, respectively. These proposed amendments, if finalized, 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 comply with the applicable provisions of
subpart W for sources not subject to NSPS OOOOb or 40 CFR part 62.
1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart W
As further described in section II.A of this preamble, the EPA is
proposing amendments that would ensure that accurate data are being
collected under the rule, improve the accuracy of emissions reported
under part 98, and enhance the overall quality of the data collected
under the GHGRP. Consistent with section II.A.1 of this preamble, we
are proposing to incorporate recent data to update selected subpart W
emission factors. Where emission factors are currently provided in
subpart W for certain emission source types, those emission factors
were based on the best available public data at the time that subpart W
was promulgated. In the years since promulgation of subpart W,
additional data have been collected for some source types as part of
emissions studies, and the EPA has reviewed and evaluated the data in
these studies. Based on those evaluations, the EPA is proposing to
update selected subpart W population emission factors \64\ for natural
gas pneumatic device vents across a variety of industry segments and
equipment leaks from the Onshore Petroleum and Natural Gas Production,
Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural
Gas Distribution industry segments. The EPA is also proposing revisions
to the leaker emission factors for all industry segments conducting
equipment leak surveys to account for differences in the leak detection
methodologies. Consistent with section II.A.2 of this preamble, the EPA
is proposing amendments to improve calculation methodologies for
emissions from natural gas pneumatic pumps,
[[Page 36963]]
centrifugal compressors, reciprocating compressors, equipment leak
surveys, combustion units, and sources that use the acoustic leak
detection method for leak detection. Consistent with section II.A.3 of
this preamble, we are proposing to add calculation and reporting
requirements for ``other large release events,'' which are emission
events that are not sufficiently accounted for using the current
subpart W methodologies, and emissions from uncombusted methane from
compressor engines. We are also proposing to require facilities in the
Onshore Natural Gas Processing industry segment to begin calculating
and reporting emissions from natural gas pneumatic devices and
proposing to require facilities in the LNG Import/Export industry
segment to begin calculating and reporting emissions from acid gas
removal vents. Consistent with section II.A.4 of this preamble, we are
proposing to add or revise reporting requirements to better understand
and characterize the emissions from acid gas removal units, glycol
dehydrator vents, liquids unloadings, atmospheric storage tanks,
associated gas flaring, flare stacks, and equipment leaks, as well as
to better characterize facilities in the Onshore Petroleum and Natural
Gas Gathering and Boosting industry segment. Finally, consistent with
section II.A.5 of this preamble, we are proposing to clarify
calculation and reporting requirements for natural gas pneumatic
devices, natural gas driven pneumatic pumps, blowdown vent stacks,
atmospheric storage tanks (including requirements for open thief
hatches), associated gas venting and flaring, centrifugal and
reciprocating compressors, combustion devices, and facilities in the
Onshore Natural Gas Transmission Pipeline industry segment, in part to
address questions asked by reporters to the GHGRP Help Desk and in
verification correspondence via e-GGRT.
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\64\ When the total emissions from all leaking sources of the
same type are divided by the total count of that source type, then
the resultant factor is referred to as a population emission factor.
When the total emissions from all leaking sources of the same type
are divided by the total count of leaking sources for that source
type, then the resultant factor is referred to as a leaker emission
factor.
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a. Natural Gas Pneumatic Device Vents
Revisions to emission factors. Subpart W 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). 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-2019-0424.
---------------------------------------------------------------------------
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, NSPS OOOOb, and 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. For more information regarding this review, see the document
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 ``subpart W TSD''), available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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\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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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.A.1 of this preamble, we are
proposing to amend the emission factors for the Onshore Petroleum and
Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and
Boosting, Onshore Natural Gas Transmission Compression, and Underground
Natural Gas Storage industry segments. We are also proposing to add
pneumatic device venting as an emission source for the Onshore Natural
Gas Processing industry segment using the same emission factors we are
proposing for the Onshore Natural Gas Transmission Compression and
Underground Natural Gas Storage industry segments, consistent with
section II.A.3 of this preamble.
Intermittent bleed pneumatic devices subject to 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 optical gas imaging (OGI) or other
technologies. As noted in the introduction to section III.J 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 methane and volatile organic compound
(VOC) emission rate of zero. The only 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
under the proposed zero-emission standard and presumptive standard for
these pneumatic devices, compliance with which would require the use of
non-emitting devices. 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 addition, as noted in section
III.J 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
[[Page 36964]]
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, similar to the
2016 amendments to subpart W (81 FR 4987, January 29, 2016), 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.A.2 of this preamble. Specifically, for facilities that would be
required to inspect their intermittent bleed pneumatic devices
requirements under NSPS OOOOb or an approved state plan or the
applicable Federal plan in 40 CFR part 62 (to the extent there are any)
or facilities that elect to conduct routine monitoring surveys of their
existing natural gas intermittent bleed pneumatic devices consistent
with the methods in NSPS OOOOb prior to becoming subject to 40 CFR part
62, we are proposing to provide an alternative calculation methodology
analogous to a ``leaker factor'' approach used for equipment leaks.
Reporters using this calculation methodology would report the total
number of natural gas intermittent bleed pneumatic devices at the
facility, the frequency of monitoring, the number of devices found to
be malfunctioning, and the average time the malfunctioning devices were
malfunctioning. 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-2019-0424.
Hours of operation of natural gas pneumatic devices and natural gas
driven pneumatic pumps. In correspondence with the EPA via e-GGRT,
reporters have indicated that there is confusion over the use of the
term ``operational'' in the definition of variable ``Tt'' in
equation W-1 in 40 CFR 98.233(a) and the term ``in operation'' in the
reporting requirements in 40 CFR 98.236(b)(2). Both the current
emission factors and the proposed updated emission factors described
earlier in this section for natural gas pneumatic devices were
developed by taking both periods of actuation and periods without
actuation into account; \67\ in other words, the emission factors are
population emission factors. To calculate emissions accurately using a
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). Therefore,
consistent with section II.A.5 of this preamble, we are proposing to
revise the definition of variable ``Tt'' in equation W-1 and
the corresponding reporting requirement in 40 CFR 98.236(b)(2) to use
the term ``in service (i.e., supplied with natural gas)'' rather than
``operational'' or ``in operation.''
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\67\ 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-2019-0424.
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Similarly, the population emission factor for natural gas driven
pneumatic pumps was developed using measurements taken during
actuations together with manufacturer data and observed operational
data at facilities (e.g., pump actuation rate).\68\ In other words, the
emission factor represents the average emissions over the period when
the pump is operating, not just the emissions during periods when the
pump was actuating. Therefore, we are also proposing to revise the
definition of variable ``T'' in equation W-2 in 40 CFR 98.233(c)(1) for
natural gas driven pneumatic pumps to use the term ``in service (i.e.,
supplied with natural gas),'' and we are proposing to use that same
term in the corresponding reporting requirement in proposed 40 CFR
98.236(c)(4).
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\68\ The development of the emission factor for natural gas
pneumatic pumps 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-2019-0424.
---------------------------------------------------------------------------
b. Natural Gas Driven Pneumatic Pump Venting
The current procedures in subpart W for calculating and reporting
emissions from natural gas driven pneumatic pump venting are specified
in 40 CFR 98.233(c) and 40 CFR 98.236(c). The inputs to equation W-2 in
40 CFR 98.233(c) are the total number of natural gas driven pneumatic
pumps and average estimated number of hours in the operating year the
pumps were operational. Reporters then report these inputs along with
the emissions under 40 CFR 98.236(c). As the calculated emissions are
vented emissions from natural gas driven pneumatic pumps, the intent is
that the total number of natural gas driven pneumatic pumps should
include only those pumps that are vented directly to the atmosphere
(i.e., uncontrolled). However, based on contact with reporters, we
understand that emissions from some natural gas driven pneumatic pumps
are routed to controls, particularly flares or combustion units. Flared
emissions from natural gas driven pneumatic pumps are not required to
be calculated and reported separately from other flared emissions.
Instead, emission streams from natural gas driven pneumatic 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, emissions from natural gas driven pneumatic 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).
In correspondence with the EPA via e-GGRT, some reporters have
expressed confusion regarding the requirements for natural gas driven
pneumatic pumps that are routed to flares or combustion devices,
particularly between 40 CFR 98.236(c) (for vented emissions) and 40 CFR
98.236(n) or (z) (for flared or combusted emissions, respectively).
Additionally, the counts of controlled natural gas driven pneumatic
pumps currently are not reported separately from counts of vented
natural gas driven pneumatic pumps under 40 CFR 98.236(c), and the
emissions currently reported from flares and combustion units are not
attributed specifically to natural gas driven pneumatic pumps. This
lack of reported information leads to uncertainty in verification of
reported data when there are significant changes in reported data at a
facility from one year to the next, which can result in additional
communication with the reporter to clarify whether or not the changes
are an error. The lack of reported information also means changes in
the trends related to implementation of such controls relative to
trends in overall use of natural gas driven pneumatic pumps in the
petroleum and natural gas systems source category would be difficult to
track. In addition, there are other rules
[[Page 36965]]
that require the control of pneumatic pumps (e.g., NSPS OOOOa), so we
expect that there will be an increase in the number of natural gas
driven pneumatic pumps that are routed to controls as more facilities
become subject to those rules.
Thus, consistent with section II.A.2 of this preamble, we are
proposing to revise 40 CFR 98.233(c) to clarify requirements for
calculating emissions from both natural gas driven pneumatic pumps that
are vented to the atmosphere and controlled natural gas driven
pneumatic pumps that are consistent with the intent of the current
rule. Specifically, we are proposing to revise 40 CFR 98.233(c)
introductory text and the definitions of the terms ``Count'' and ``T''
in equation W-2 to further clarify that the provisions of 40 CFR
98.233(c)(1) and (2) should only be used to calculate emissions from
natural gas driven pneumatic pumps venting directly to the atmosphere.
We are proposing to add 40 CFR 98.233(c)(3) to specify that if the
emissions are flared, then flared emissions would be calculated using
the method for flare stack emissions in 40 CFR 98.233(n) and reported
as flare stack emissions under 40 CFR 98.236(n). If emissions are
routed to a combustion device, then emissions would be calculated using
the methods for combustion devices as specified in 40 CFR 98.233(z) and
reported as specified in 40 CFR 98.236(z). Finally, if the emissions
are routed to vapor recovery and are not subsequently routed to a
combustion device, then we are proposing that reporters would not
calculate or report emissions. If a natural gas driven pneumatic pump
is 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, the reporter would calculate emissions using all applicable
procedures and adjust the number of hours used in equation W-2 as
needed. We request comment on whether pneumatic pumps are routed to
vapor recovery systems and whether there are other controls that should
be addressed with these new provisions. In addition, we request comment
on whether flared emissions associated with natural gas driven
pneumatic pumps should continue to be reported as flare stack emissions
under 40 CFR 98.236(n) or should be reported in the natural gas driven
pneumatic pumps emission source under 40 CFR 98.236(c).
We are also proposing to add new reporting elements in 40 CFR
98.236(c) to align with the proposed clarifications to the emission
calculation procedures. Specifically, we are proposing to expand the
current requirement to report the total count of natural gas driven
pneumatic pumps to three separate counts: the number of natural gas
driven pneumatic pumps that are vented directly to atmosphere (i.e.,
uncontrolled); the number of natural gas driven pneumatic pumps that
are routed to a flare, combustion, or vapor recovery (i.e.,
controlled); and the total number of natural gas driven pneumatic pumps
at the facility. The total count of pneumatic pumps is a proposed
reporting element along with the counts of uncontrolled and controlled
pneumatic pumps because the total count would not always be equal to
the sum of the other two counts. For example, a reporter that switches
from one scenario to another during a year for a particular pneumatic
pump (e.g., from vented to flared) would include that pneumatic pump in
the count of pumps that vent directly to atmosphere and in the count of
pumps that are routed to flares, but that pneumatic pump would only be
counted once towards the total number of pneumatic pumps. The number of
pneumatic pumps vented directly to the atmosphere would be equal to the
``Count'' in equation W-2 and would be used in the verification of
annual reports to the GHGRP. The total count of pneumatic pumps at the
facility and the number of pneumatic 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 pumps are controlled across the industry, how often pneumatic
pumps are both controlled and vented directly to the atmosphere in the
same year, and how the use of controls for pneumatic pumps changes
across multiple years.
c. Acid Gas Removal Vents
Acid Gas Removal Units at LNG Import/Export Facilities. Emissions
from acid gas removal units are currently reported for three industry
segments: Onshore Petroleum and Natural Gas Production, Onshore Natural
Gas Processing, and Onshore Petroleum and Natural Gas Gathering and
Boosting. However, prior to becoming LNG, natural gas is treated to
specifications more stringent than pipeline quality natural gas to
remove nearly all of the heavy hydrocarbons, mercury, CO2,
sulfur compounds, and other impurities to prevent problems with the
liquefaction process (e.g., CO2 and hydrogen sulfide can
cause freezing and plugging in downstream units once the gas is
liquefied). Therefore, liquefaction plants at LNG export facilities may
include acid gas removal units, and those emissions are not currently
reported to the GHGRP if the acid gas removal unit vents are vented
directly to the atmosphere. Emissions from acid gas removal unit vents
that are routed to flares or thermal oxidizers that meet the subpart W
definition of flare in 40 CFR 98.238 are reported under the flare
stacks emission source, but they are not characterized as acid gas
removal emissions. LNG export facilities may receive natural gas that
has already been treated in a natural gas processing plant as well as
raw material from dedicated gas fields, so the emissions from acid gas
removal units at these facilities can comprise a significant portion of
the facility's emissions if the gas received at an LNG export facility
has a relatively high CO2 content.\69\
---------------------------------------------------------------------------
\69\ 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-2019-0424.
---------------------------------------------------------------------------
Therefore, consistent with section II.A.3 of this preamble, the EPA
is proposing to revise 40 CFR 98.232(h) and 40 CFR 98.236(a)(7) to add
acid gas removal vents to the list of emission sources for which
facilities in the LNG Import/Export industry segment must calculate and
report emissions. Facilities in this industry segment with an acid gas
removal unit would use one of the four calculation methods currently
provided in 40 CFR 98.233(d) and report emissions as currently provided
in 40 CFR 98.236(d). Facilities in this industry segment without an
acid gas removal unit would only be required to indicate that in their
report. We request comment on whether all four calculation methods
currently provided in 40 CFR 98.233(d) are appropriate for facilities
in the LNG Import/Export industry segment and if not, how specific
calculation methods could be adjusted to be more applicable to this
industry segment. In addition, we request comment on whether there are
other emission sources at LNG Import/Export facilities with significant
emissions that should be added to subpart W (e.g., glycol dehydrators),
as well as whether there are other industry segments with acid gas
removal units that are not reported and make up a significant portion
of facility emissions.
Calculation method 4 reporting. Reporters with acid gas removal
units that elect to calculate emissions using Calculation Method 4 are
required to report several data elements that are inputs to the
simulation software package that is used to calculate
[[Page 36966]]
emissions. One of the required inputs to report is the solvent weight,
in pounds per gallon (40 CFR 98.236(d)(2)(iii)(L)). A variety of
different solvents may be used in an acid gas removal unit (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 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 requirement to report
solvent weight with a requirement to report the solvent type and, for
amine-based solvents, the general composition. Reporters would choose
the type/general composition option from a pre-defined list that most
closely matches the solvent type and composition used in their acid gas
removal unit. 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.'' 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 acid gas
removal unit 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 acid gas removal
vent emissions, consistent with section II.A.4 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 streamline and improve implementation
compared to the current requirement of reporting an exact value for
solvent weight, consistent with section II.B.3 of this preamble.
d. 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 40 CFR
98.233(e) based on the unit's annual average daily natural gas
throughput. For 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 40 CFR 98.233(e)(2).
For 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 40 CFR 98.233(e)(1), which require modeling GHG
emissions using a software program (e.g., AspenTech HYSYS[supreg] \70\
or GRI-GLYCalcTM \71\).
---------------------------------------------------------------------------
\70\ AspenTech HYSYS[supreg] software available from AspenTech
website (https://www.aspentech.com/).
\71\ GRI-GLYCalcTM software available from Gas
Technology Institute website (https://sales.gastechnology.org/).
---------------------------------------------------------------------------
The EPA has reviewed the subpart W glycol dehydrator data and
reporting requirements in 40 CFR 98.236(e) and has made a preliminary
determination that additional information would help to more accurately
characterize emissions from glycol dehydrators with an annual average
daily natural gas throughput greater than or equal to 0.4 MMscf per
day. Specifically, the EPA's review found no strong correlations
between glycol dehydrator emissions and the operating parameters
currently reported under 40 CFR 98.236(e)(1). This assessment is
consistent with the results of an analysis provided to the EPA by GPA
Midstream, which indicated that the correlations between vent gas flow
rate, glycol circulation rate, and glycol pump type provided the most
accurate approximation of dehydrator emissions.\72\ While subpart W
does currently collect information on glycol pump type and circulation
rate for each modeled glycol dehydrator with an annual average daily
natural gas throughput greater than or equal to 0.4 MMscf per day,
reporters are not asked to report any characteristics of their units'
flash tank and still vents, including vent gas flow rate. As such, the
EPA is not able to review historical subpart W dehydrator data to
verify GPA Midstream's suggested correlation between vent gas flow
rate, glycol circulation rate, and glycol pump type. Therefore, the EPA
is proposing to add new reporting requirements to 40 CFR 98.236(e)(1),
consistent with section II.A.4 of this preamble. The following new data
elements are proposed to be added to subpart W for glycol dehydrators
with an annual average daily natural gas throughput greater than or
equal to 0.4 MMscf per day:
---------------------------------------------------------------------------
\72\ GPA Midstream Association. Presentation slides regarding
three alternatives for possible development of emission factors for
large glycol dehydrators. November 20, 2019. Available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
Flash tank control technique
Regenerator still vent control technique
Flash tank vent gas flow rate (standard cubic feet per hour
(scfh))
Regenerator still vent gas flow rate (scfh)
Concentrations of CH4 and CO2 in flash
tank vent gas (mole fraction)
Concentrations of CH4 and CO2 in
regenerator still vent gas (mole fraction)
Type of stripping gas used
Flow rate of stripping gas (standard cubic feet per minute
(scfm))
These proposed additional data elements are intended to allow the
EPA to derive a correlation between vent flow rate and absorbent
circulation rate and better characterize emissions from glycol
dehydrators with an annual average daily natural gas throughput greater
than or equal to 0.4 MMscf per day. Further, the EPA is proposing to
require separate reporting of emissions for a modeled glycol
dehydrator's still vent and flash tank vent. These vents
[[Page 36967]]
often use different control techniques, so requiring the emissions from
these vents to be reported separately would ensure that future analyses
accurately characterize the emissions. The proposed data elements are
included in the output files from the modeling software used for glycol
dehydrators and are, therefore, not expected to be difficult for
reporters to implement.
Additionally, in correspondence with the EPA via e-GGRT, some
reporters have expressed confusion regarding the requirements for
glycol dehydrators emissions that are routed to vapor recovery and
subsequently routed to a flare or regenerator firebox/fire tubes. As
such, the EPA is proposing edits to the vapor recovery calculation
methodology of 40 CFR 98.233(e)(5) (proposed to be moved to 40 CFR
98.233(e)(4)) to clarify that unrecovered emissions that are not routed
to flares or regenerator fireboxes/fire tubes should be reported as
emissions vented directly to atmosphere, while emissions that are
routed to flares or regenerator fireboxes/fire tubes should be reported
as flared emissions from dehydrators. Along with the proposed
amendments to 40 CFR 98.233(e)(6) (proposed to be moved to 40 CFR
98.233(e)(5)) for calculating emissions from flares or regenerator
fireboxes/fire tubes (discussed in section III.J.1.i of this preamble),
the EPA seeks to enhance the overall quality of the data collected
under the GHGRP, consistent with section II.A.5 of this preamble.
e. Liquids Unloading
Subpart W currently requires reporting of emissions from well
venting for liquids unloading. Facilities 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)). Under the
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 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.\73\ 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.
---------------------------------------------------------------------------
\73\ 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-2019-0424.
---------------------------------------------------------------------------
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 significant
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.A.4 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 that reporters would report emissions from automated
unloadings separately from manual unloadings. 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
an 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 that reporters would identify
the type of non-plunger lift unloading as an automated or manual non-
plunger lift unloading and that reporters would report emissions and
activity data separately for each unloading type. In addition, for all
non-plunger lift unloadings, the EPA is proposing to add requirements
in 40 CFR 98.236(f)(2)(ix) (proposed to be moved to 40 CFR
98.236(f)(2)(xi)) to report the average well depth for all wells in the
sub-basin (WDp) and the average shut-in pressure or surface
pressure for wells with tubing production, or average casing pressure
for wells with no packers for all wells in the sub-basin
(SPp).
For plunger lift unloadings that use Calculation Method 3 in 40 CFR
98.233(f)(3), the EPA is proposing that reporters would identify the
type of plunger lift unloading as an automated or manual plunger lift
unloading and that reporters would report emissions and activity data
separately for each unloading type. In addition, for all plunger lift
unloadings, the EPA is proposing to add requirements in 40 CFR
98.236(f)(2)(x) (proposed to be moved to 40 CFR 98.236(f)(2)(xii)) to
report the average tubing depth to plunger bumper for all wells in the
sub-basin (WDp) and the average flow-line pressure for all
wells in the sub-basin (SPp). Finally, for all unloadings
that use Calculation Method 2 or 3, the EPA is proposing to add
requirements in 40
[[Page 36968]]
CFR 98.236(f)(2)(ix) and (x) to report the average flow-line rate of
gas for all wells in the sub-basin (SFRp) and cumulative
number hours that all wells in the sub-basin are left open to the
atmosphere during unloading events (HRp,q), respectively.
f. Blowdown Vent Stacks
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 that there is some confusion regarding the
reference to ``distribution'' pipelines in the descriptions of the
``facility piping'' and ``pipeline venting'' categories because
compressor stations are not associated with distribution pipelines.
Therefore, the EPA is proposing to revise the descriptions of the
facility piping and pipeline venting categories to reduce confusion
regarding which equipment or event type category is appropriate for
each blowdown, consistent with section II.A.5 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.
Conversely, 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 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 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 phrase ``located within a facility boundary'' generally
refers to being part of the facility as defined by the existing
provisions of subpart A or subpart W, as applicable. 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.
g. Atmospheric Storage Tanks
Open thief hatches. Facilities in the Onshore Petroleum and Natural
Gas Production and Onshore Petroleum and Natural Gas Gathering and
Boosting industry segments are 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''). 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 pressure on the tank while
preventing excessive vacuum from collapsing the tank. 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
(40 CFR 98.233(j)(4)) and storage tanks with a flare (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 (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 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 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 emissions from open thief hatches on
atmospheric storage tanks may not be accurately portrayed in subpart W,
as many reporters claim 100 percent capture efficiency from vapor
recovery systems and flares. In order to alleviate any reporting
confusion, the EPA is proposing several clarifying edits to 40 CFR
98.233(j)(4) and (5), consistent with section II.A.5 of this preamble.
We are proposing to specifically state in each paragraph 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 flare feed gas volumes. Reduced capture
efficiency may occur during periods when the control device is not
operating or is bypassed and at times 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.
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 tanks with open or unseated thief hatches within
the reporting year, as well as the total volume of gas vented through
the open or unseated thief hatches. 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.A.4 of this
preamble.
Malfunctioning dump valves and atmospheric storage tanks with
flares. 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 40 CFR 98.233(j)(6) and
use equation W-16 to calculate emissions from occurrences of gas-
[[Page 36969]]
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. However, the definition
of the variable ``En'' in equation W-16 does not include the
procedure to be used for emissions from malfunctioning dump valves and
atmospheric storage tanks that are flared. In order to address any
confusion for reporters, the EPA is proposing to amend the definition
of the variable ``En'' in equation W-16 to include flared
storage tank emissions as determined in paragraph 40 CFR 98.233(j)(5),
consistent with section II.A.5 of this preamble. The EPA is also
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) through (5). We are also proposing to replace the
``n'' and ``p'' 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) through (5).
Composition of hydrocarbon liquids. 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
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, 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. Consistent with section II.A.4 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.
h. Associated Gas Venting and Flaring
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 requires reporters to calculate annual emissions from
associated gas venting and flaring using equation W-18, which uses the
gas-to-oil ratio (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.
As discussed further in section III.J.1.i 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. One of the proposed amendments would provide for the use of
continuous flow measurement devices for the purposes of calculating
flared emissions. Similarly, for associated gas venting emissions, we
are proposing provisions to specify that if a continuous flow
measurement device is present, it must be used to determine the volume
of gas vented rather than equation W-18. We are proposing corresponding
reporting requirements for associated gas venting emissions, including
requiring an indication of whether a continuous flow monitor or
continuous composition analyzer was used and the flow-weighted mole
fractions. Finally, we are proposing to specify that if all of the
volumetric emissions from associated gas venting and flaring in the
sub-basin were determined using a continuous flow measurement device
rather than equation W-18 (i.e., equation W-18 was not used for any
wells in the sub-basin), then reporting of the GOR, the volume of oil
produced, and the volume of gas sent to sales for wells with associated
gas venting or flaring is not required for that sub-basin.
Oil and gas volumes. As noted previously in this section, subpart W
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
reported, there seems to be confusion among some reporters regarding
the inputs to these equations. For example, for some reporters, when
the reported volume of gas sent to sales during time periods in which
associated gas was vented or flared under 40 CFR 98.236(m)(6) is summed
across all sub-basins at the facility, the total is the same as the
total volume of gas sent to sales for the facility reported under 40
CFR 98.236(aa)(1)(i)(B). If these reporters are accurately reporting
the volume of gas sent to sales 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). Consistent with
section II.A.5 of this preamble, these proposed amendments would reduce
reporter confusion regarding the volumes that should be used in the
[[Page 36970]]
emissions calculations and the volumes that should be reported.
i. 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.\74\
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\74\ Flare stacks are an emission source type 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.
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Total CO2, CH4, and N2O emissions
from each flare 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 must also separately calculate the
flared emissions from several types of emission sources.\75\ The
methodology for calculating source-specific flared emissions is
specified in the applicable paragraph of 40 CFR 98.233 for each source
type. The procedures in the source-specific paragraphs of the rule
cross-reference the calculation procedures in 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,
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 40 CFR 98.233(e)(1) through (5). Since
source-specific flared emissions often are a portion of the total
emissions from a flare, 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 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.
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\75\ Facilities 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,
well venting during completions and workovers with hydraulic
fracturing, gas well venting during completions and workovers
without hydraulic fracturing, onshore production and onshore
petroleum and natural gas gathering and boosting storage tanks,
transmission storage tanks, well testing venting and flaring, and
associated gas venting and flaring.
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This calculation and reporting paradigm often means zero mass
emissions are reported for the flare because all of the mass emissions
are reported as flared emissions from other source types. However, even
when the only streams routed to a flare are from source types that are
subject to flared emissions reporting, 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 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 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 40 CFR 98.236(n)(12), only the flare ID and the
measured CO2 emissions must be reported.
Reporting requirements for flared emissions. Many reporters have
provided information through the GHGRP Help Desk and in correspondence
with the EPA via e-GGRT indicating that reporters are not interpreting
the reporting requirements as written and as the EPA intended for
flares that receive gas from sources that are subject to source-
specific flared emissions reporting (e.g., atmospheric tanks). A key
misconception is that the adjustment requirement in 40 CFR 98.233(n)(9)
applies to all flare data, not just the mass emissions (as intended).
Thus, some reporters provide 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 their annual GHG
report. Some reporters have also indicated that it is confusing to
report activity data for a flare in one table in the reporting form
(i.e., Table N.1), but to report the emissions in different tables;
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. One industry stakeholder, GPA Midstream, also suggested
that flare activity data should be reported in the same manner that
flared emissions are reported. In other words, instead of providing a
single comprehensive record of the activity data per flare as is
currently required by 40 CFR 98.236(n), the activity data for flared
streams for a particular emission source (e.g., associated gas or
atmospheric storage tanks) should be reported with the flared emissions
for the same emission source type. According to GPA Midstream, this
reporting approach would be simpler and easier for reporters to follow
than the current requirements.\76\ We reviewed the flare reporting
requirements based on this feedback, and we are proposing several
revisions to the reporting requirements to improve the quality of the
reported data, consistent with section II.A.4 of this preamble.
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\76\ 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-2019-0424.
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First, we are proposing to modify the reporting requirements so
that the existing requirements in 40 CFR 98.236(n) would apply only to
flares that receive gas from miscellaneous flared sources. The activity
data to report would be limited to the streams from the miscellaneous
flared sources, and the CO2, CH4, and
N2O emissions to report would be the emissions that are
calculated from combustion of the same streams. In addition, we would
add comparable activity data reporting requirements to the reporting
required for all of the source types for which flared emissions
reporting is currently required (e.g., 40 CFR 98.236(e) for
dehydrators, 40 CFR 98.236(g) for completions and workovers with
hydraulic fracturing). The activity data reporting would be on the same
basis as the emissions reporting. For example, activity data for glycol
dehydrators with an annual average daily natural gas throughput greater
than or equal to 0.4 MMscf per day would be related to the flared
streams from each dehydrator because flared emissions are reported per
dehydrator. Activity data to be
[[Page 36971]]
reported for associated gas streams, on the other hand, would be
aggregated over all associated gas streams routed to flares in a sub-
basin because flared associated gas emissions are reported per sub-
basin. In addition, for completions and workovers with hydraulic
fracturing, flaring during the initial flowback period may not be
possible; therefore, some of the wells that report as part of a
``flared'' well type combination because most of the gas is flared may
also include emissions from gas that is vented before flaring begins.
To improve our understanding of the characteristics of the ``flared''
emissions from completions and workovers with hydraulic fracturing, we
are proposing that reporters would indicate in 40 CFR 98.236(g)(10)(i)
whether the total emissions reported under 40 CFR 98.236(g)(8) and (9)
include emissions from venting during the initial flowback period.
These proposed amendments would better align the flared emissions and
activity data for source types for which flared emissions reporting is
currently required.
Second, in the current rule, 40 CFR 98.236(n)(7) and (8) require
reporting of the CH4 and CO2 mole fractions in
feed gas that are used in equations W-19 and W-20 to calculate total
emissions from a flare. The intent was for reporters to provide the
average values used to calculate total emissions from the flare.
However, the rule language is not clear on this point, and it appears
some reporters have interpreted these data elements in different ways.
It appears that one common interpretation is to report the mole
fraction for the emissions source type with the most flared emissions.
Because that interpretation does not align with the EPA's intent,
clarification of this reporting requirement is needed to improve the
verification process. Thus, we are proposing to modify these reporting
elements, both in 40 CFR 98.236(n) (proposed to be moved to 40 CFR
98.236(n)(1)(ix) and (x)) and for all the proposed activity data
reporting elements for individual source types that are subject to
source-specific flared emissions reporting as described above.
Specifically, we are proposing to require the flow-weighted annual
average mole fraction of CH4 over all streams from a
particular emission source type that are used in equation W-19 to
calculate the reported flared CH4 emissions from that
emission source type (and used in equation W-20 to calculate
CO2 emissions). For example, if a flare receives gas from an
acid gas removal vent and a blowdown vent stack, both of which are
miscellaneous flared sources, then the CH4 mole fraction to
report should be the flow-weighted annual average value from the acid
gas removal vent and each blowdown through the blowdown vent stack. The
CO2 mole fractions to report would also be a flow-weighted
annual average determined in the same manner.
Third, reporters are required to use equation W-40 to calculate
N2O emissions from flares. Variables in the equation are the
volume of gas routed to the flare and the HHV of the gas. The volume of
gas routed to the flare must be reported, but the HHV is not reported.
As a result, when reported N2O emissions differ
significantly from the amount that would be expected if using the
default HHV, it can be difficult for the EPA to determine whether the
reported emissions are an error or if the difference is due to the use
of a site-specific HHV. To improve the verification process and
potentially reduce the amount of communication with reporters via e-
GGRT, we are proposing to add a reporting element that would require
reporters to indicate whether each reported N2O value is
based on the default HHV, a site-specific HHV(s), or both the default
and site-specific HHVs. The proposed reporting element would be added
in 40 CFR 236(n)(4)(iv) for miscellaneous flared sources, and it would
be included as one of the proposed activity data reporting elements for
each of the other source types that are subject to source-specific
flared emissions reporting. Providing an option to indicate that both
types of HHVs are used is needed because some reported flared
N2O emissions are aggregated values over all flares in a
sub-basin or county (e.g., for atmospheric tanks), and a reporter may
choose to use different methods for the flares in each sub-basin or
county. In addition to improving the verification process, knowledge of
site-specific HHVs would allow the EPA to assess how well the default
HHV characterizes flared gas streams in different industry segments and
basins.
Fourth, an additional finding from the currently reported data is
that a number of 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 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. To
help clarify the source types that are generating large amounts of
flared gas, we are proposing in 40 CFR 98.236(n)(1)(v) 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 miscellaneous
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 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 example, one potential additional
reporting element could be a requirement to describe the primary source
of miscellaneous flared emissions for any flare that reports
CO2 emissions greater than an amount that would be
determined if such a reporting requirement were finalized.
Finally, one objective of the current flare reporting requirements
is to obtain information on the total number of flares and their
operating characteristics. If the proposed changes to flare activity
data requirements as described previously in this section were
finalized, then additional amendments to reporting requirements would
be needed to continue collecting flare-specific information. Thus, we
are proposing to require reporting of a list of all flare IDs per
facility and add reporting for a series of flare-specific data
elements. One of the proposed flare reporting elements is the total
volume of
[[Page 36972]]
gas routed to the flare. This information is consistent with current
reporting requirements and would be helpful in conducting verification
of other reported flare data because the sum of the total volume from
all flares should be equal to the sum of the disaggregated volumes
reported for all flared emissions source types. The total volumes per
flare also would provide information on the range of flare sizes in
different industry segments and would be useful in analyses for
potential future policy decisions related to flares. Another of the
proposed flare reporting elements is a list of the subpart W emission
source types that routed emissions to the flare stack. This proposed
data element would improve verification of other reported flare data as
well as provide information regarding the types of sources that are
combined and routed to the same flare. We are also proposing a few new
flare-specific reporting elements to help us better understand the
state of flaring in the industry, 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) 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).
Further, researchers conducting remote sensing tests of emissions from
flares have reported detecting much larger quantities of emissions from
un-lit flares than is evident from the GHGRP data. To help us better
understand the prevalence of emissions from un-lit flares, we are
proposing to add requirements to report an indication of whether the
flare has a continuous pilot or autoigniter, whether the presence of
flame is continuously monitored if the flare has a continuous pilot,
and an indication of how the reporter identifies periods when the flare
is not lit if the flare does not have a continuous pilot. These
proposed data elements would be added in 40 CFR 98.236(n). This
paragraph of subpart W would be rearranged into two subparagraphs. The
first subparagraph, 40 CFR 98.236(n)(1), would include the current
activity data and emissions data reporting elements but would be
revised to be specific to miscellaneous flared sources (as discussed
previously), and the proposed flare-specific reporting elements would
be added in the second subparagraph, 40 CFR 98.236(n)(2).
Definition of flare stack emissions. In response to a verification
message in e-GGRT, one reporter noted that the 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. However, the current definition,
which was added to the 2010 Final Revisions 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 proposed rule, 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 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 NOX under certain operating conditions in
the flare. 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'' 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.
Calculation methodology for flared emissions. In addition to
proposing changes to the flare reporting requirements as discussed
above, we are also proposing to clarify language in the emission
calculation procedures of 40 CFR 98.233(n) that we believe may be
ambiguous for flares that do not have CEMS, consistent with section
II.A.5 of this preamble. The procedures for determining the volume and
composition of gas routed to flares for use in the emission calculation
equations for a particular emission source type are currently specified
in two places for each source type. Each source type-specific paragraph
in 40 CFR 98.233 specifies calculation methodologies for that emissions
source type, as do 40 CFR 98.233(n)(1) and (2). The procedures in the
source type-specific requirements specify only that the volume and
composition of the flared gas are to be determined using the procedures
for estimating vented emissions from that source type, but they also
cross-reference the calculation method in 40 CFR 98.233(n) for
determining the emissions from the flaring of that gas stream. However,
40 CFR 98.233(n)(1) and (2) specify that if continuous flow or
composition measurement devices are used on the gas to the flare, then
data from those devices must be used to calculate emissions; otherwise,
estimates may be used. The intent is that the procedures in 40 CFR
98.233(n) should take precedence, but this may not be clear to all
reporters. Additionally, the procedures for continuous measurement
devices in 40 CFR 98.233(n)(1) and (2) refer to devices ``on the
flare'' or ``on gas to the flare.'' The intent is that the procedures
should apply to devices regardless of whether they are on a stream
routed from a single emission source or on a stream routed to a flare
that includes streams combined from multiple emission source types, but
this is not explicitly described. A third potential ambiguity is that
procedures in 40 CFR 98.233(n)(1) and (2) do not specify how to
disaggregate data collected with a continuous measurement device when
the device measures a combined stream from more than one emission
source type.
To clarify these requirements, we are proposing to specify all of
the potential options for determining volume and composition of gas to
the flare(s) in the applicable sections of 40 CFR 98.233 for each of
the emission source types that have flared emissions reporting
requirements. In general, the volume of gas would be determined by a
continuous flow measurement device, if available, or using the methods
for determining vented emissions for the applicable emission source
type. If the measured volume includes flow from multiple source types
routed to the same flare, reporters would use process knowledge and
best available data to determine the portion of the total flow
[[Page 36973]]
from each emission source type.\77\ Similarly, the composition of the
gas from the emission source type would be determined by a continuous
composition analyzer, if available, or using the methods for
determining the composition of the vented emissions for the applicable
emission source type. Alternatively, if multiple source types are
routed to one flare and the gas routed to the flare from each of those
source types is expected to have similar compositions, the reporter
could measure the composition of the total gas to the flare using a
continuous composition analyzer just upstream of the flare and apply
the results to each of the applicable source types. The source-specific
sections of 40 CFR 98.233 would then cross-reference only 40 CFR
98.233(n)(3) through (8) for the applicable calculation equations and
procedures for determining combustion efficiency, converting volumetric
emissions to mass emissions, and the separate procedures that apply if
a CEMS is used on gases from the flare. As part of this proposed
amendment, we would also remove 40 CFR 98.233(n)(9); with these
proposed calculation methodology clarifications and the reporting
clarifications described earlier in this section, a general direction
to correct flare emissions to avoid double counting would no longer be
necessary (however, a provision specifically to avoid double counting
of CO2 emissions from acid gas removal units that route
emissions to a flare would still be needed, as discussed later in this
section). We recognize that the proposed changes introduce some
repetition to the regulatory text overall because the requirements for
each emission source type are similar. However, clearly describing the
applicable procedures for each source type separately rather than
trying to generally describe a single set of consolidated procedures
would make the rule easier for reporters to understand, and we request
comment on whether the proposed changes achieve this goal.
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\77\ The proposed revisions to 40 CFR 98.233(n)(1) would remove
``company records'' from the existing list of information upon which
engineering calculations may be based. In this instance, the use of
``company records'' was intended to refer generally to facility
records rather than the specific type of records as defined in 40
CFR 98.3, and we expect that general facility records are covered by
the proposed inclusion of process knowledge and best available data.
Therefore, we are proposing to remove the defined term ``company
records'' solely to avoid confusion for reporters; this amendment is
not intended to indicate a change in the engineering calculations.
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Calculation methodologies for flared emissions from acid gas
removal vents. We are also proposing source type-specific provisions
for calculating and reporting emissions from acid gas removal vents
routed to flares that are related to the proposed calculation
methodology clarifications described earlier in this section,
consistent with section II.A.5 of this preamble. Reporters are
currently required to report the CO2 removed from the
natural gas as CO2 emissions from acid gas removal vents,
and that quantity is not affected (i.e., the CO2 is not
converted to another compound) when the acid gas vent stream is routed
to a flare, engine, or sulfur recovery plant. Therefore, the current
rule does not require reporters to separate emissions vented directly
to the atmosphere from emissions routed through a flare, engine, or
sulfur recovery plant. Instead, as noted earlier in this section, 40
CFR 98.233(n)(9) specifies that the total CO2 for a flare
that receives gas from acid gas removal vents must be adjusted downward
by the amount of the CO2 emissions that are calculated for
those acid gas removal vents. In other words, the CO2
emissions that are calculated for the acid gas removal vents are
reported under 40 CFR 98.236(d) and not under 40 CFR 98.236(n).
Because the reporting of emissions from acid gas removal vents
routed to a flare is addressed differently in the current rule from the
reporting of flared emissions for all other source types, we are
proposing amendments for acid gas removal vents routed to flares that
are slightly different than the proposed amendments for other sources.
First, as noted previously in this section, we are proposing to remove
40 CFR 98.233(n)(9) because it would be unnecessary for other source
types in light of the other amendments previously described. However,
for acid gas removal vents routed to flares, an adjustment would still
be necessary for CO2 emissions. Therefore, we are proposing
to add provisions in 40 CFR 98.233(d)(12) for calculating emissions
from acid gas removal vents routed to flares (as described in more
detail in the next paragraph) and proposing to add a clarification to
the requirement to report CO2 emissions from flare stacks
(40 CFR 98.236(n)(9), proposed to be moved to 40 CFR 98.236(n)(1)(xi))
indicating that the reported CO2 emissions should not
include emissions from acid gas removal vents reported under 40 CFR
98.236(d)(1)(v) to prevent double counting of emissions.
Second, we reviewed the calculation methods for acid gas removal
vents and flares, and we are proposing amendments to more closely align
the methods for acid gas removal vents routed to flares. For acid gas
removal vents, Calculation Method 1 (40 CFR 98.233(d)(1)) is required
to be used if a vent has a CEMS installed, and Calculation Method 2 (40
CFR 98.233(d)(2)) is required to be used if a vent has a continuous
flow monitor. If there is no CEMS or flow monitor installed, then
reporters currently must use Calculation Methods 3 or 4 (40 CFR
98.233(d)(3) or (4), which are estimation methods based on the volume
of natural gas treated and the acid gas contents of the inlet and
outlet natural gas. However, because these are estimation methods
rather than methods based on measurements, the EPA has found through
the verification process and correspondence with reporters via e-GGRT
that these methods can sometimes result in estimated volumetric
CO2 emissions from acid gas removal vents routed to a flare
that are greater than the reported total volume of gas routed to that
flare. Therefore, we are proposing new provisions in 40 CFR
98.233(d)(12) for reporters routing acid gas removal vents to flares.
The first set of amendments would apply to acid gas removal vents that
are routed to any dedicated flare as well as acid gas removal vents
comingled with emissions from other source types and routed to flares
with no continuous monitors for either the flow or composition of the
comingled gas stream. In either of these cases, reporters would
continue to calculate CO2 emissions using one of the
Calculation Methods 1 through 4, as applicable for the type of
monitoring available, and would continue to report those emissions
under 40 CFR 98.236(d) rather than 40 CFR 98.236(n). Reporters would
also incorporate the flow rate and composition of the acid gas removal
vent stream into the calculation of total flare emissions from
miscellaneous flared sources. For acid gas removal vent streams
comingled with emissions from other source types and routed to flares
with continuous monitoring of the flow and/or composition of the
comingled gas stream, we are proposing that reporters would first
determine the total emissions from the flare stacks and then use site-
specific engineering estimates based on best available data to estimate
the portion of the total flared CO2 emissions that is from
the acid gas removal vents. In this case, we are proposing that
reporters would select ``Routed to a flare [Sec. 98.233(d)(12)(ii)]''
as the calculation method. We are also proposing new reporting
requirements for acid gas removal vents routed to flares; in addition
to the current requirements to report the CO2 emissions
under 40 CFR 98.236(d)(1)(v),
[[Page 36974]]
we are proposing to add the identification of the flare to which the
acid gas removal vent is routed.
j. 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 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. 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.
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.
Subpart W 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 defines the following ``compressor
modes'': operating-mode (for both centrifugal and reciprocating
compressors), standby-pressurized-mode (for reciprocating compressors
only \78\), 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.
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\78\ Currently, subpart W does not require measurements for
centrifugal compressors in standby-pressurized-mode and therefore
does not define this mode for centrifugal compressors.
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For centrifugal compressors, subpart W 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 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.
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 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. This has led to confusion from reporters regarding
how to report the data from the measurements performed. To address this
issue, we are proposing to add standby-pressurized-mode to the defined
modes for centrifugal compressors (40 CFR 98.238) and require
measurement of volumetric emissions from the wet seal oil degassing
vent and volumetric emissions from blowdown valve leakage through the
blowdown vent when the compressor is found in this mode (40 CFR
98.233(o)(1)(i)(C) as proposed), consistent with sections II.A.2 and
II.A.5 of this preamble.
Second, dry seals on centrifugal compressors were not included in
the 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, dry seals may still
contribute to centrifugal compressor emissions. Additionally, the
measurement crew will already be at the centrifugal compressor to make
the ``as found'' measurement for blowdown valve leakage. Therefore, to
better characterize the emissions from dry seal centrifugal
compressors, we are proposing to add dry seal vents to the defined
compressor sources for centrifugal compressors (40 CFR 98.238) and
require measurement of volumetric emissions from the dry seal vents in
both operating-mode and in standby-pressurized-mode (40 CFR
98.233(o)(2)(iii) as proposed), consistent with section II.A.2 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. Screening methods
may also be used to determine if a quantitative measurement is
required. Acoustical screening or measurement methods are not
applicable to dry seal vents because these emissions are not a result
of through-valve leakage. These proposed revisions include a proposed
new reporting requirement 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.\79\ The inclusion of this compressor mode-source combination
would more accurately reflect compressor emissions, consistent with
section II.A.2 of this preamble. Furthermore, the measurement crew will
already be at the compressor to make the ``as found''
[[Page 36975]]
measurement for blowdown valve leakage and several reporters already
make these measurements.
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\79\ 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-2019-0424.
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Fourth, 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 greater flexibility and
improved clarity of the wet seal oil degassing provisions consistent
with section II.A.2 of this preamble.
Fifth, we are proposing to remove acoustic leak detection from the
screening and measurement methods allowed for manifolded groups of
compressor sources. As noted in 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.A.2 of this preamble.
Sixth, 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.A.5 of 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) 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).
In addition to these proposed revisions to the ``as found''
measurement requirements, we are also 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 Petroleum and Natural
Gas Gathering and Boosting facilities, consistent with section II.A.2
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. Finally, we are 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.A.4 of this
preamble.
k. Equipment Leak Surveys
Addition of leaker emission factors for survey methods other than
method 21. Subpart W reporters are 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 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 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
[[Page 36976]]
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424. 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.
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 that provide measurement data 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.\80\ These studies 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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\80\ 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-2019-0424.
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Based on our review of these studies, we are proposing to amend the
leaker emission factors in Table W-1E for onshore petroleum and natural
gas production and onshore petroleum and natural gas gathering and
boosting facilities to include separate emission factors for leakers
detected with OGI, consistent with section II.A.1 of this preamble.
These emission factors were developed by combining the data from
Zimmerle et al. (2020) and Pacsi et al. (2019) to provide OGI leaker
emission factors by site type (i.e., gas or oil). These studies were
selected as the basis for the proposed OGI 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. 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-2019-0424.
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 would be used to quantify the
emissions from the leaks identified using these other monitoring
methods.
For onshore petroleum and natural gas gathering and boosting
facilities, all components are considered to be in gas service
consistent with the language in 40 CFR 98.233(q)(2)(iv); thus, the gas
service factors from Table W-1E should be applied to all leakers. In
order to make clear how onshore petroleum and natural gas production
facilities should apply these revised emission factors, 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, 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-1E to
this subpart.
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. Therefore, we are proposing to apply the ``OGI enhancement''
factor identified from measurement study data in the onshore production
and gathering and boosting industry segments to the leaker emission
factors for the other subpart W industry segments as a means to
estimate an OGI emission factor set. Analogous to the proposed changes
in Table W-1E for the Onshore Petroleum and Natural Gas Production and
Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments, this results in the addition of an emission factor set
specific to OGI, infrared laser beam illuminated instrument, or
acoustic leak detection device screening methods. The proposed emission
factor sets are included in Tables W-2A, W-3A, W-4A, W-5A, W-6A, and W-
7 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, respectively. A detailed description 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-2019-0424.
As an alternative to the proposed revised default leaker emission
factors, we are also proposing an option 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.A.2 of this preamble. The proposed amendments would provide that
[[Page 36977]]
facilities with components subject to 40 CFR 98.233(q) can elect to
perform direct measurement of leaks using one of the 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, a complete leak detection survey would be
the fugitive emissions monitoring of a well site 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 and Boosting industry segment, a complete leak detection
survey would be the fugitive emissions monitoring of a compressor
station 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 ``compressor station''
or at a ``centralized oil production site'' (and we are proposing to
define these terms in 40 CFR 98.238, as described in section III.J.1.p
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
relative to other quantitative measurement methods provided in the
rule.
Finally, as part of this overall amendment, we are also 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 to
be moved to 40 CFR 98.234(a)(1)(ii)) 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. 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. In addition to providing more accurate emissions
data consistent with section II.A.2 of this preamble, the removal of
the additional monitoring step would streamline and improve
implementation consistent with section II.B.2 of this preamble.
Amendments related to oil and natural gas standards and emissions
guidelines in 40 CFR part 60. As noted in the introduction to section
III.J of this preamble, the EPA recently proposed NSPS OOOOb and EG
OOOOc for 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 and compressor station affected sources. In addition, the proposed
NSPS OOOOb and EG OOOOc include a proposed appendix K to 40 CFR part
60, 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 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.A.2 of this preamble.
First, under these proposed amendments, facilities with certain
fugitive emissions components at a well site 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 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
cross-reference to 40 CFR 60.5397a to 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 the presumptive standards in the proposed EG
OOOOc and subject to 40 CFR part 62 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
40 CFR part 62 (e.g., sources subject to other state regulations and
sources participating in the Methane Challenge Program or other
voluntarily
[[Page 36978]]
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 that fugitive emissions
monitoring conducted to comply with NSPS OOOOa, NSPS OOOOb, or an
applicable approved state plan or applicable Federal plan in 40 CFR
part 62 is considered a ``complete leak detection survey,'' so that
onshore petroleum and natural gas production and onshore petroleum and
natural gas gathering and boosting facilities can use NSPS OOOOb or 40
CFR part 62 fugitive emission surveys directly for their subpart W
reports. In a corresponding amendment, we are also proposing to expand
the current reporting requirement in 40 CFR 98.236(q)(1)(iii) to
require reporters to indicate if 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 OOOOb or an applicable approved state plan or
applicable Federal plan in 40 CFR part 62.\81\ 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 subpart W.
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\81\ We are similarly proposing to revise the existing reporting
requirement 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).
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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 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). 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.
The EPA proposed in NSPS OOOOb and EG OOOOc that owners and
operators 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 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. As part of the proposal of
NSPS OOOOb and EG OOOOc, the EPA proposed an alternative screening
approach for fugitive emissions from well sites and compressor stations
that would allow the use of advanced measurement technologies to detect
large equipment leaks. 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, even if no large emissions are
identified, facilities using these advanced technologies would still be
required to conduct annual fugitive emissions monitoring using OGI or
Method 21. 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 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 that for 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 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 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
[[Page 36979]]
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 total hydrocarbon
leaker emission factors are the same as the total hydrocarbon leaker
emission factors for the Onshore Natural Gas Transmission Compression
and the Underground Natural Gas Storage industry segments (Table W-3A
and Table W-4A, respectively). For more information on the derivation
of the original emission factors, see the TSD for the final subpart W
standards,\82\ and for more information on the derivation of the
emission factors proposed to be added to Table W-2B, see the TSD for
the 2016 amendments to subpart W.\83\ In a corresponding amendment, we
are also proposing to expand the reporting requirement in 40 CFR
98.236(q)(1)(iii) 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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\82\ 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-2019-0424.
\83\ 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-2019-0424.
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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)(1), 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 Table
W-2A. As with the proposed ``other'' leaker emission factors, these
proposed leaker emission factors are the same as the total hydrocarbon
leaker emission factors for the Onshore Natural Gas Transmission
Compression and the Underground Natural Gas Storage industry segments
(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.\84\ 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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\84\ 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-2019-0424.
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l. Equipment Leaks by Population Count
As noted in section III.J.1.k of this preamble, subpart W reporters
are 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), depending upon
the industry segment. The equipment leaks by population count method
uses the count of equipment components, subpart W emission factors
(e.g., 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 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 Tables W-1B
and W-1C, as applicable. Reporters in other industry segments 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.A.1,
II.A.4, and II.A.5 of this preamble.
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 Table W-1A of subpart W.
The gas service population emission factors are based on the 1996 Gas
Research Institute (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-2019-0424). The oil service
population emission factors are based on the American Petroleum
Institute's (API) Emission Factors for Oil
[[Page 36980]]
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 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 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 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 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) \85\
and Zimmerle et al. (2020),\86\ have performed an equipment and
component inventory alongside equipment leak screening and measurement
results. Another recent study, Rutherford et al. (2021),\87\ included
synthesis and analysis of measurements from component-level field
studies. These studies provide the necessary data to develop and
compare study-estimated population emission factors as well as study-
estimated default component counts per major equipment 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.
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\85\ 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-2019-0424.
\86\ 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-2019-0424.
\87\ 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-2019-0424.
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Based on our review of these studies, we are proposing to amend the
population count method for onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and boosting
facilities using these more recent study data, consistent with section
II.A.1 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 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 inventory
their major equipment and consistently apply the same emissions factor
to estimate 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. The major equipment emission factors were developed
by combining data from Zimmerle et al. (2020) and Pacsi et al. (2019)
to provide population emission factors by major equipment and site type
(i.e., gas or oil). The emission factors were derived by summing the
leaker emissions by major equipment type, including wellhead,
separator, meters/piping, compressor, acid gas removal unit,
dehydrator, header, heater treater, and storage vessel, by the reported
site type and dividing those leaker emissions by the count of major
equipment screened to yield an emission factor in units of scf whole
gas/hour-equipment. Specific to meters/piping and consistent with
current requirements related to meters/piping at 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 Pacsi/
Zimmerle studies, the proposed emission factors include more pieces of
major equipment than are currently included in subpart W. 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-2019-0424. The proposed major equipment
emission factors would replace the component-based emission factors in
the current Table W-1A. We are also proposing to revise the titles of
Tables W-1B, W-1C, and W-1D to clarify that they apply to reporting
years up to and including RY2022. These tables would not apply to
subsequent reporting years as they provide activity data that would no
longer be needed for the population count method for these industry
segments. We are seeking comment on the approach of providing
population count emission factors by major equipment.
We note that the application of these emission factors is by site
type such that for onshore petroleum and natural gas production
facilities, gas well sites should use the proposed gas service emission
factors and oil well sites should use the proposed oil service emission
factors. Similarly, for onshore petroleum and natural gas gathering and
boosting facilities, we consider all equipment to be in gas service
consistent with the language in 40 CFR 98.233(r)(2); thus, the proposed
gas service factors from Table W-1A should be applied to all equipment
counts. We
[[Page 36981]]
are proposing language clarifying the service-specific application of
these emission factors specifically for onshore petroleum and natural
gas production in 40 CFR 98.233(r)(2).
Natural Gas Distribution Emission Factors. Natural Gas Distribution
companies 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 Table W-7 (proposed
to be moved to Table W-8), and operating time to estimate emissions.
The population emission factors for pipeline mains and services in
Table W-7 (proposed to be moved to Table W-8) are based on information
from the 1996 GRI/EPA study.\88\ Specifically for plastic mains,
additional data are sourced from a 2005 ICF analysis.\89\ The
population emission factors for pipeline mains are published per mile
of main by pipeline material and emission factors for pipeline services
are published per service by pipeline material. The population emission
factors for below grade stations in Table W-7 (proposed to be moved to
Table W-8) are based on information from the 1996 GRI/EPA study.\90\
The population emission factors for below grade transmission-
distribution transfer stations and below grade metering-regulating
stations are published per station by three inlet pressure categories
(>300 psig, 100-300 psig, <100 psig).
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\88\ 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-2019-0424.
\89\ 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-2019-0424.
\90\ 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-2019-0424.
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The EPA is proposing to update the population emission factors in
Table W-7 (proposed to be moved to Table W-8) 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.\91\ \92\ The majority of the
U.S. GHG Inventory updates were based on data published by Lamb et al.
in 2015.\93\ 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.\94\
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. For more information on the
review and analysis of the various studies, see the subpart W TSD,
available in the docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-
2019-0424).
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\91\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks: Revisions under Consideration for Natural Gas Distribution
Emissions. December 2015. Available at https://www.epa.gov/sites/production/files/2016-02/documents/proposed_revisions_to_ng_distribution_segment_emissions.pdf and in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
\92\ 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-2019-0424.
\93\ 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-2019-0424.
\94\ 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-2019-0424.
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The population emission factors for distribution mains and services
are a function of the average measured leak rate (scf/hr) 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 GRI/EPA
study. The Weller et al. study quantified leaks from only distribution
mains using the Advanced Mobile Leak Detection (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.
During our assessment of the Lamb et al. and Weller et al. studies,
we identified the method for leak quantification as being a key
strength of the Lamb et al. study and the significantly larger sample
size used in estimating the annual leak frequency as being a key
strength of the Weller et al. study. In order to take advantage of the
strengths of both studies, we are proposing to amend the subpart W
emission factors for distribution mains using the measurements from
Lamb et al. combined with the pipeline material specific leaks per mile
data from Weller et al. We are proposing to amend the subpart W
emission factors for distribution services using the measurements from
Lamb et al. only, consistent with the emission factors used in the 2016
U.S. GHG Inventory, because services were not included in the Weller et
al. study. See the subpart W TSD, available in the docket for this
rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424) for more information
on our assessment of both studies and the derivation of the proposed
emission factors from the data published by Lamb et al. and Weller et
al. We are seeking comments on the approach of combining data from both
studies to update the distribution mains emission factors. As
alternatives to the proposed amendments, we also considered updating
the distribution mains emission factors using data from each study
independently. Accordingly, we are also seeking comment on whether
using data only from Lamb et al., consistent with the emission factors
used in the U.S. GHG Inventory, or only from Weller et al. to update
the distribution mains emission factors would be preferable over the
combined approach included in this proposal, and if so, which study is
preferred and why.
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 36982]]
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-2019-0424). 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 Table W-7 (proposed to be moved to
Table W-8) to a single emission factor without regard to inlet
pressure. We are also proposing to amend the corresponding section
header in Table W-7 (proposed to be moved to Table W-8) for below grade
station emission factors and the references to Table W-7 (proposed to
be moved to Table W-8) 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 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.B.3 of this preamble.
Gathering pipeline emission factors. Facilities in the Onshore
Petroleum and Natural Gas Gathering and Boosting industry segment
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 Table W-
1A, and operating time to estimate emissions. The population emission
factors for gathering pipeline mains in 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.\95\ The
population emission factors for gathering pipelines are published per
mile by pipeline material.
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\95\ 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-2019-0424.
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As noted previously in this section, the EPA is proposing to update
the natural gas distribution population emission factors in Table W-7
(proposed to be moved to Table W-8) 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.\96\ The EPA has reviewed the recent studies
published for onshore petroleum and natural gas gathering and boosting
facilities as well as the additional studies for pipeline distribution
mains, and none of the studies provide new emissions data or activity
data specific to gathering pipelines. Therefore, consistent with the
updates to the emission factors for distribution mains, and consistent
with section II.A.1 of this preamble, we are proposing to revise the
gathering pipeline population emission factors 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-2019-0424).
---------------------------------------------------------------------------
\96\ 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-2019-0424.
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m. Other Large Release Events
We are proposing to add an additional emissions source, referred to
as ``other large release events'' to capture abnormal emission events
that are not fully accounted for using existing methods in subpart W,
consistent with section II.A.3 of this preamble. 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. 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, are generally
small, and have been studied and characterized. 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 of CH4 between October 2015 and February
2016 and a well blowout in Ohio released an estimated 40,000 to 60,000
tons of CH4 in a 20-day period in 2018. 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.\97\ Because these events can significantly
contribute to the total GHG emissions from this sector, we are
proposing new calculation methods for estimating the GHG emissions from
other large release events in 40 CFR 98.233(y) and requirements for
reporting other large release events in 40 CFR 98.236(y). These
proposed additional calculation and reporting requirements would apply
to all subpart W industry segments and would improve the accuracy of
emissions reported under subpart W and enhance the overall quality of
the data collected under the GHGRP.
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\97\ The EPA notes that the full emissions from this event were
included in the U.S. GHG Inventory based on the results of multiple
measurement studies.
---------------------------------------------------------------------------
The new calculation requirements being proposed rely on 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. 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. This is equivalent to approximately
500,000 scf of pipeline quality natural gas. We selected this proposed
threshold to capture reporting for large emission events, such as well
blowouts, well releases, and large pressure relief venting. In order to
establish this reporting threshold, we first assessed other emission
sources that we considered large. Specifically,
[[Page 36983]]
we considered completions of hydraulically fractured wells that are not
controlled (i.e., not performed using reduced emission completions) to
be large emissions events. Based on analysis of GHGRP data of wells
that are not reduced emission completions and that vent, the U.S. GHG
Inventory developed an average emission factor of about 360
mtCO2e for these events. Because this is an average
emissions 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.
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 will be less than this average value. The 250
mtCO2e threshold is approximately equivalent to 500,000 scf
of natural gas, which compares reasonably well with the lower range of
well blowouts expected based on the average emission factor of 2.5
MMscf per event.
We also find that the 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
conclude 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-2019-0424. 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 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, 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. 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.1.g 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-2019-0424.
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
event because such events are so rare that they generally do not exist
when measurement studies are conducted. Additionally, skewing the
emission factors used to account for such an event would yield
erroneously high emissions from normal operations for nearly all
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, 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.
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 reporting requirement that would
require subpart W reporters to indicate whether an ``other large
release event'' was identified under any provisions of NSPS OOOOb or an
applicable approved state plan or applicable Federal plan in 40 CFR
part 62. As described in section III.J.1.k of this preamble, the EPA
proposed a fugitive emissions monitoring program in NSPS OOOOb and EG
OOOOc, including an alternative screening approach for fugitive
emissions from well sites and compressor stations that would allow the
use of advanced measurement technologies to detect emissions. 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,
[[Page 36984]]
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
methane satellite imagery, would not be specifically included as
measurement methods in 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 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.
n. Combustion
Methane slip from compressor engines. 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). 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 methane 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.\98\ 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-2019-0424).
---------------------------------------------------------------------------
\98\ 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-2019-0424.
---------------------------------------------------------------------------
Based on the EPA's review and analysis, there appears to be
combustion slip for all compressor engine types 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 engine and not the application (i.e., we
expect combustion slip from compressor engines regardless of the
industry segment). Therefore, the EPA is proposing to revise the
methodologies for determining combustion emissions from compressor
engines to account for combustion slip, consistent with section II.A.3
of this preamble. For the three subpart W industry segments that
calculate combustion emissions per 40 CFR 98.233(z), we are proposing
to accomplish this with two amendments to the calculation methods and
the addition of one new reporting requirement. For compressor engines
in those subpart W industry segments that combust natural gas and
qualify to determine emissions using the subpart C calculation
methodologies per 40 CFR 98.233(z)(1) and proposed new
98.233(z)(2),\99\ we are proposing that reporters would use subpart-W
specific emission factors by engine design class (e.g., 2-stroke lean-
burn, 4-stroke lean-burn, 4-stroke rich-burn, or other) in proposed new
Table W-9 rather than the emission factors in Table C-2. For compressor
engines that combust natural gas and determine emissions per 40 CFR
98.233(z)(2) (proposed to be moved to 40 CFR 98.233(z)(3)), we are
proposing updated combustion efficiency value(s) ([eta]) by engine
design class to be used in equations W-39A and W-39B that would reflect
combustion slip. We are also proposing to add a reporting requirement
to 40 CFR 98.233(z)(2) to specify the design class of reported internal
combustion units that are compressor-drivers to facilitate verification
of the selected emission factors and efficiencies, as applicable, and
the resulting emissions.
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\99\ See section III.J.2.f 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.
---------------------------------------------------------------------------
In an analogous amendment for the reporters in the other subpart W
industry segments that calculate and report combustion emissions under
subpart C, we are proposing that they also use subpart W-specific
emission factors rather than the emission factors in Table C-2.
Currently, these facilities use either equation C-8, C-8a, C-8b, C-9,
C-9a, C-9b, 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. As described in section III.B of this preamble, the emission
factor term definition in each of these equations is proposed to be
amended to reference Table W-9 rather than Table C-2 specifically for
quantifying emissions from compressor-drivers. We are also proposing to
add a footnote to Table C-2 to specify that the default CH4
emission factor should only be used for combustion devices that are not
compressor-drivers.
Clarifications of calculation methodologies. As noted previously in
this section, Onshore Petroleum and Natural Gas Production, Onshore
Petroleum and Natural Gas Gathering and Boosting, and Natural Gas
Distribution facilities report combustion emissions calculated in
accordance with 40 CFR 98.233(z) instead of reporting under subpart C.
Stakeholders (e.g., GPA Midstream) have identified several concerns
with the requirements in 40 CFR 98.233(z). First, GPA Midstream 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.\100\ In particular, 40 CFR
98.233(z)(2)(ii) currently specifies that to determine the
concentrations of
[[Page 36985]]
hydrocarbon constituents in the flow of gas to the unit, reporters must
either use a continuous gas composition analyzer (if one is present) or
the procedures in the applicable paragraph in 40 CFR 98.233(u)(2) of
this section. 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, GPA Midstream explained that
onshore petroleum and natural gas gathering and boosting facilities do
not necessarily use the gas received at their facility for combustion.
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 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 to be moved to 40 CFR
98.233(z)(3)(ii)(B)) 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. In addition to improving the accuracy of the
emissions calculated and therefore the quality of data collected,
consistent with section II.A.2 of this preamble, this proposed
amendment is expected to provide additional flexibility for reporters,
consistent with section II.B.2 of this preamble.
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\100\ 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-2019-0424.
---------------------------------------------------------------------------
Second, GPA Midstream indicated that the existing provisions of 40
CFR 98.233(z)(1)(ii) are unclear and that some member companies have
been interpreting those provisions 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 rather than subpart C (even
given the provisions in 40 CFR 98.233(z)(1) that reference subpart C
for certain fuels).\101\ 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 current 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 under subpart C. As part of the amendments described
in this section, consistent with section II.A.5 of this preamble, 40
CFR 98.233(z)(1)(ii) is proposed to be moved to 40 CFR 98.233(z)(4),
and we are proposing wording changes to be clear that this paragraph
refers only to reporting. We are also proposing to add a reference to
this new paragraph 40 CFR 98.233(z)(4) in both 40 CFR 98.233(z)(1)(ii)
and 98.233(z)(2)(ii) (as proposed to be amended).
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\101\ 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-2019-0424.
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o. Leak Detection and Measurement Methods
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.A.2 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.
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.A.2 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 methane 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 clarifying the calculation
methods needed if the high volume sampler outputs methane 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 methane 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 methane 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
methane 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 methane flows above the manufacturer's methane 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
[[Page 36986]]
docket for this rulemaking (Docket Id. No EPA-HQ-OAR-2019-0424).
p. Onshore Petroleum and Natural Gas Gathering and Boosting Compressor
Stations
The EPA received feedback from GPA Midstream that a count of
compressor stations per Onshore Petroleum and Natural Gas Gathering and
Boosting facility would provide the EPA with improved data on the
number and type of equipment at gathering and boosting stations, which
could help to better inform future rulemakings.\102\ In addition, the
EPA could use information on the count of compressor stations to
improve the process of verifying annual reports to the GHGRP. As an
example, a facility with high emissions for a particular source type
compared to other facilities in the same basin might currently be
identified as a potential outlier. However, if the report also
indicated that the facility has a large number of compressor stations
compared to other facilities, the EPA could use that information during
report verification to confirm the high emissions without needing to
contact the facility owner or operator. Therefore, the EPA is proposing
to add a requirement in 40 CFR 98.236(aa)(10)(v) to report the count of
compressor stations for facilities in the Onshore Petroleum and Natural
Gas Gathering and Boosting industry segment, consistent with section
II.A.4 of this preamble. Additionally, the count of compressor stations
per facility would allow for refinements to the activity data used by
the U.S. GHG Inventory. In particular, the calculated national-level
compressor station activity data used by the U.S. GHG Inventory could
be informed by reported compressor station counts for Onshore Petroleum
and Natural Gas Gathering and Boosting facilities subject to subpart W,
which improves the U.S. GHG Inventory estimate of total national
emissions. The EPA is also proposing a definition of ``compressor
station'' in 40 CFR 98.238 to be used for the purposes of this
reporting requirement to reduce any potential reporter confusion.
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\102\ 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-2019-0424.
---------------------------------------------------------------------------
Based on the definition of Onshore Petroleum and Natural Gas
Gathering and Boosting industry segment, this industry segment also
includes ``centralized oil production sites.'' These are sites that
collect oil from multiple well pads but that do not have compressors
(i.e., are not ``compressor stations''). Therefore, we are proposing to
add a requirement in 40 CFR 98.236(aa)(10)(vi) to report the count of
centralized oil production sites for facilities in the Onshore
Petroleum and Natural Gas Gathering and Boosting industry segment,
consistent with section II.A.4 of this preamble. We are also proposing
to add a definition of ``centralized oil production site'' in 40 CFR
98.238 to be used for the purposes of this reporting requirement. These
proposed additional data elements would enhance the overall quality of
the data collected under the GHGRP.
q. Onshore Natural Gas Transmission Pipeline Throughput Information
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 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.J.2.g of this preamble, the EPA has received stakeholder comments
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 40 CFR 98.236(aa)(11)(ii) and
(iii). After consideration of the stakeholder comments, the EPA is
proposing to clarify the term ``in-system.'' Specifically, we are
proposing to amend 40 CFR 98.236(aa)(11)(ii) and (iii) to clarify that
``in-system'' withdrawals/additions of natural gas from storage are
specifically 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.A.5 of this
preamble.
2. Proposed Revisions to Streamline and Improve Implementation for
Subpart W
As further described in section II.B of this preamble, we are also
proposing amendments to remove, reduce, or simplify requirements that
would streamline and improve implementation while maintaining the
quality of the data collected under part 98. To determine which
reporting requirements and data elements of subpart W to propose
amending, the EPA reviewed correspondence with reporters during the
annual verification of GHGRP data, questions submitted to the GHGRP
Help Desk and the responses provided, and the specific regulatory
language of subpart W. As a result of that process, the EPA is
proposing to eliminate, clarify, or otherwise amend select calculation
methodologies and reporting requirements as described in this section.
Consistent with section II.B.2 of this preamble, some of the proposed
amendments would add monitoring or reporting flexibility for certain
calculation methodologies. Other proposed revisions would remove
reporting requirements that are redundant with data already reported to
the EPA or no longer being used at this time, as further described in
section II.B.3 of this preamble.
a. Dehydrator Vents
Removal of requirements for desiccant dehydrators. Subpart W
currently requires reporting of desiccant dehydrators as a subcategory
of dehydrator vents. Based on the data reported to date, the emissions
from these sources are less than 0.1 percent of total reported
emissions from dehydrator vents (in RY2020, desiccant dehydrators
contributed 760 mtCO2e of the total 3.35 million
mtCO2e from all dehydrator vent emissions). In addition, it
appears that a significant percentage of the emissions reported to date
may be from molecular sieve dehydrators; however, we never intended to
require reporting of emissions from such units, and based on the
definition of ``dehydrator'' in 40 CFR 98.6, we do not read the rule to
require such reporting. In RY2015 through RY2020, about 60 percent of
the facilities that reported counts of desiccant dehydrators also
reported emissions of 0 mtCO2e (516 out of 897 reporters),
and more than one-quarter of the reported desiccant dehydrators were at
facilities that reported 0 emissions from desiccant dehydrators (1,888
out of 7,139 units). Furthermore, facilities that report emissions from
desiccant dehydrators in a given year may not have depressurized every
one of their desiccant dehydrators
[[Page 36987]]
in that year, but this cannot be determined from the reported data
because emissions are reported at the facility level instead of per
dehydrator. This pattern of emissions reporting is consistent with the
expected results for molecular sieve dehydrators because such units
typically are opened (depressurized) only once every few years. Thus, a
significant percentage of the reported emissions from desiccant
dehydrators may be from units that are not subject to reporting,
meaning that the actual emissions from desiccant dehydrators would be
less than the reported 0.1 percent of the total dehydrator emissions.
Therefore, we are proposing to remove requirements for desiccant
dehydrators from 40 CFR 98.233(e)(3) and (4) and 40 CFR 98.236(e)(3) of
subpart W, consistent with section II.B.2 and II.B.3 of this
preamble.\103\ As a corollary to the proposed removal of the desiccant
dehydrator requirements, we are also proposing to remove the definition
of ``desiccant'' and to revise the definition of ``dehydrator'' in 40
CFR 98.6, as discussed in section III.A of this preamble.
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\103\ We are also proposing to move the specifications for
calculating mass emissions from volumetric emissions for glycol
dehydrators with an annual average of daily natural gas throughput
that is less than 0.4 MMscf per day from 40 CFR 98.233(e)(4) to 40
CFR 98.233(e)(2), which would consolidate the requirements for those
dehydrators.
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As an alternative to removing the requirements for all desiccant
dehydrators, we considered revising 40 CFR 98.233(e)(3) to clarify that
only devices with desiccant that absorb water (as opposed to those
containing materials that adsorb water) are subject to the GHGRP. That
change would be consistent with the original intent, as evidenced by
the definitions of ``desiccant'' and ``dehydrator'' in 40 CFR 98.6, and
it would clarify that molecular sieve units (which contain material
that adsorbs water) are not subject to subpart W. That change also
would reduce the number of reporters. However, we are not proposing
that option because the reported emissions would be extremely small
relative to other dehydrator emissions. We request comment on other
advantages and disadvantages of this option relative to the proposed
plan of deleting requirements for desiccant dehydrators and whether
commenters think there are potential benefits of this option that
outweigh potential drawbacks.
Although this proposal would remove the desiccant dehydrator
requirements from subpart W, other requirements in subpart W may then
apply instead. Currently, 40 CFR 98.233(e)(3) and 40 CFR 98.233(i)
specify that desiccant dehydrator emissions calculated using equation
W-6 do not have to be calculated separately under the blowdown vent
stacks provisions in 40 CFR 98.233(i). However, because we are
proposing to remove the desiccant dehydrator provisions, the EPA is
also proposing to remove the exception at the end of the 40 CFR
98.233(i) introductory paragraph. Thus, the blowdown provisions in 40
CFR 98.233(i) would apply, provided that the volume of space in a
desiccant dehydrator that is depressurized to atmosphere is greater
than 50 cubic feet. Similarly, in the absence of desiccant dehydrator
provisions, if the emissions from depressurizing desiccant dehydrators
are routed to a flare, then the emissions would be subject to the
requirements for flare stack emissions in 40 CFR 98.233(n). We note
that while these emissions may still be reported to the EPA if the
proposal to remove the desiccant dehydrator provisions is finalized,
they would no longer be required to be calculated and reported
separately, which would still streamline implementation for reporters.
Clarification of Count for Glycol Dehydrators with Annual Average
Daily Natural Gas Throughput Less Than 0.4 MMscf per Day. As noted in
section III.J.1.d 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 40 CFR 98.233(e)(2) and report emissions per 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 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 that the count of dehydrators in 40 CFR
98.236(e)(2)(i) 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 amendments are expected to streamline and improve
implementation, consistent with section II.B.3 of this preamble.
b. Blowdown Vent Stacks
Blowdown equipment types. 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, public
commenters indicated that the existing equipment or event types were
not appropriate for the new segment, so 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. Also,
both the third sentence and last sentence in 40 CFR 98.233(i)(2)
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.'' According to this provision, when a
blowdown event consists of emissions from two or more equipment types,
the emissions must be apportioned to each applicable equipment type,
unless such apportionment is not possible.
The EPA is proposing 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
[[Page 36988]]
regarding the applicable requirements for each industry segment.
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
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). As a result of 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. 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
(Onshore Natural Gas Transmission Pipeline and Onshore Petroleum and
Natural Gas Gathering and Boosting) and increase flexibility for
Onshore Natural Gas Transmission Pipeline reporters, consistent with
section II.B.2 of this preamble.
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 to allow use of engineering estimates to determine
the temperature and pressure of an emergency blowdown for both the
Onshore Natural Gas Transmission Pipeline and Onshore Petroleum and
Natural Gas Gathering and Boosting industry segments, consistent with
equation W-14A.
c. Atmospheric Storage Tanks
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) requires reporting of
counts of the total number of atmospheric storage tanks within the sub-
basin or county, the number of atmospheric storage tanks that are
controlled by a vapor recovery system, the number of atmospheric
storage tanks that are controlled by a flare, and the number of
atmospheric storage tanks that are not controlled by either a vapor
recovery system or a flare. As atmospheric storage tanks are typically
controlled by both a vapor recovery system and a flare, these counts
allow for overlap and cause confusion among reporters. Additionally,
atmospheric storage tanks may be included in multiple categories of
counts if the facility elects to add an emissions control partway
through the reporting year.
Therefore, the EPA is proposing to reorganize the reporting
requirements in 40 CFR 98.236(j)(1) to reduce overlap between several
of the current data elements that are reported by control methodology.
Specifically, the EPA is proposing to collect only the total number of
tanks within the sub-basin or county, the count of atmospheric tanks
that routed emissions to vapor recovery and/or flares at any point
during the reporting year, and the count of atmospheric tanks that
vented gas directly to the atmosphere and did not control emissions
using a vapor recovery system or flares at any point during the
reporting year.
For consistency with the revisions to the atmospheric storage tank
count data elements, the EPA is proposing to require separate reporting
of emissions for tanks that did not control emissions using a vapor
recovery system or flares at any point during the reporting year and
for tanks that routed emissions to vapor recovery and/or flares at any
point during the reporting year. For tanks that do not control
emissions using a vapor recovery system or flares at any point during
the reporting year, facilities would report CO2 and
CH4 emissions resulting from venting gas directly to the
atmosphere. For tanks that rout emissions to vapor recovery and/or
flares at any point during the reporting year, facilities would report
CO2, CH4, and N2O emissions from
flares and the total mass of CO2 and CH4 that was
recovered using a vapor recovery system in addition to the
CO2 and CH4 emissions resulting from venting gas
directly to the atmosphere. With this reorganization of the emissions
reporting requirements for atmospheric storage tanks, the EPA expects
to streamline reporting and reduce redundancy between data elements,
consistent with section II.B.3 of this preamble.
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 (40 CFR
98.236(j)(1)(xi)), consistent with section II.B.3 of this preamble.
This reporting requirement is 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 tanks in the
sub-basin per 40 CFR 98.236(j)(1)(x).
Calculation method 3 reporting. 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 follow the Calculation Method 3 methodology specified in 40
CFR 98.233(j)(3) and equation W-15. 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.
The EPA has received feedback through correspondence with reporters via
e-GGRT that these reporting requirements are unclear.
[[Page 36989]]
After consideration of this feedback, the EPA has made a preliminary
determination that these reporting requirements 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 40 CFR 98.236(j)(2)(i)(E)
to completely align the requirement with the total ``Count'' input
variable in equation W-15. The EPA proposes to amend the language in 40
CFR 98.236(j)(2)(i)(E) to request the total number of separators,
wells, or non-separator equipment in the basin used to calculate
Calculation Method 3 storage tank emissions. The current language in 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 40 CFR 98.236(j)(2)(i)(F), which
requires reporting of the number of wells without gas-liquid separators
in the basin. Both of the current data elements in 40 CFR
98.236(j)(2)(i)(E) and 40 CFR 98.236(j)(2)(i)(F) have been determined
to be no longer as useful for present program or policy purposes, as
they do not correlate with the calculated Calculation Method 3
atmospheric tank emissions. These changes would streamline the
requirements for all facilities reporting atmospheric storage tanks
emissions using Calculation Method 3. Consistent with section II.B.3 of
this preamble, reporters would no longer be required to determine two
separate counts that may not be representative of the inputs used in
equation W-15.
In addition, the provisions in 40 CFR 98.236(j)(2)(ii) and (iii)
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.
Using the calculation procedures provided in 40 CFR 98.233(j)(3)
through (5), when a facility adds a flare control to an atmospheric
storage tank in the middle of a reporting year, facilities are required
to separately calculate emissions that are not flared from emissions
that are flared from that tank, sum these emissions values, and report
all emissions from the tank as part of the sub-basin or county flared
tanks total per the requirements of 40 CFR 98.236(j)(2)(iii). In an
effort to streamline and improve implementation consistent with section
II.B.2 of this preamble, the EPA is proposing to clarify that for
storage tanks using Calculation Method 3, reporters would calculate
either flared or vented emissions for a tank, but not both.
Specifically, the EPA is proposing to add language in 40 CFR
98.233(j)(5) that specifies that if the flare captured flash gas from
at least half of the annual hydrocarbon liquids received by the tank
for which emissions were calculated using Calculation Method 3, flared
emissions would be calculated according to 40 CFR 98.233(j)(5) (i.e.,
as if all flash gas generated from a tank during the entire reporting
year is sent to a flare). The EPA is also proposing to amend 40 CFR
98.236(j)(2)(iii) to specify that the reporting requirements in that
section 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. The EPA is
proposing a corresponding change to 40 CFR 98.236(j)(2)(ii), which
would require reporting of the Calculation Method 3 emissions from the
remaining atmospheric storage tanks that either used flares to control
emissions from less than half the annual hydrocarbon liquids received
or did not control any emissions with a flare. The emissions from these
remaining atmospheric storage tanks would be calculated as venting
directly to the atmosphere for the entire year (i.e., emissions from
tanks that flared for less than half of the year would not be
calculated using the flare procedures provided in 40 CFR 98.233(j)(5)).
d. 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 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 leaks. As a result, the
reported flared emissions from transmission storage tank vent stacks in
each of the last 6 years have been 0 metric tons of CO2,
CH4, and N2O. Based on these results, the EPA has
made a preliminary determination that continued reporting of source-
specific flared emissions from transmission tanks would not likely
provide new insights or knowledge of the industry sector, emissions, or
trends. Therefore, consistent with section II.B.3 of this preamble, the
EPA is proposing that transmission tanks be classified as a
miscellaneous flared source such that any flared emissions from the
tanks in the future would be reported collectively with flared
emissions from all miscellaneous flared sources as specified in 40 CFR
98.236(n)(1). The EPA is proposing to retain the current requirements
in 40 CFR 98.233(k)(1) and (2) to monitor the tank vent stack annually
for leaks and to quantify the leak rate if a leak is detected. As an
alternative to these source-specific requirements, a reporter also
would be allowed to continuously measure either total flow from the
transmission tank vent stack or the comingled total flow into the
flare, consistent with the existing requirement in 40 CFR 98.233(n)(1).
Flow data determined by either of these methods would still be needed
to calculate total flared emissions from the miscellaneous flared
sources. 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 flare activity
data reporting requirements for flared emissions from transmission
storage tank vent stacks consistent with the activity data reporting
for other source types that have source-specific flared emissions
reporting requirements as described in the ``Calculation Methodology
for Flared Emissions'' subsection in section III.J.1.i of this
preamble. The proposed rule language under this alternative would be
added to 40 CFR 98.233(k)(5), and it would be similar to proposed
language for other flared sources (e.g., well testing in 40 CFR
98.233(l)(6) and associated gas flaring in 40 CFR 98.233(m)(5)). One
difference is that an option to continuously measure combined streams
into a flare would not be allowed for transmission tanks because it
would not be possible to tell if there were any scrubber dump valve
leaks if only a combined emissions stream is measured. We request
comment on the advantages and disadvantages of both approaches we are
considering relative to the current requirements.
e. Compressors
As noted in section III.J.1.j of this preamble, reporting
requirements for compressors in the Onshore Natural Gas Processing,
Onshore Natural Gas Transmission Compression, Underground Natural Gas
Storage, LNG Storage, and LNG Import and Export Equipment industry
segments include requirements to conduct ``as found'' measurements for
the compressor mode-source combination in which the
[[Page 36990]]
compressor is found. In addition, 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.B.2 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. 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 (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.
In addition, centrifugal and reciprocating compressors are the only
sources for which capture for fuel use and thermal oxidizers are
specifically listed as dispositions for emissions that would otherwise
be vented. 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. To avoid confusion, and
to clarify that the EPA's intent is generally to treat emissions routed
to flares and combustion devices other 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'' means 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'' means 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).
Finally, 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, 40 CFR 98.236(o)(1)(vi) and 40 CFR
98.236(p)(1)(vi) require reporters to indicate which individual
compressors are part of a manifolded group of compressor sources, and
40 CFR 98.236(o)(1)(vii) through (ix) and 40 CFR 98.236(p)(1)(vii)
through (ix) require reporters to indicate whether individual
compressors have compressor sources routed to flares, vapor recovery,
or combustion. However, 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 40 CFR 98.236(o)(1)(vi) through
(ix) and 40 CFR 98.236(p)(1)(vi) through (ix), consistent with section
II.B.3 of this preamble.
f. Combustion
Subpart W refers reporters in the Onshore Petroleum and Natural Gas
Production, Onshore Petroleum and Natural Gas Gathering and Boosting,
and Natural Gas Distribution industry 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 Btu 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. Stakeholders (e.g., GPA Midstream) have identified several
concerns with these requirements. In general, they have stated that the
ability to use subpart C calculation methodologies is unclear and too
restrictive. We are proposing several amendments to these provisions to
address these concerns and increase the flexibility of the calculation
methods, consistent with section II.B.2 of this preamble.
First, GPA Midstream has indicated that it is not clear whether
field gas that is of pipeline quality meets the criteria to use the
subpart C methodologies under 40 CFR 98.233(z)(1),\104\ and ``field
gas'' is not defined within 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. GPA Midstream
stated that the procedures in 40 CFR 98.233(z)(2) are more burdensome
than the subpart C methodologies and asked that the EPA clarify that
``field gas'' streams of pipeline quality can use the subpart C
methodologies. After review of these comments, 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 clarify
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
[[Page 36991]]
EPA is also proposing conforming edits to 40 CFR 98.233(z)(2) (proposed
to be moved to 40 CFR 98.233(z)(3)) for consistency.
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\104\ 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-2019-0424.
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Second, reporters have indicated in questions submitted to the
GHGRP Help Desk that the term ``pipeline quality'' is also not defined
in subpart W, leading to confusion over whether some fuel streams meet
the criteria to use the subpart C calculation methodologies per 40 CFR
98.233(z)(1). In addition, GPA Midstream 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,
they have 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).\105\
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\105\ 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-2019-0424.
---------------------------------------------------------------------------
We have reviewed the analysis in GPA Midstream's May 18, 2016
letter 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-
2019-0424).
Based on our analysis, we are proposing to add numeric composition
thresholds for natural gas to a new 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 (with the 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 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 CO2 content and minimum
CH4 content, as well as whether additional specification
criteria should be included (e.g., a maximum HHV).
Third, we are proposing amendments to clarify that emissions may be
calculated in 40 CFR 98.233(z)(3)(ii) for groups of combustion units.
The current provisions of 40 CFR 98.233(z)(2) (proposed to be moved to
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 and fuel, it is 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
with similar combustion efficiencies, emissions may be determined for
that combined volume of fuel (i.e., for that group of combustion
units). In other words, it is not necessary in this 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-driven compressor drivers. If any of
the combustion units downstream of this shared measurement point are
natural gas-driven compressor drivers, 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.J.1.n of this preamble.
g. Onshore Natural Gas Processing and Natural Gas Distribution
Throughput Information
Onshore Natural Gas Processing plants are required to report seven
facility-level throughput-related items under subpart W, as specified
in 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 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, including from the
American Gas Association (AGA),\106\ related to some of these reporting
elements. 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
[[Page 36992]]
liquid products supplied downstream and their associated emissions. For
example, for natural gas processing plants, 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, some duplicative
reporting is required as well. For example, 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 U.S. Energy
Information Administration (EIA) on Form EIA-176, the Annual Report of
Natural and Supplemental Gas Supply and Disposition.\107\ The
commenters explained that subpart W and subpart NN collect nearly the
same data, and 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.
---------------------------------------------------------------------------
\106\ 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-2019-0424.
\107\ 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
``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.'' \108\ In
the specific case of subpart NN, in the 2009 Final Rule, 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 sought ``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 test products
rather than use default emission factors.''
---------------------------------------------------------------------------
\108\ 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-2019-0424.
---------------------------------------------------------------------------
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.B.3 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
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.\109\ 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.\110\
---------------------------------------------------------------------------
\109\ 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.
\110\ While it is the EPA's intention that the reported quantity
of natural gas received at the facility in 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 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 proposing6 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). 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.
[[Page 36993]]
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 and have caused confusion for subpart
W reporters, require additional burden to estimate, and have not been
used for the EPA's analyses of the subpart W data. As a result of
removing these data elements, the EPA proposes to reserve paragraph 40
CFR 98.236(aa)(9). Table 2 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 2--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 Sec. 98.406(b)(1)... Annual volume of natural
gas received at all Sec. 98.406(b)(5)... gas received by the LDC at
custody transfer its city gate stations and
stations. Annual volume natural gas
that bypassed the city
gate(s).
Sec. 98.236(aa)(9)(ii)........... Quantity of natural Sec. 98.406(b)(3)... Annual volume natural gas
gas withdrawn from in- withdrawn from on-system
system storage. storage and annual volume
of vaporized LNG withdrawn
from storage.
Sec. 98.236(aa)(9)(iii).......... Quantity of natural Sec. 98.406(b)(2)... Annual volume of natural
gas added to in- gas placed into storage or
system storage. liquefied and stored.
Sec. 98.236(aa)(9)(iv)........... Quantity of natural Sec. Annual volume of natural
gas delivered to end 98.406(b)(13)(i) gas delivered by the LDC
users. through (iv). to residential consumers,
commercial consumers,
industrial consumers,
electricity generating
facilities.
Sec. 98.236(aa)(9)(v)............ Quantity of natural Sec. 98.406(b)(6)... Annual volume of natural
gas transferred to gas delivered to
third parties. downstream gas
transmission pipelines and
other local distribution
companies.
Natural Gas Processing Plants
that Fractionate NGLs.
Sec. 98.236(aa)(3)(i)............ Quantity of natural Sec. 98.406(a)(3)... Annual volume of natural
gas received. gas received for
processing.
Sec. 98.236(aa)(3)(iii).......... Cumulative quantity of Sec. 98.406(a)(2)... Annual quantity of each NGL
all NGLs (bulk and Sec. 98.406(a)(4)(i) product received and
fractionated) annual quantities of y-
received. grade, o-grade and other
bulk NGLs received.
Sec. 98.236(aa)(3)(iv)........... Cumulative quantity of Sec. 98.406(a)(1)... Annual quantity of each NGL
all NGLs (bulk and Sec. product supplied and
fractionated) leaving. 98.406(a)(4)(ii). annual quantities of y-
grade, o-grade and other
bulk NGLs supplied.
----------------------------------------------------------------------------------------------------------------
h. Onshore Natural Gas Processing Industry Segment
According to 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 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.
GPA Midstream has 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. According to GPA
Midstream, it would be more appropriate for such facilities to be in
the Onshore Petroleum and Natural Gas Gathering and Boosting industry
segment. GPA Midstream 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, 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, GPA Midstream recommended replacing the onshore natural gas
processing definition in subpart W with the natural gas processing
plant definition in NSPS OOOOa.\111\
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\111\ 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-2019-0424.
---------------------------------------------------------------------------
After review of these comments, we are proposing to replace the
definition of ``Onshore natural gas processing'' in 40 CFR 98.230(a)
with language similar to the definition of ``natural gas processing
plant'' in NSPS OOOOa. 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
[[Page 36994]]
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 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. This
proposed amendment would provide reporters with certainty about the
applicable industry segment for the reporting year, reducing the
monitoring data they must collect to only the information needed for
the applicable industry segment, consistent with section II.B.2 of this
preamble.
This proposed amendment is not expected to decrease overall
coverage of the GHGRP for the petroleum and natural gas systems
industry, although we anticipate that some facilities would report
under a different industry segment going forward. 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.
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 former 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 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 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 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. The two potentially applicable
segments report emissions from different sources and with different
calculation methods. For example, facilities in the Onshore Natural Gas
Processing industry segment are not required to report emissions from
atmospheric storage tanks and are required to measure leaks from
individual compressors, while facilities in the Onshore Petroleum and
Natural Gas Gathering and Boosting industry segment are required to
report emissions from atmospheric storage tanks but may use emission
factors to calculate emissions from compressors rather than conducting
measurements. These sites would meet the revised proposed definition of
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, and as a result,
removing the 25 MMscf per day threshold is expected to increase the
number of facilities that report under the Onshore Natural Gas
Processing industry segment. We request comment on the impact the
proposed change 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 change.
Finally, we note that the definition of natural gas processing
plant in NSPS OOOOa does not specifically include residue gas
compression equipment. Residue gas compression is defined in 40 CFR
98.238 as the compressors operated by the processing facility, whether
inside the processing facility boundary fence or outside the fence-
line, that deliver the residue gas from the processing facility to a
transmission pipeline. Per 40 CFR 98.230(a)(3), the Onshore Natural Gas
Processing industry segment includes all residue gas compression
equipment owned or operated by the natural gas processing plant. We are
requesting comment on whether to remove the existing requirement to
include residue gas compression equipment owned or operated by the
natural gas processing facility from 40 CFR 98.230(a)(3) and 40 CFR
98.231(b). If this change were finalized, we anticipate that residue
gas compression equipment would then be part of the Onshore Natural Gas
Transmission Compression industry segment, which would require
reporters with residue gas compression equipment that currently only
report under the Onshore Natural Gas Processing industry segment to
begin reporting under both the Onshore Natural Gas Processing and
Onshore Natural Gas Transmission Compression industry segments in order
to fully report their facility emissions. As part of the request for
comment on this issue, we request comment on the expected impact on the
level of reported emissions that would result if this change were
finalized. We also request comment on other rationale for or against
finalizing this change.
3. Other Proposed Minor Revisions or Clarifications
See Table 3 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.A.5 of this
preamble.
[[Page 36995]]
Table 3--Proposed Technical Corrections to Subpart W
------------------------------------------------------------------------
Section (40 CFR) Description of proposed amendment
------------------------------------------------------------------------
98.232(b), 98.233(s), Update the outdated acronym ``BOEMRE'' to
98.236(s). the current acronym ``BOEM.''
98.232(b), 98.233(s)......... Update the cross references to the BOEM
requirements from ``30 CFR 250.302
through 304'' to ``30 CFR 550.302
through 304.''
98.233(a)(1)................. Revise the definition of the equation
variable ``EFt'' to consolidate the list
of applicable industry segments and
tables into one sentence.
98.233(e)(1)(x).............. Add ``at the absorber inlet'' to the end
of the paragraph to clarify the location
for the wet natural gas temperature and
pressure to be used for modeling.
98.233(g)(4)(ii)............. Revise the instance of ``formation on
N2O'' in the second sentence to read
``formation of N2O'' to correct a
typographical error.
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(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 Moved 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, and vapor recovery apply to
all industry segments.
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).
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(s).................... Remove the outdated references to
``GOADS.''
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)(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.
98.236 introductory text..... Add missing ``than'' to read ``report gas
volumes at standard conditions rather
than the gas volumes at actual
conditions.''
98.236(e)(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(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.
Table W-1A, Table W-3B, and Change ``Low Continuous Bleed Pneumatic
Table W-4B to subpart W of Device Vents'' to ``Continuous Low Bleed
part 98. Pneumatic Device Vents'' and change
``High Continuous Bleed Pneumatic Device
Vents'' to ``Continuous High Bleed
Pneumatic Device Vents'' to be
consistent with the terms used
throughout the rest of subpart W.
Table W-3B and Table W-4B to Change table headings and footnotes to
subpart W of part 98. clarify that the population emission
factors for pneumatic device vents are
whole gas emission factors rather than
total hydrocarbon emission factors.
------------------------------------------------------------------------
4. Best Available Monitoring Methods
The EPA is proposing that facilities would be allowed to use BAMM
on a short-term transitional basis for the proposed amendments for the
2023 reporting year for only the specific industry segments and
emission sources for which new monitoring or data collection
requirements are being proposed. These industry segments and emission
sources include calculating and reporting emissions from natural gas
pneumatic devices at onshore natural gas processing facilities, natural
gas intermittent bleed pneumatic devices for which the reporter
conducts routine monitoring surveys, acid gas removal vents at LNG
import/export facilities, other large release events at all facilities,
miscellaneous flared sources, glycol dehydrators and atmospheric
storage tanks routed to vapor recovery systems, compressor sources and
mode-
[[Page 36996]]
source combinations for which new measurements would be required, and
measurements taken using a high volume sampler. We are also proposing
that reporters of an onshore natural gas processing facility that
becomes part of an onshore petroleum and natural gas gathering and
boosting facility, or vice versa, solely due to the proposed change in
the definition of 40 CFR 98.230(a)(3) would be allowed to use BAMM for
the emission sources for which measurements were not required under the
previous industry segment. This proposal would allow reporters to use
best available methods to estimate inputs to emission equations for the
newly proposed emission sources using their best engineering judgment
for cases where the monitoring of these inputs would not be possible
beginning on January 1, 2023.
These reporters would have the option of using BAMM from January 1,
2023, to December 31, 2023, without seeking prior EPA approval for
certain parameters that cannot reasonably be measured according to the
monitoring and quality assurance/quality control (QA/QC) requirements
of 40 CFR 98.234. This additional time for reporters to comply with the
monitoring methods for new emission sources in subpart W would allow
facilities to install the necessary monitoring equipment during other
planned (or unplanned) process unit downtime, thus avoiding process
interruptions. The EPA is not proposing to allow the use of BAMM beyond
RY2023 and does not anticipate that BAMM would be needed beyond 2023
for the specific industry segments and emissions sources with proposed
amendments in this rule. The EPA is also not proposing to allow the use
of BAMM for industry segments and emission sources for which no
amendments have been proposed that would require additional data
collection because reporters should already be collecting the
measurements and activity data needed to meet the requirements of the
current rule.
K. Subpart X--Petrochemical Production
We are proposing several amendments to subpart X of part 98
(Petrochemical Production) to improve the quality of data reported and
to clarify the calculation, recordkeeping, and reporting requirements
for the reasons described in this section and in section II.A of this
preamble.
For the reasons described in section II.A.3 of this preamble, we
are proposing to add a reporting element in 40 CFR 98.246(b)(7) and
(c)(3) for each flare that is reported under the CEMS and optional
ethylene combustion methodologies. These sections of subpart X
currently require reporting of the total emissions from each flare that
burns off-gas from a petrochemical process unit for which emissions are
determined under the CEMS or optional ethylene combustion
methodologies. We are proposing that reporters also report estimated
fractions of the total CO2, CH4, and
N2O emissions from these flares that are due to combusting
petrochemical off-gas because the current requirements result in an
overestimate of emissions attributed to a petrochemical process unit
when the flare is not dedicated to a petrochemical process unit,
particularly if the flare is also used to combust off-gas from non-
petrochemical process units. The proposed requirement would allow the
fractions attributed to each petrochemical process unit that routes
emissions to the flare to be estimated using engineering judgment. This
proposed change would allow more accurate quantification of emissions
both from individual petrochemical process units and from the industry
sector as a whole.
For the reasons described in section II.A.4 of this preamble, we
are proposing to add a requirement in 40 CFR 98.246(c)(6) to report the
names and annual quantity (in metric tons) of each product produced in
each ethylene production process under the optional ethylene combustion
methodology. Subpart X currently requires reporting of only the
quantity of ethylene produced. The proposed change would make product
reporting under the optional ethylene combustion methodology consistent
with product reporting requirements under the CEMS and mass balance
reporting options. Data on the quantities of all products will improve
the EPA's ability to verify reported emissions from these process
units, and the data will be useful in informing future policy
decisions.
For the reasons described in section II.A.5 of this preamble, we
are proposing two changes to clarify emissions calculation requirements
for flares. Currently, 40 CFR 98.243(b)(3) and (d)(5) cross-reference
the calculation procedures in 40 CFR 98.253(b)(1) through (b)(3) of
subpart Y. We are proposing to revise these sections to cross-reference
all of 40 CFR 98.253(b) to clarify that the provisions added in past
amendments and in this amendments package to the introductory paragraph
in 40 CFR 98.253(b) also apply to flares that are subject to reporting
under subpart X. This proposed change would clarify that subpart X
reporters are not required to report emissions from combustion of pilot
gas and, as discussed in section III.L of this preamble, that gas
released during SSM events of <500,000 scf/day are excluded from
equation Y-3.
Additionally, we are proposing five amendments to clarify subpart X
rule language pertaining to reporting of required data elements. In
previous rule amendments, we added requirements to report the annual
quantity of each petrochemical product produced from each process unit.
In making the changes, we inadvertently introduced some overlapping
reporting requirements. First, to clarify the reporting requirements
and eliminate confusion for facilities that use the mass balance
approach, we are proposing to amend 40 CFR 98.246(a)(2) to remove the
requirement to report feedstock and product names. The rule currently
specifies in two places that a reporter using the mass balance
methodology must report the feedstock and product names for a subject
process unit. The requirement in 40 CFR 98.246(a)(2) is to report the
``names of products, and names of carbon-containing feedstocks.'' The
requirement in 40 CFR 98.246(a)(12) is to report the ``(n)ame (. . .)
of each carbon-containing feedstock included in equations X-1, X-2, and
X-3 of Sec. 98.243.'' The requirement in 40 CFR 98.246(a)(13) is to
report the ``(n)ame (. . .) of each product included in equations X-1,
X-2, and X-3.'' Although the language in 40 CFR 98.246(a)(2) is
slightly different from the language in 40 CFR 98.246(a)(12) and (13),
the scope of 40 CFR 98.246(a)(2) is identical to the collective scope
of 40 CFR 98.246(a)(12) and (13). For example, all gaseous carbon-
containing feedstocks must be entered in the equation X-1 calculation,
all liquid carbon-containing feedstocks must be entered in the equation
X-2 calculation, and all solid carbon-containing feedstocks must be
entered in the equation X-3 calculation. Thus, the current requirement
in 40 CFR 98.246(a)(12) to report the name of each carbon-containing
feedstock used in any of the equations means all carbon-containing
feedstocks must be reported, which is identical to the requirement in
40 CFR 98.246(a)(2) to report the names of carbon-containing
feedstocks. A similar analysis applied to the products results in the
conclusion that the current requirement in 40 CFR 98.246(a)(13) to
report the name of each product used in any of the equations means all
products must be reported, which is identical to the requirement in 40
CFR 98.246(a)(2) to report the names of products. Note that the rule
does not
[[Page 36997]]
specify reporting of ``carbon-containing'' products; this is
unnecessary because the term ``product'' is defined in 40 CFR 98.248 to
mean ``. . .carbon-containing outputs. . .'' To eliminate the
redundancy, we are proposing to delete the requirement to report names
of products and the names of carbon-containing feedstocks from 40 CFR
98.246(a)(2) because the same requirements are also included in 40 CFR
98.246(a)(12) for feedstocks and 40 CFR 98.246(a)(13) for products.
The second amendment to the mass balance reporting requirements is
to revise 40 CFR 98.246(a)(5) and 40 CFR 98.246(a)(13) to clarify the
petrochemical and product reporting requirements for integrated
ethylene dichloride/vinyl chloride monomer (EDC/VCM) process units. In
a letter received from Occidental Chemical Company titled ``Request to
Consider IPCC Balanced EDC/VCM Process Studies and Data for the
Elimination of e-GGRT Validation Messages at VCM Production Facilities
Reporting Under Subpart X,'' dated July 10, 2015 (available in the
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424),
industry representatives indicated that an integrated EDC/VCM process
unit is a continuous process in which the EDC is produced as an
intermediate that is used in the production of VCM; purified EDC
circulates to the VCM production portion of the process, and multiple
recovery loops recycle unconverted EDC from the VCM operations to the
EDC operations for purification. These streams that pass back and forth
between the EDC and VCM portions of the integrated unit are not
isolated and are not measured in a manner that would allow for accurate
calculation of the amount of intermediate EDC produced. Since the
amount of EDC produced as an intermediate in such process units may not
be measured, subpart X was previously amended to allow reporters to
consider the entire integrated EDC/VCM process unit to be the
petrochemical process unit (proposal at 81 FR 2536, January 15, 2016;
final at 81 FR 89188, December 16, 2016). At the same time, 40 CFR
98.246(a)(5) was amended to specify that the amount of intermediate EDC
produced in such units and included in the total reported amount of EDC
petrochemical produced could be based on either measurements or an
estimate. In subsequent years, data reported under subpart X of the
GHGRP indicated that some facilities with an integrated EDC/VCM process
unit withdraw small amounts of the EDC as a separate product stream.
The amendments in 2016 were silent on how to report the amount of any
EDC that is withdrawn as a separate product from the integrated unit.
The intent of the proposed changes is that the amount of EDC product
not used as an intermediate would continue to be determined as it would
be for a standalone EDC process unit, this amount of EDC product would
be added to the amount of intermediate EDC, and the total would be
reported under 40 CFR 98.246(a)(5) as the amount of EDC petrochemical
produced by the integrated EDC/VCM process unit. To clarify this intent
we are proposing to revise 40 CFR 98.246(a)(5) to specify that the
portion of the total amount of EDC produced that is an intermediate in
the production of VCM may be either a measured quantity or an estimate,
the amount of EDC withdrawn from the process unit as a separate product
(i.e., the portion of EDC produced that is not utilized in the VCM
production) is to be measured in accordance with 40 CFR 98.243(b)(2) or
(3), and the sum of the two values is to be reported under 40 CFR
98.246(a)(5) as the total quantity of EDC petrochemical from an
integrated EDC/VCM process unit. We are also proposing a harmonizing
change in 40 CFR 98.246(a)(13) to clarify that the amount of EDC
product to report from an integrated EDC/VCM process unit should be
only the amount of EDC, if any, that is withdrawn from the integrated
process unit and not used in the VCM production portion of the
integrated process unit. Reporting as a product only the quantity of
EDC not used in the VCM process is consistent with the boundary of the
mass balance being around the integrated EDC/VCM process unit.
For facilities that use CEMS, we are proposing a third amendment to
40 CFR 98.246(b)(8) to clarify the reporting requirements for the
amount of EDC petrochemical when using an integrated EDC/VCM process
unit. In previous amendments (81 FR 89188, December 16, 2016),
reporting requirements related to the quantity of intermediate EDC for
an integrated EDC/VCM process unit were added to the petrochemical
quantity reporting requirements at 40 CFR 98.246(b)(8) for CEMS-
monitored units that were identical to the reporting requirements added
to 40 CFR 98.246(a)(5) that are discussed above for mass balance units.
This 2016 language was added so that the reporting requirements would
be the same under both the mass balance methodology and the CEMS
methodology. However, an EDC manufacturer does not need to consider an
integrated EDC/VCM process unit to be the petrochemical process unit
when using CEMS since vent streams are directly monitored and thus
recycle streams from the VCM to EDC process are not required to be
quantified as with a mass balance unit. Under the mass balance option,
the amount of product must be a measured value because the quantity is
used in the emissions calculation equation; thus, we allowed the entire
integrated unit to be considered the petrochemical process unit so the
amount of VCM product could be the primary reported product, and it
would be measured. Under the CEMS option, the product quantity is used
only in data verification procedures and other data analyses, and the
EPA has tentatively determined that, for these purposes, reporting an
estimated value is an acceptable alternative to incurring the expense
of modifying an integrated unit process unit so that measurements can
be taken. Thus, we are proposing to revise 40 CFR 98.246(b)(8) by
removing language related to considering the petrochemical process unit
to be the entire integrated EDC/VCM process unit.
For facilities that use the optional ethylene combustion
methodology to determine emissions from ethylene production process
units, we are proposing a fourth amendment to 40 CFR 98.246(c)(4) to
clarify that the names and annual quantities of feedstocks that must be
reported would be limited to feedstocks that contain carbon. This
proposed change will make the feedstock reporting requirement under the
optional ethylene combustion methodology consistent with the feedstock
reporting requirements under the mass balance and CEMS options.
The fifth proposed change to clarify the reporting requirements
under subpart X consists of clarifying changes to 40 CFR 98.246(a)(15).
Currently, this paragraph specifies that the annual average molecular
weight must be reported for each gaseous feedstock and product. The
proposed revision would more clearly specify that molecular weight must
be reported for gaseous feedstocks and products only when the quantity
of the gaseous feedstock or product used in equation X-1 is in standard
cubic feet; the molecular weight does not need to be reported when the
quantity of the gaseous feedstock or product is in kilograms. This
change would be consistent with statements in the definitions of the
terms for volume or mass in equation X-1. We are also proposing to
rearrange the text in 40 CFR 98.246(a)(15) and split the paragraph into
two sentences to improve clarity.
[[Page 36998]]
These proposed clarifying changes would pose no new monitoring,
reporting, or recordkeeping requirements. We are also proposing related
confidentiality determinations for the new or revised data elements, as
discussed in section VI of this preamble.
L. Subpart Y--Petroleum Refineries
1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart Y
We are proposing several amendments to subpart Y of part 98
(Petroleum Refineries) to improve data collection, clarify rule
requirements, and correct an error in the rule.
For the reasons described in section II.A.2 and II.A.4 of this
preamble, we are proposing to amend some of the requirements for DCUs
to improve data collection and our ability to perform verification of
reported data for these emission sources. During the verification of
DCU emissions, we noted a disproportionate number of facilities were
messaged with potential emission errors that used mass measurements
from company records to estimate the dry coke at the end of the coking
cycle (as an alternative to estimating this quantity using Eq. Y-18a)
in 40 CFR 98.257(b)(41). Through correspondence with facilities
regarding these potential emission errors, we found that the some of
the errors were due to reporters incorrectly determining the mass of
coke at the end of the coking cycle on a wet basis rather than on a dry
basis. This led to an erroneously high value being used for the
Mcoke input parameters to equation Y-18b, resulting in an
unusually low value of Mwater and subsequently lower-than-
expected methane emissions. We also found that some of the errors were
explained by the use of a facility-specific bulk density of coke that
was sufficiently different from the default value used in EPA-estimated
emissions to generate a potential error message. Finally, we found that
some facilities indicated the coke may not be completely submerged by
water due to initiating draining prior to atmospheric venting. Such
activities undermine some of the underlying assumptions of the steam
generation model being used to estimate DCU emissions. In order to
improve the quality of data collected and our ability to ensure the
reported data are accurate, we are proposing two amendments to the DCU
provisions.
The first proposed amendment is designed to enhance the reporting
and recordkeeping specifically for facilities using mass measurements
from company records to estimate Mcoke. Currently,
facilities using mass measurements have less recordkeeping requirements
than those facilities using equation Y-18a to estimate the quantity.
Facilities using equation Y-18a are required to keep records of the
drum outage, drum height, and the drum diameter as specified in 40 CFR
98.257(b)(42) through (44), while facilities using mass measurements
from company records for Mcoke do not have any related
reporting or recordkeeping other than the recordkeeping requirement of
the Mcoke quantity in 40 CFR 98.257(b)(41). Therefore, we
have limited data available by which to verify the reported dry mass of
coke at the end of the cycle, Mcoke. In order to perform
more robust and consistent verification of all of these reported
quantities in future years, we are proposing to add reporting
requirements for facilities using mass measurements from company
records to estimate the amount of dry coke at the end of the coking
cycle in 40 CFR 98.256(k)(6)(i) and (ii). These new subparagraphs would
require these facilities to additionally report, for each DCU: (1) the
internal height of the DCU vessel; and (2) the typical distance from
the top of the DCU vessel to the top of the coke bed (i.e., coke drum
outage) at the end of the coking cycle (feet). These new elements will
allow the EPA to estimate and verify the reported mass of dry coke at
the end of the cooling cycle as well as the reported DCU emissions,
ensuring the most consistent and accurate data are provided. We do not
anticipate that the proposed data elements would require any additional
monitoring or data collection by reporters, as these data are likely
already available in existing company records. We are proposing related
confidentiality determinations for the additional data elements, as
discussed in section VI of this preamble.
The second amendment for DCUs we are proposing is to amend equation
Y-18b in 40 CFR 98.253(i)(2) to include a new variable
``fcoke'' and revise the existing descriptions of the
``Mwater'' output and ``Hwater'' variable. As
noted in the discussion, some of the facilities messaged for potential
emission errors explained that the coke was not completely submerged at
the time the vessel is vented to the atmosphere, which contradicts
assumptions underlying the calculation methodology. First, we are
proposing to revise the definitions of ``Mwater'' and
``Hwater'' to add the phase ``or draining'' to specify that
these parameters reflect the mass of water and the height of water,
respectively, at the end of the cooling cycle just prior to atmospheric
venting or draining. The steam generation model requires a complete
accounting of the heat within the unit prior to venting or draining
since steam generation will occur if superheated water is drained from
the unit prior to venting. We are also proposing similar revisions to
the recordkeeping requirements at 40 CFR 98.257(b)(45) and (46) to add
the phrase ``or draining'' to the description of the records. We are
also proposing to add a new variable ``fcoke'' to equation
Y-18b to allow facilities that do not completely cover the coke bed
with water prior to venting or draining to accurately estimate the mass
of water in the drum. The ``fcoke'' variable would be
defined as the fraction of coke-filled bed that is covered by water at
the end of the cooling cycle just prior to atmospheric venting or
draining, where a value of 1 represents cases where the coke is
completely submerged in water. The second term in equation Y-18b
represents the volume of coke in the drum. It is subtracted from the
water-filled coke bed volume to determine the volume of water. If the
coke bed is not completely submerged in the water, subtracting the
entire volume of coke from the water-filled coke bed volume will
underestimate the actual volume of water in the coke drum vessel,
resulting in an underestimate of the methane emissions. Adding the
``fcoke'' variable to the second term in equation Y-18b
would make the equation universally applicable in cases where the coke
bed is not fully submerged when the coke drum is first vented or
drained. We are also proposing to add a corresponding recordkeeping
requirement at 40 CFR 98.257(b)(53).
We are proposing several clarifying changes, for the reasons
described in section II.A.5 of this preamble. We are proposing to add
clarifying language to 40 CFR 98.253(c) and 98.253(e) to reiterate the
language from 40 CFR 98.252(b) that the emissions being quantified in
these paragraphs are coke burn-off emissions rather than emissions that
may occur from other venting events. The language at 40 CFR 98.252(b)
clearly indicates that the emissions to be reported are ``. . . coke
burn-off emissions from each catalytic cracking unit, fluid coking
unit, and catalytic reforming unit . . . '' [emphasis added]. However,
the language at to 40 CFR 98.253(c) and 98.253(e) could be construed to
apply to other vented emissions. We have received a GHGRP Help Desk
question concerning the applicability of the calculation methodology to
other venting events. To help clarify that the calculation
methodologies in 40 CFR 98.253(c) and 98.253(e) are specific to
[[Page 36999]]
coke burn-off emissions, we are proposing to add ``from coke burn-off''
immediately after the first occurrence of ``emissions'' in the
introductory text of 40 CFR 98.253(c) and 40 CFR 98.253(e).
We are proposing a clarifying change to correct an inconsistency
introduced into subpart Y by the amendments published on December 9,
2016 (81 FR 89188). The introduction to the flare emission calculation
requirements at 40 CFR 98.253(b) was revised in 2016 to state that all
gas discharged through the flare stack must be included in the
calculations except for pilot gas. The intent of this provision was to
require inclusion of purge and sweep gas in addition to SSM events.
However, because equation Y-3 excludes SSM events less than 500,000
scf/day, the new provision created an apparent inconsistency about
whether to include or exclude SSM events less than 500,000 scf/day in
equation Y-3. Some reporters have interpreted that such SSM events must
be included. We are proposing to clarify in 40 CFR 98.253(b) that SSM
events less than 500,000 scf/day may be excluded, but only if reporters
are using the calculation method in 40 CFR 98.253(b)(1)(iii). This
proposed clarification corrects the 2016 amendment, which was not
intended to eliminate the exclusion when reporters use equation Y-3,
and would reduce repeated verification and correction of errors
submitted in reports.
We are proposing a correction to an erroneous cross-reference in 40
CFR 98.253(i)(5) for the reasons described in this section and section
II.A.5 of this preamble. The section inaccurately defines the term
Mstream in equation Y-18f for DCUs. Currently,
Mstream is defined as, ``Mass of steam generated and
released per decoking cycle (metric tons/cycle) as determined in
paragraph (i)(3) of this section.'' The correct cross-reference is
paragraph (i)(4) instead of (i)(3). The proposed change would not have
any impact on burden.
Finally, we are proposing a change to correct an inconsistency
introduced into subpart Y by the amendments published on December 9,
2016 (81 FR 89188). The DCU emission calculations were updated in 2016,
and, as part of that update, 40 CFR 98.253(j) was revised to remove the
option to calculate CH4 emissions from DCUs using the
process vent method (equation Y-19). However, the DCU recordkeeping
requirements for the process vent method at 40 CFR 98.257(b)(53)
through (56) were inadvertently not removed from the rule. We are
proposing to revise 40 CFR 98.257(b)(53) to include recordkeeping
requirement for the ``fcoke'' variable, as previously
discussed in this section, and to remove and reserve the recordkeeping
requirements in paragraphs 98.257(b)(54) through (56) since equation Y-
19, the process vent calculation method, is no longer used to calculate
DCU emissions.
2. Proposed Revisions To Streamline and Improve Implementation for
Subpart Y
For the reasons described in this section and in section II.B.2 of
this preamble, we are proposing to allow the use of mass spectrometer
analyzers to determine gas composition and molecular weight without the
use of a gas chromatograph. Currently, the methods for determining gas
composition in 40 CFR 98.254(d) rely on gas chromatography. Advances in
data analytics have made it easier for mass spectrometer analyzers to
determine concentrations of individual compounds from a mixture of
hydrocarbons without the need for pre-separation of the compounds using
gas chromatography. Direct analysis using mass spectrometer analyzers
greatly reduces the cycle time between sample analyses, allowing
improved process control. As such, some refinery owner/operators use
direct mass spectrometer analyzers to determine gas stream composition.
The proposed inclusion of direct mass spectrometer analysis as an
allowable gas composition method in 40 CFR 98.254(d) would allow these
reporters to use the same analyzers used for process control or for
compliance with continuous sampling required under the National
Emissions Standards for Hazardous Air Pollutants from Petroleum
Refineries (40 CFR part 63, subpart CC) to comply with GHGRP
requirements in subpart Y. Currently, these reporters have to conduct
separate periodic sampling of these gas streams for analysis using gas
chromatography to comply with GHGRP requirements in subpart Y. Thus,
the proposed inclusion of mass spectrometer analyzers for determining
gas composition will reduce the burden for these reporters. It is also
expected to provide more accurate data due to the use of continuous
analyzers rather than periodic sampling.
M. Subpart BB--Silicon Carbide Production
For the reasons described in section II.A.4 of this preamble, we
are proposing revisions to the reporting requirements for subpart BB of
part 98 (Silicon Carbide Production) to improve the quality of the data
collected under the GHGRP.
The original 2009 GHG Reporting Rule for silicon carbide production
required reporting CH4 emissions by measuring petroleum coke
consumption and applying a default CH4 emission factor of
10.2 kilograms of CH4 per metric ton of coke consumed (see
74 FR 56260). However, in 2013, we removed the requirement for silicon
carbide production facilities to report CH4 emissions from
silicon carbide process units or furnaces and the CH4
calculation methodology because we determined that the then-current
CH4 calculation methodologies in subpart BB overestimated
the emissions of CH4 from silicon carbide facilities. At the
time we determined the following: the equations did not take into
consideration the destruction of CH4 emissions, the
CH4 emissions from these facilities were typically
controlled, the CH4 emissions from these facilities were
minimal, and the requirement to report CH4 emissions was not
necessary to understand the emissions profile of the industry (see 78
FR 19802, April 2, 2013, and 78 FR 71904, November 29, 2013). The
determination to not require reporting of CH4 emissions was
predicated on the conclusion that because CH4 emissions are
typically controlled, CH4 emissions from these facilities
are minimal. Although our understanding is still that CH4
emissions are typically controlled, we are proposing to amend the rule
in order to gather more information on CH4 control practices
at silicon carbide production facilities to better understand the
extent of those control practices and their impact on CH4
emissions. Specifically, we are interested in how the CH4
emissions are controlled, the efficiency of the control technologies,
and to what extent these technologies are operated throughout the year.
As such, we are proposing adding new reporting requirement 40 CFR
98.286(c) such that if CH4 abatement technology is used at
silicon carbide production facilities, then facilities must report: (1)
the type of CH4 abatement technology used, and the date of
installation for each; (2) the CH4 destruction efficiency
(percent destruction) for each CH4 abatement technology; and
(3) the percentage of annual operating hours that CH4
abatement technology was in use for all silicon carbide process units
or production furnaces combined. The proposed reporting requirements
would be used to confirm the operation and efficiency of CH4
abatement at silicon carbide facilities and would enable us to
determine whether the EPA's 2013 determination that CH4
emissions are typically controlled (and therefore minimal) remains
accurate. Although
[[Page 37000]]
silicon carbide facilities would continue to not be required to
estimate CH4 emissions from their processes for their GHGRP
annual report, providing data on CH4 abatement technology
and usage would allow the EPA to assess the potential for unabated
CH4 emissions that may influence the industry's emission
profile under the GHGRP. We also anticipate that we could use this kind
of information to better understand methane emission control practices
at silicon carbide facilities, to improve the EPA's knowledge of
CH4 emissions that may be useful for other CAA programs, or
to support future climate change policies, non-regulatory initiatives,
or regulations under the CAA. The proposed data could also be used to
help estimate CH4 emissions from silicon carbide facilities
at the national level, and thereby inform and improve the U.S. GHG
Inventory by allowing for more accurate estimates that account for
CH4 removal.
We are also proposing that for each CH4 abatement
technology, reporters must either use the manufacturer's specified
destruction efficiency or the destruction efficiency determined via a
performance test; if the destruction efficiency is determined via a
performance test, reporters must also provide the name of the test
method that was used during the performance test. We note that the
collection of data elements related to GHG abatement and methane
destruction are consistent with other subparts such as subparts E
(Adipic Acid Production), I (Electronics Manufacturing), V (Nitric Acid
Production), HH (Municipal Solid Waste Landfills), and FF (Underground
Coal Mines) of part 98. For these subparts, reporters are typically
provided an option to account for the destruction of methane in their
estimated emissions (e.g., fluorinated gases abated in electronics
manufacturing processes or collection and destruction of methane at MSW
facilities) and provide similar information on the type of abatement
technology, hours of operation, and destruction or control
efficiencies. This data is typically used for verification of emissions
estimates and to confirm where process technologies or control measures
result in minimal emissions. The collection of abatement data from
silicon carbide facilities would be consistent with this practice.
Finally, we are proposing that upon reporting this information once in
an annual report, reporters would not be required to report this
information again unless the information changed during another
reporting year, in which case, the reporter would update the
information in the submitted annual report. However, if it appeared
that operational practices change at facilities such that
CH4 emissions are not consistently controlled from year to
year or that unabated CH4 emissions may be a more
substantive contributor to industry emissions, then the EPA may
consider whether it would be beneficial to reintroduce CH4
calculation methodology and reporting requirements. We are proposing
adding recordkeeping requirement 40 CFR 98.287(d) for facilities to
maintain a copy of the reported data.
Based on review of available permits, we anticipate that reporters
could obtain the proposed data elements from data that is collected and
readily available to facilities as part of their standard operation.
For example, as part of normal operations, we assume facilities would
keep records of any time that the CH4 abatement technology
was not in use; therefore, the facility could then calculate the
percent of total operating hours that the abatement technology was not
in use. We are soliciting comment on whether this assumption is
correct. We are also proposing related confidentiality determinations
for the additional data elements, as discussed in section VI of this
preamble.
We are also seeking comment on alternative methods for determining
destruction efficiency (i.e., methods other than using either the
manufacturer's specified destruction efficiency or the destruction
efficiency determined via a performance test). For example, we are
considering whether it would be more reasonable to allow for the
``lesser of manufacturer's specified destruction efficiency and 0.99,''
as is required in subpart HH.
N. Subpart DD--Electrical Transmission and Distribution Equipment Use
1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart DD
For the reasons discussed in section II.A.3 of this preamble, we
are proposing several revisions to subpart DD of part 98 (Electrical
Transmission and Distribution Equipment Use) to improve the quality of
the data collected from this subpart. These include adding F-GHGs other
than SF6 and PFCs to the monitoring, calculation, and
reporting requirements of subpart DD (at 40 CFR 98.302, 98.303, 98.304,
98.305, and 98.306), clarifying the definition in 40 CFR 98.308 for
``facility,'' adding definitions for ``energized,'' ``insulating gas,''
``new equipment,'' and ``retired equipment,'' and specifying procedures
in 40 CFR 98.303(b) for establishing user-measured nameplate capacity
values for new and retiring equipment.
Currently, this subpart includes all electric transmission and
distribution equipment and servicing inventory insulated with or
containing SF6 or PFCs used within an electric power system.
We are proposing to revise the existing calculation, monitoring, and
reporting requirements of subpart DD to require reporting of additional
F-GHGs as defined under 40 CFR 98.6. At the time of the 2010 Final Rule
for Additional Fluorinated GHGs, SF6 was the most commonly
used insulating gas in the electrical power industry, and PFCs were
occasionally used as dielectrics and heat transfer fluids in power
transformers. During the implementation of the reporting program,
electrical power systems equipment manufacturers and F-GHG suppliers
have introduced alternative technologies and replacements for
SF6 with lower GWPs, including fluorinated gas mixtures,
such as fluoronitriles or fluoroketones mixed with carrier gases (e.g.,
CO2 and O2), as a replacement for dielectric
insulation gases. The GWPs of these gases are generally much lower than
the GWP of SF6; the GWPs of fluoronitrile mixtures are
typically estimated to fall between 300 and 500, whereas the GWPs of
fluoroketone mixtures are usually estimated to be less than 1. The EPA
is aware that some electric power systems are currently using or
considering use of these alternative gas mixtures; Therefore, we are
proposing revisions to the reporting requirements in order to capture
emissions from equipment using these alternative gases that are not
currently accounted for. While the use of alternative insulation gases
will generally result in lower GHG emissions, we would expect that that
increased usage of these alternative technologies, particularly
fluoronitrile mixtures, could still significantly contribute to the
total GHG emissions from this sector if used in large quantities. The
proposed reporting of these additional F-GHGs would improve the
accuracy and completeness of the emissions reported under subpart DD
and enhance the overall quality of the data collected under the GHGRP.
To implement these revisions, we are proposing at 40 CFR 98.300(a)
to redefine the source category to include equipment containing
``fluorinated GHGs (F-GHGs), including but not limited to sulfur-
hexafluoride (SF6) and perfluorocarbons (PFCs).'' As
discussed in section III.N.2 of this preamble, the proposed changes
would also apply to the threshold in 40 CFR 98.301. Under
[[Page 37001]]
the proposed rule, both electric power systems and electric generating
units with insulated equipment would also consider any additional F-
GHGs, including those in F-GHG mixtures, used at the facility in the
nameplate capacity used for estimating the threshold. At this time, we
are unaware of any facilities that currently use the alternative gas
mixtures exclusively or in large quantities that would render them
newly subject to the subpart; therefore, we expect the minimal burden
from the proposed requirements would fall on existing reporters, who
would only be required to account for the additional F-GHGs in their
gas-insulated equipment (GIE) and inventory.
The proposed revisions to subpart DD include minor revisions to
equation DD-1 (which would be redesignated as equation DD-3 at 40 CFR
98.303(a) under this proposed rule) to incorporate the estimate of
emissions from all F-GHGs within the existing calculation methodology,
including F-GHG mixtures. Equation DD-3 would maintain the facility-
level mass balance approach of tracking and accounting for decreases,
acquisitions, disbursements, and net increase in total nameplate
capacity for the facility each year, but would require applying the
weight fraction of each F-GHG to determine the user emissions by gas.
It is our understanding that facilities receive gas in equipment pre-
mixed and do not mix the gas themselves; therefore, the proposed
revisions assume that facilities will track the mixtures received, and
rely on supplier data to obtain the weight fraction of each F-GHG
within equipment containing a gas mixture. Facilities would need to
track mixtures with unique weight fractions of individual F-GHGs
separately. However, we are seeking comment on whether the weight
fraction of individual F-GHGs is readily available from supplier data.
We are also seeking comment on whether there are facilities that mix
gas in equipment on site, or that expect to mix gas in equipment at the
facility in the future, and whether we should account for this mixing
in the current equation. Since we assumed that gases are typically
received pre-mixed, the proposed changes include reporting of an ID
number or descriptor for each insulating gas and the name and weight
percent of each fluorinated gas of each insulating gas reported. To
simplify references to F-GHGs and F-GHG mixtures throughout the subpart
(especially in equation DD-3), we are proposing to introduce the term
``insulating gas'' and to define it as follows: ``Insulating gas, for
the purposes of this subpart, means any fluorinated GHG or fluorinated
GHG mixture, including but not limited to SF6 and PFCs, that
is used as an insulating and/or arc quenching gas in electrical
equipment.'' The proposed changes also include updating the monitoring
and quality assurance requirements at 40 CFR 98.304(b) to account for
emissions from additional F-GHGs, and harmonizing revisions to the term
``facility'' in the definitions section at 40 CFR 98.308, and the
requirements at 40 CFR 98.302, 40 CFR 98.305, and 40 CFR 98.306 such
that reporters would account for the mass of each F-GHG for each
electric power system. The proposed changes would not significantly
revise the existing calculation, monitoring, or reporting requirements;
therefore, we expect only a minimal increase in burden due to the
collection of data for any equipment containing F-GHGs that are not
SF6 or PFCs. We are proposing related confidentiality
determinations for the revised data elements that incorporate
additional F-GHGs, as discussed in section VI of this preamble. We are
proposing one additional change to remove an outdated monitoring
provision at 40 CFR 98.304(a), which reserves a prior requirement for
use of BAMM that applied solely for RY2011.
For the reasons described in section II.A.5 of this preamble, we
are also proposing to add new definitions to clarify the existing
provisions of the rule. The mass balance methodology in 40 CFR 98.303
(used for calculating facility emissions) uses the terms ``new'' and
``retired'' to describe equipment added to or removed from active use,
and reporters are required to report nameplate capacity and the number
of F-GHG containing pieces of any new and retired equipment. We have
previously received questions from reporters regarding what equipment
should be included as new or retired equipment each year, and we
developed interpretations of these terms for our list of Frequently
Asked Questions.\112\ We are proposing to adopt the previous
interpretations into the rule's requirements in order to help ensure
that reporters correctly estimate emissions, which would improve the
quality of the data collected. The proposed revisions would also reduce
time spent searching the list of Frequently Asked Questions or
responding to questions through the GHGRP Help Desk.
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\112\ U.S. EPA. ``Q852. What equipment should be included as new
or retired equipment each year for Subpart DD?'' April 6, 2020.
https://ccdsupport.com/confluence/pages/viewpage.action?pageId=721715270.
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First, we are proposing a definition at 40 CFR 98.308 of
``energized'' to more clearly designate what equipment is considered to
be installed and functioning as opposed to being in storage. The
proposed definition clarifies that energized equipment includes gas-
insulated equipment (including hermetically-sealed pressure switchgear)
that is connected through busbars or cables to an electrical power
system or that is fully-charged, ready for service, and being prepared
for connection to the electrical power system, and does not include
spare GIE (including hermetically-sealed pressure switchgear) in
storage that has been acquired by the facility, and is intended for use
by the facility, but that is not being used or prepared for connection
to the electrical power system. Consistent with our previous
interpretation, we are proposing to add a definition for ``new
equipment'' to mean any GIE, including hermetically-sealed pressure
switchgear, that is not energized at the beginning of the reporting
year, but is energized at the end of the reporting year. Similarly, we
are proposing a definition for ``retired equipment'' to mean any GIE,
including hermetically-sealed pressure switchgear, that is energized at
the beginning of the reporting year, but is not energized at the end of
the reporting year. Finally, we are clarifying that (1) new equipment
may also include equipment that has been transferred while in use,
meaning it has been added to the facility's inventory without being
taken out of active service (e.g., when the equipment is sold to or
acquired by the facility while remaining in place and continuing
operation), and (2) retired equipment may also include equipment that
has been transferred while in use, meaning it has been removed from the
facility's inventory without being taken out of active service (e.g.,
when the equipment is acquired by a new facility while remaining in
place and continuing operation).
The proposed definitions of ``energized,'' ``new equipment,'' and
``retired equipment'' are intended to clarify how these terms should be
interpreted for purposes of the equation used to estimate emissions for
annual reporting (i.e., the current equation DD-1, which we are
proposing to redesignate as equation DD-3). This equation uses a mass-
balance approach that assesses annual net gas consumption (based on the
decrease in gas inventory and gas acquisitions and disbursements) and
accounts for gas used or freed up, respectively, by equipment
installations and
[[Page 37002]]
retirements.\113\ The nameplate capacity of new equipment is subtracted
from the total, reflecting the fact that some of the insulating gas
consumed is used to fill the new equipment, while the nameplate
capacity of retiring equipment is added to the total, reflecting the
fact that the gas formerly used to fill the retiring equipment, unless
emitted, would either be added to the gas inventory or disbursed (e.g.,
to an SF6 recycling company). Implicit in this approach are
the assumptions that ``new'' equipment is filled with insulating gas
during the same year that it is considered ``new,'' and that
``retired'' equipment is emptied of insulating gas during the same year
that it is considered ``retired.'' \114\ We request comment on whether
new equipment is typically filled with gas during the same year that it
is ``energized'' under the proposed definition of ``energize,'' and on
whether retiring equipment is typically emptied of gas during the same
year that it ceases to be ``energized'' under the proposed definition.
If gas is added to or removed from ``new'' and/or ``retired'' equipment
in a year different from the year that the equipment is energized or
ceases to be energized, respectively, it may be clearer to directly tie
the terms ``new'' and ``retired'' to the filling and emptying of the
equipment (for closed-pressure equipment).
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\113\ This particularly applies to closed-pressure equipment.
Closed-pressure equipment is typically delivered to the facility
without a full and proper charge of insulating gas and therefore
must be filled to the full and proper charge before it is energized.
Similarly, closed-pressure equipment is typically emptied of
insulating gas before it is sent off-site for recycling or disposal.
Hermetically sealed-pressure equipment, on the other hand, is
generally expected to be fully charged upon delivery unless it has
leaked en route. Hermetically sealed-pressure equipment is also
often sent off-site (e.g., returned to the equipment manufacturer)
with its charge intact unless it has leaked over its lifetime.
\114\ Note that this logic does not necessarily apply to
equipment that is ``new'' or ``retired'' because it is transferred
to or from another owner while it remains energized. In this case,
we are assuming that insulating gas is not generally added to or
removed from equipment upon transfer, and that both the transferring
and receiving facilities would presume that the equipment is
transferring with its full and proper charge, meaning that the
transfer of such equipment would not affect the emissions calculated
under the mass-balance equation. We request comment on whether this
assumption is correct.
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In 40 CFR 98.303(b) we are proposing to require users of electrical
equipment to follow certain procedures when they elect to measure the
nameplate capacities (in units of mass of insulating gas) of new and
retiring equipment rather than relying on the rated nameplate
capacities provided by equipment manufacturers. This option would be
available only for closed-pressure equipment with a voltage capacity
greater than 38 kV, not for hermetically sealed pressure equipment or
smaller closed-pressure equipment. The procedures are intended to
ensure that the nameplate capacity values that equipment users measure
match the full and proper charges of insulating gas in the electrical
equipment. These procedures are also intended to be similar to and
compatible with the procedures for measuring nameplate capacity adopted
by the California Air Resources Board (CARB) in its Regulation for
Reducing Sulfur Hexafluoride Emissions from Gas Insulated Switchgear
(effective January 1, 2022).\115\
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\115\ State of California Air Resources Board, ``Regulation for
Reducing Sulfur Hexafluoride Emissions from Gas Insulated
Switchgear.'' Available at https://ww2.arb.ca.gov/rulemaking/2020/sf6?utm_medium=email&utm_source=govdelivery.
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As discussed above, the nameplate capacities of new and retiring
electrical equipment are used in the current equation DD-1 of subpart
DD (which would be redesignated as equation DD-3 under this proposed
rule), which calculates annual GHG emissions from the equipment. In the
equation, nameplate capacity is defined as referring to ``the full and
proper charge of equipment rather than to the actual charge, which may
reflect leakage.'' With each piece of electrical equipment, electrical
equipment manufacturers typically provide a rated nameplate capacity in
pounds of SF6 (or other insulating gas) on a nameplate
affixed to the equipment and/or in the product specifications. When the
EPA promulgated subpart DD, we expected that users of electrical
equipment would be able to use these rated nameplate capacities in
their emissions calculations without introducing any errors. Experience
has shown, however, that even when users of electrical equipment follow
industry-accepted equipment filling and gas measuring methods, the mass
of insulating gas contained in the equipment when it is filled to the
manufacturer-specified density can sometimes differ from that specified
on the nameplate. That is, the actual nameplate capacity of the
equipment (the full and proper charge) can differ from the rated
nameplate capacity of the equipment.\116\
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\116\ Electrical equipment manufacturers indicate that this is
because the rated nameplate capacity was historically only intended
to indicate the approximate mass of gas required to fill equipment.
The full and proper charge for a given model of equipment can vary
from year to year and even from one piece of equipment to the next
due to minor design changes and manufacturing variability. To ensure
that the equipment functions correctly, manufacturers provide
precise instructions for filling to the proper density. (The
Electric Transmission & Distribution SF6 Coalition
(administered by NEMA), SF6 Reporting Challenges, undated. Accessed
at https://www.nema.org/docs/default-source/products-document-library/sf6-reportingchallenges.pdf on June 3, 2021.)
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Differences between the actual and rated nameplate capacities may
result in either under- or over-estimates of emissions in the short
run, depending on: (1) whether the actual nameplate capacity is greater
than the rated nameplate capacity or vice versa; and (2) whether the
equipment is being commissioned or retired. For example, if the actual
nameplate capacity of new equipment is larger than the rated nameplate
capacity of that equipment, emissions will be overestimated, because
some of the gas that was actually used to fill the new equipment will
be assumed to have been emitted. On the other hand, if the actual
nameplate capacity of retiring equipment is larger than the rated
nameplate capacity of the equipment, emissions will be underestimated
(and may even be calculated as negative), because the quantity of gas
recovered or emitted from the retiring equipment will be larger than is
accounted for by the equation. (More scenarios are described in the
document Technical Support for Proposed Revisions to Subpart DD (2021)
included in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-
2019-0424.)
As the above example shows, these underestimates and overestimates
from a piece of equipment would cancel out over the lifetime of the
equipment. To some extent, they may also cancel out in any given year
because rated nameplate capacities can be either larger or smaller than
the actual nameplate capacities, and most electrical equipment users
are likely to both install and retire several pieces of equipment
during the year. However, if a large piece of electrical equipment (or
several smaller pieces of electrical equipment) is installed or retired
in a given year, an error in the rated nameplate capacity of that
equipment could potentially have a significant impact on the calculated
emissions from the electrical equipment user in that year.
For this reason, when electrical equipment users have asked the EPA
via the Helpdesk whether they may use a nameplate capacity value
different from the rated nameplate capacity value in their calculations
and reporting under subpart DD, we have responded \117\ that
[[Page 37003]]
they may use the nameplate capacity value that corresponds to the full
and proper charge of the equipment, which is determined based on
density (e.g., the temperature-corrected pressure of the equipment) per
the manufacturer's filling instructions. We have also noted that
subpart DD does not currently specify a method for calculating
nameplate capacity values, but for the mass-balance approach to yield
correct results, the nameplate capacity value should reflect any
shipping charge contained in the equipment upon delivery, and the same
nameplate capacity value should be used throughout the life of the
equipment. Finally, we have noted that paragraph 98.3(g)(2) requires
equipment users to keep records of the method used to calculate the
nameplate capacity value.
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\117\ See documents ``HELPDESK-64899'' and ``HELPDESK-30364'',
available in the docket for this rulemaking (Docket Id. No. EPA-HQ-
OAR-2019-0424).
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The process that we are proposing in this action would elaborate on
and adopt this guidance into the rule's requirements. It is designed to
avoid a number of potential errors by equipment users that can result
in inaccuracies in the nameplate capacities that they measure. Such
errors can occur when:
Equipment is deliberately overfilled or underfilled;
Shipping charges are accounted for incorrectly or not at
all;
Inaccurate weigh scales, flowmeters, pressure gauges, or
thermometers are used to fill equipment;
The temperature of the insulating gas is not measured
accurately when the equipment is filled or emptied (e.g., the
temperature of the gas is incorrectly equated to the ambient
temperature);
The insulating gas in equipment (especially retiring
equipment) is not completely recovered (or the gas remaining in the
equipment is not accounted for);
Previous leakage from equipment (especially retiring
equipment) is not accounted for; or
Insulating gas in hoses and gas carts is not accounted
for.
To avoid these potential errors, the EPA is proposing certain
requirements at 40 CFR 98.303(b) for when electrical equipment users
measure the nameplate capacity of new equipment that they install.
These proposed requirements for new equipment would help ensure that
electrical equipment users:
Correctly account for the mass of insulating gas contained
in equipment upon delivery from the manufacturer (i.e., the holding
charge);
Use flowmeters or weigh scales that meet certain accuracy
and precision requirements to measure the mass of insulating gas added
to the equipment;
Use pressure-temperature charts and pressure gauges and
thermometers that meet certain accuracy and precision requirements to
fill equipment to the density specified by the equipment manufacturer,
allowing appropriate time for temperature equilibration; and
Ensure that insulating gas remaining in hoses and gas
carts is correctly accounted for.
The EPA is also proposing certain requirements at 40 CFR 98.303(b)
for when electrical equipment users measure the nameplate capacity of
retiring equipment. These proposed requirements for retiring would help
ensure that electrical equipment users:
Correctly account for the mass of insulating gas contained
in equipment upon retirement, measuring the actual temperature-adjusted
pressure and comparing that to the temperature-adjusted pressure that
reflects the correct filling density of that equipment;
Use flowmeters or weigh scales that meet certain accuracy
and precision requirements to measure the mass of insulating gas
recovered from the equipment;
Use pressure-temperature charts and pressure gauges and
thermometers that meet certain accuracy and precision requirements to
recover the insulating gas from the equipment to the correct blank-off
pressure, allowing appropriate time for temperature equilibration; and
Ensure that insulating gas remaining in the equipment,
hoses and gas carts is correctly accounted for.
We are proposing at 40 CFR 98.303(b)(6) that instead of measuring
the nameplate capacity of electrical equipment when it is retired,
users may measure the nameplate capacity of electrical equipment
earlier during maintenance activities that require opening the gas
compartment. In this case, the equipment user would still be required
to follow the measurement procedures required for retiring equipment at
40 CFR 98.303(b)(5) to measure the nameplate capacity, and the measured
nameplate capacity would be recorded but would not be used in equation
DD-3 until that equipment was actually retired.
As previously mentioned, only closed-pressure equipment with a
voltage capacity greater than 38 kV would be eligible for nameplate
capacity measurement and correction. This is because the quantities of
insulating gas that are typically inside hermetically sealed-pressure
equipment and in closed pressure equipment with smaller voltage
capacities are individually and collectively less significant than
those in closed-pressure equipment with voltage capacities at or above
38 kV. Consequently, any errors in the rated nameplate capacities of
smaller equipment are not likely to have a significant impact on the
calculated emissions of equipment users, and efforts to correct the
nameplate capacity values of smaller equipment do not appear to be
justified by the improvement in accuracy that would result. CARB has
established eligibility criteria similar to those we are proposing
based on their finding that the criteria would cover ``approximately 23
percent of California's GIE [gas insulated equipment] and approximately
80 percent of the SF6 used in the State.'' \118\ In
addition, users rarely add or remove gas to or from hermetically
sealed-pressure equipment, by design. We request comment on the
proposed eligibility criteria.
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\118\ State of California Air Resources Board, ``Notice of
Public Availability of Modified Text: Proposed Amendments to the
Regulation for Reducing Sulfur Hexafluoride Emissions from Gas
Insulated Switchgear,'' May 5, 2021, pp. 17-18.
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We are proposing a scheme in 40 CFR 98.303(b) that would require
all eligible new and retiring equipment to be treated consistently with
respect to the measurement and adoption of nameplate capacities. To
avoid biases that could result from measuring and adopting nameplate
capacities for some pieces of eligible new or retiring equipment but
not others, electrical equipment users electing to measure the
nameplate capacities of any new or retiring equipment would be required
at 40 CFR 98.303(b)(1) to measure the nameplate capacities of all
eligible new and retiring equipment in that year and in all subsequent
years. For each piece of equipment, the electrical equipment user would
be required to calculate the difference between the user-measured and
rated nameplate capacities, verifying that the rated nameplate capacity
was the most recent available from the equipment manufacturer. Where a
user-measured nameplate capacity differed from the rated nameplate
capacity by two percent or more, the electrical equipment user would be
required at 40 CFR 98.303(b)(2) to adopt the user-measured nameplate
capacity for that equipment for the remainder of the equipment's life.
Where a user-measured nameplate capacity differed from the rated
nameplate capacity by less than two percent, the electrical equipment
user would have the option at 40 CFR 98.303(b)(3) to adopt the user-
measured nameplate capacity, but if they chose to do so they would be
required to adopt the user-measured nameplate capacities for all new
and retiring equipment
[[Page 37004]]
whose user-measured nameplate capacity differed from the rated
nameplate capacity by less than two percent. As is the case for the
proposed requirement to consistently measure or not measure the
nameplate capacities of all new and retiring equipment, the proposed
requirement to consistently adopt or not adopt the user-measured
nameplate capacities where they differ from the rated nameplate
capacity by less than two percent is intended to avoid bias that could
result from adopting only a subset of the user-measured nameplate
capacities that fall into this category.
We are proposing the two-percent tolerance for differences between
the user-measured and rated nameplate capacities because, given the
precisions and accuracies that we are proposing for the measuring
devices (scales, gauges, etc.) used to calculate nameplate capacities
(as discussed further in this section), differences of one percent or
less are not expected to be mathematically meaningful. We request
comment on the value of two percent and on whether the percentage
tolerance should be supplemented by an absolute tolerance, such as 100
pounds of SF6 (equivalent to 1,034 mtCO2e). In
the latter case, differences equal to or greater than the lesser of two
percent or 100 pounds would trigger the requirement to use the user-
measured nameplate capacity. The drawback of using a separate absolute
tolerance is that this tolerance may not be mathematically meaningful
if the full and proper charge of the equipment exceeded 10,000 pounds.
Our proposal to allow electrical equipment users to adopt the user-
measured nameplate capacity even when the difference between that
capacity and the rated capacity is less than two percent is based on
our desire to maintain as much consistency as possible between GHGRP
requirements and the proposed requirements of CARB. Our understanding
is that CARB is proposing \119\ to require electrical equipment users
in California to measure the nameplate capacity of all newly installed
closed pressure equipment with a voltage capacity greater than 38 kV
and to adopt the measured value irrespective of the magnitude of the
difference between the measured value and the manufacturer-supplied
value.
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\119\ Attachment A: Modifications to the Proposed Regulation
Order, California Air Resources Board, available at https://ww3.arb.ca.gov/board/15day/sf6/15dayatta.pdf.
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When electrical equipment is retired, the quantity of the gas
remaining in the equipment may reflect leakage that has occurred since
the last time the equipment was serviced or re-filled. In this case, we
are proposing at 40 CFR 98.303(b)(5) to allow equipment users to
account for the leakage using one of two approaches. In both
approaches, equipment users would: (1) measure the temperature-
compensated pressure of the equipment before they removed the
insulating gas from that equipment; and (2) compare the measured
temperature-compensated pressure to the temperature-compensated
pressure corresponding to the full and proper charge of the equipment
(the design operating pressure). If the measured temperature-
compensated pressure was different from the temperature-compensated
pressure corresponding to the full and proper charge of the equipment,
the equipment user could either (a) add or remove insulating gas to or
from the equipment until the equipment reached its full and proper
charge, recover the gas until the equipment reached a pressure of 0.068
pounds per square inch, absolute (psia) (3.5 Torr) or less,\120\ and
weigh the recovered gas (charge adjustment approach), or (b) if the
measured temperature-compensated pressure was at least 90 percent of
the temperature-compensated design operating pressure, recover the gas
that was already in the equipment, weigh it, and account mathematically
for the difference between the quantity of gas recovered from the
equipment and the full and proper charge (mathematical adjustment
approach). In the mathematical adjustment approach, proposed as
equation DD-4, the equipment user would calculate the mass of the full
and proper charge by scaling up the mass recovered by the ratio of
pressures (in absolute terms) corresponding to the full and proper
charge and the actual charge, respectively, accounting for any
insulating gas remaining in the equipment (if the final pressure of the
equipment exceeded 0.068 psia).\121\ We are proposing to limit the
mathematical adjustment approach to situations where the measured
temperature-compensated pressure is equal to or greater than 90 percent
of the design operating pressure to ensure that nameplate capacity
measurements and calculations remain precise. If smaller fractions of
the full charge are scaled up to calculate the nameplate capacity, the
uncertainty of the calculation begins to approach (and ultimately
exceed) two percent given the precision and accuracy requirements we
are proposing for pressure gauges and other measurement devices. We
request comment on the expected accuracy of the mathematical adjustment
approach, and whether it should be enhanced to account for non-
linearities in the relationship between pressure and density. Our
analysis of this issue, discussed in the Technical Support Document,
indicates that such non-linearities can lead to systematic errors in
the results of the mathematical adjustment approach under some
circumstances. One way of addressing such non-linearities would be to
include a compressibility factor (often termed a ``Z'' factor) in the
calculation, as we have done for gas measurements for other subparts
(see, e.g., equation I-25 of subpart I (Electronics Manufacturing) and
equation L-33 of subpart L (Fluorinated Gas Production) of part 98). A
version of equation DD-4 including compressibility factors is included
in the Technical Support Document.
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\120\ 3.5 Torr is a common ``blank-off pressure'' to which gas
carts are designed to recover insulating gas from electrical
equipment. At 3.5 Torr, the EPA estimates that 0.1 percent of the
full and proper charge of insulating gas would remain in the
equipment, assuming that a full and proper charge has a pressure of
5 atmospheres (3800 Torr). We are therefore proposing to treat
quantities of gas remaining at pressures of 3.5 Torr and below as
negligible in nameplate capacity calculations.
\121\ Equipment users could also use a hybrid approach wherein
they would top up the equipment but account mathematically for any
gas remaining in equipment at a pressure above 0.068 psia.
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The mathematical adjustment approach would accommodate situations
where it may not be possible to fully recover the insulating gas from
the equipment, e.g., where the equipment has leaks through which air
would be drawn into the equipment and subsequently into the recovery
equipment or gas cart if the equipment were drawn into a deep vacuum.
However, as discussed further in the Subpart DD TSD, an inability to
pull the equipment into a vacuum may lead to inaccurate nameplate
capacity measurements unless the accuracy and precision requirements
for pressure gauges are tightened beyond those in the proposed rule. We
request comment on this issue and on alternative methods for addressing
nameplate capacity measurements for equipment with large leaks. For
example, CARB has adopted an exception to its nameplate capacity
measurement requirements for equipment with ``compromised integrity.''
The mathematical adjustment approach would also avoid some of the
disadvantages of the charge adjustment approach, which, compared to the
mathematical adjustment approach, would be more time-consuming and
risks emitting more insulating gas and
[[Page 37005]]
contaminating the insulating gas used to top up the equipment with
impurities in the gas that remains in the equipment.
To ensure that the mass-balance method is based on consistent
nameplate capacity values throughout the life of the equipment, we are
proposing at 40 CFR 98.303(b)(9) that electrical equipment users would
be allowed to measure and revise the nameplate capacity value of any
given piece of equipment only once, unless the nameplate capacity
itself is likely to have changed due to changes to the equipment (e.g.,
replacement of the equipment bushings).
Currently, subpart DD requires that scales used to measure
cylinders of gas be accurate and precise to within 2 pounds of true
weight and be periodically recalibrated per the manufacturer's
specifications. Subpart DD does not include accuracy or precision
requirements for other measuring devices, such as flow meters, pressure
gauges, or thermometers. To help ensure that electrical equipment users
obtain accurate measurements of their equipment's nameplate capacities,
we are therefore proposing at 40 CR 98.303(b)(10) that electrical
equipment users use measurement devices that meet the following
accuracy and precision requirements when they measure the nameplate
capacities of new and retiring equipment.
(1) Flow meters must be certified by the manufacturer to be
accurate and precise to within one percent of the largest value that
the flow meter can, according to the manufacturer's specifications,
accurately record.
(2) Pressure gauges must be certified by the manufacturer to be
accurate and precise to within 0.5 percent of the largest value that
the gauge can, according to the manufacturer's specifications,
accurately record.
(3) Temperature gauges must be certified by the manufacturer to be
accurate and precise to within 1.0 [deg]F; and
(4) Scales must be certified by the manufacturer to be accurate and
precise to within one percent of the true weight.
These requirements are the same as those proposed by CARB in its
May 5, 2021 and June 17, 2021 documents,\122\ except we are clarifying
that the measurement devices must be precise as well as accurate. The
measurement devices listed here would be subject to the general GHGRP
calibration requirements at 40 CFR 98.3(i).
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\122\ State of California Air Resources Board, ``Notice of
Public Availability of Modified Text: Proposed Amendments to the
Regulation for Reducing Sulfur Hexafluoride Emissions from Gas
Insulated Switchgear,'' May 5, 2021, and State of California Air
Resources Board, ``Notice of Public Availability of Modified Text:
Proposed Amendments to the Regulation for Reducing Sulfur
Hexafluoride Emissions from Gas Insulated Switchgear,'' June 17,
2021. Available at https://ww2.arb.ca.gov/rulemaking/2020/sf6?utm_medium=email&utm_source=govdelivery.
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Even if electrical equipment users use an accurate thermometer,
they may under- or overestimate the temperature of the gas being filled
into the equipment or recovered from it, for example if they assume
that the gas is at the same temperature as the area surrounding the
equipment. This is because gas that is filled into equipment from a
container may be cooler or warmer than the ambient temperature
depending on the method used to transfer the gas. Where the insulating
gas is pulled from the container in the liquid phase, an evaporator is
generally used between the container and the equipment to ensure that
only gas is transferred into the electrical equipment. A representative
of a gas cart manufacturer indicated that the gas transferred using
this method is often slightly warmer than the ambient temperature. In
this case, the density of the gas will be lower than the density
calculated using the ambient temperature. Where the insulating gas is
pulled from the container in the gas phase, the container (and the gas
inside) tends to cool as the gas boils off from a reservoir of liquid
insulating gas in the container. Heating blankets are often used to
warm the container and gas in this case, but they may not compensate
for the temperature loss associated with the phase change. In this
case, the gas will be cooler than the ambient temperature, and its
density will be higher than the density calculated using the ambient
temperature. To at least partly address these issues, we are proposing
to require that equipment users measure the temperature of the
electrical equipment rather than relying on the ambient temperature
when making nameplate capacity measurements. However, even measurements
on the surface of the electrical equipment may not reflect the
temperatures inside, at least not right away. To ensure that the
temperature of the gas is not under- or overestimated, we are
considering requiring a minimum temperature equilibration time
following the gas filling procedure. We request comment on this option,
including on what appropriate waiting times would be for temperature
equilibration for equipment of different sizes and on whether
manufacturer filling directions adequately address temperature
measurement issues. Temperature equilibration times that we are
considering range from 30 minutes for relatively small equipment to 8
to 24 hours for large equipment.
We also request comment on whether it would be sufficient to
require that any gas inside hoses is ``accounted for'' both before and
after equipment filling or emptying processes, or whether we should
specify a more detailed procedure for evacuating hoses before and after
equipment filling and emptying. A representative of a gas cart
manufacturer who commonly provides training on use of its gas carts
described the following procedure to the EPA: Any gas in the hoses
should be pulled back into the gas cart/cylinders before the filling or
emptying process begins, and the baseline measurements on scales and/or
flow meters should be taken at that point. Then the equipment should be
filled or emptied, the hoses should be isolated from the equipment, and
any remaining gas in the hoses should be pulled back into the gas cart/
cylinders. At that point the final measurements on scales and/or flow
meters should be taken. We request comment on whether we should require
use of this procedure or whether there may be other acceptable
procedures for ensuring that any gas in hoses is accounted for in
nameplate capacity measurements.
We are proposing at 40 CFR 98.307(b) to require equipment users to
keep records of certain identifying information for each piece of
equipment for which they measure the nameplate capacity: the rated and
measured nameplate capacities, the date of the nameplate capacity
measurement, the measurements and calculations used to obtain the
measured nameplate capacity (including the temperature-pressure curve
and/or other information used to derive the initial and final
temperature-adjusted pressures of the equipment), and whether or not
the measured nameplate capacity value was adopted for that piece of
equipment. In addition, we are proposing at 40 CFR 98.306(o) and (p) to
require equipment users who measure and adopt nameplate capacity values
to report the total rated and measured nameplate capacities across all
the equipment whose nameplate capacities were measured and for which
the measured nameplate capacities have been adopted in that year.
Collecting this information would help enable us to ascertain the
average magnitude of nameplate capacity adjustments at both the
facility and U.S. level, providing insight into the extent to which
manufacturer-assigned nameplate capacities may err and alerting us to
situations where adjustments are unusually large, which may indicate
[[Page 37006]]
that equipment users are not following the procedures specified in the
rule to ensure that they measure nameplate capacity values accurately.
2. Proposed Revisions To Streamline and Improve Implementation for
Subpart DD
In alignment with our proposed revisions to include additional F-
GHGs in the source category, and for the reasons described in section
II.B.1 of this preamble, we are proposing to revise the applicability
threshold of subpart DD at 40 CFR 98.301. Subpart DD currently requires
reporting from facilities with a total nameplate capacity of
SF6 and PFC-containing equipment located within the facility
or under common ownership or control exceeding 17,820 pounds. The EPA
established the nameplate capacity threshold \123\ of 17,820 pounds in
the 2010 Final Rule for Additional Sources of Fluorinated GHGs(75 FR
74774) as an ``equivalent threshold'' that approximated the 25,000
metric tons of CO2 threshold for emissions. Emissions of
SF6 and PFC from the source category include emissions from
equipment leaks and venting from gas-insulated substations and switch
gear. The insulating gas can also be released during equipment
manufacturing, installation, normal operation and maintenance, and
disposal. We initially chose a nameplate capacity-based threshold
because nameplate capacity is strongly correlated with SF6
emissions, and a capacity-based threshold allows potential sources to
determine whether they are above or below the threshold more quickly
and with less effort than through estimating emissions.\124\ The
threshold of 17,820 pounds was estimated using the GWP of
SF6 that was applicable at the time and historical leakage
data reported by industry owners and operators who are partners in
EPA's SF6 Emission Reduction Partnership for Electric Power
Systems.
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\123\ The current threshold is based on the total nameplate
capacity of SF6 or PFC containing equipment located
within the facility and SF6 or PFC containing equipment
that is not located within the facility but is under common
ownership or control.
\124\ See U.S. EPA. Subpart DD Technical Support Document--Use
of Electric Transmission and Distribution Equipment, November 2010.
Available at https://www.epa.gov/sites/production/files/2015-03/documents/subpartdd-tsd-electricpowerequip.pdf and in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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To help ensure that the GHGRP data collected better reflects the
emission rates and insulating gases that prevail in the current
electric power system industry, we are proposing to replace the
existing nameplate capacity threshold with an emissions threshold of
25,000 metric tons CO2e per year of F-GHGs. To calculate
their F-GHG emissions for comparison with the threshold, electrical
equipment users would use one of two new equations in subpart DD at 40
CFR 98.301, proposed equations DD-1 and DD-2. The proposed equations
explicitly include not only the nameplate capacity of the equipment but
also an updated default emission factor and the GWP of each insulating
gas. The equations would therefore account for additional fluorinated
gases (including GHG mixtures) now being marketed to the industry as
well as lower reported emission rates within the industry.\125\ The
current nameplate-capacity based threshold was based on the historical
emission rate, which was estimated at approximately 13 percent, and the
GWP for SF6. For small facilities (total nameplate capacity
between 17,000 and 50,000 lbs), the largest emission rate reported
since 2013 (based on beginning of year capacity) was 10.3 percent.\126\
Additionally, some facilities within this industry sector may have
begun to use lower GWP F-GHGs, which is not reflected when using only
nameplate capacity of the equipment to determine applicability.
Therefore, the current nameplate capacity threshold may require
facilities with annual subpart DD emissions below 25,000
mtCO2e per year to report. Revising the reporting threshold
to account for lower emission rates and the use of F-GHGs with lower
GWPs would reduce burden for those electric power systems and
facilities that have decreased their reliance on SF6-
insulated equipment and would maintain a threshold equivalent to the
25,000 mtCO2e threshold.
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\125\ Id. The leak rate was originally based on 1999 weighted
leak rates from 42 entities reporting to the EPA's SF6
Emission Reduction Partnership for Electric Power Systems.
\126\ Calculated based on beginning of year nameplate capacity
and total reported emissions to subpart DD of 40 CFR part 98, Use of
Electric Transmission and Distribution Equipment, Envirofacts,
downloaded from https://www.epa.gov/enviro/greenhouse-gas-customized-search on July 8, 2020.
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As discussed in section III.N.1 of this preamble, we are proposing
to revise the existing calculation, monitoring, and reporting
requirements of subpart DD to require reporting of additional F-GHGs
beyond SF6 and PFCs. Therefore, the proposed new equations
DD-1 and DD-2 that we are proposing for the applicability threshold
would require potential reporters to account for the total nameplate
capacity of all F-GHG containing equipment (located on-site and/or
under common ownership or control), including equipment containing F-
GHG mixtures, and multiply by the weight fraction of each F-GHG (for
gas mixtures), the GWP for each F-GHG, and an emission factor of 0.10
(representing an emission rate of 10 percent). We have determined that
the proposed threshold methodology is more appropriate because it
represents the actual fluorinated gases used by a reporter, accounts
for gas mixtures, and updates the contemporaneous emission rate
performance for the industry.\127\ Finally, we are proposing
harmonizing changes in multiple subsections to renumber existing
equation DD-1 and maintain cross-references to the equation.
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\127\ For more information see, Technical Support for Proposed
Revisions to Subpart DD (2021), available in the docket for this
rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424).
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The proposed revisions would also streamline the reporting
requirements to focus Agency resources on the substantial emission
sources within the sector and would exclude new electric power systems
and other new facilities from subpart DD when their emissions of
insulating gas were estimated to be below 25,000 mtCO2e per
year. The proposed changes would revise the existing threshold in 40
CFR 98.301 and Table A-3 to subpart A (General Provisions). Reporters
would continue to determine the applicability of subpart DD under 40
CFR 98.2(a)(1), which applies to source categories listed in Table A-3,
such that only total estimated emissions from F-GHGs would be accounted
for in determining whether the applicability threshold is met.
Therefore, facilities would continue to determine the applicability of
subpart DD without consideration of the combined emissions from
stationary fuel combustion sources (subpart C), miscellaneous use of
carbonates (subpart U), and other applicable source categories towards
the threshold.
Due to the definition of ``facility'' for electric power systems
that is different from the definition of ``facility'' (in subpart A of
part 98) that covers facilities in other subparts, electric power
systems always report to the GHGRP as unique facilities (i.e.,
emissions from other sources covered by the GHGRP that may have overlap
in location with a subpart DD facility are reported under a different
e-GGRT identifier due to the different definition of ``facility'').
Thus, placement of subpart DD in Table A-3 or Table A-4 of subpart A
has no effect on the emissions considered when determining
applicability for electric power systems if an equivalent threshold is
used.
[[Page 37007]]
However, for other facilities that use electrical equipment, it is
possible to add emissions under subpart DD to those from other subparts
as they use the standard definition of ``facility'' in Subpart A. We
are currently proposing to maintain subpart DD in Table A-3 of subpart
A. By keeping subpart DD in Table A-3, we expect to continue to capture
the majority of annual emissions from the use of electrical
transmission and distribution equipment (approximately 65 percent in
2019; down from a high of 73 percent due to some facilities becoming
eligible to exit the program \128\) while not significantly increasing
burden. Moving subpart DD to Table A-4 of subpart A would likely have a
significant impact on the number of reporters subject to subpart DD but
is unlikely to result in a significant increase to the proportion of
emissions covered by the GHGRP, because moving subpart DD to Table A-4
would only affect facilities that are not electric power systems.
Facilities that are not electric power systems have historically
reported emissions significantly below 25,000 mtCO2e even
when the total nameplate capacity at the facility was over the current
threshold of 17,820 lbs.\129\ One option that we are considering is to
move use of electrical equipment to Table A-4 of subpart A, which would
require facilities that used electrical equipment but that were not
electric power systems to determine applicability according to 40 CFR
98.2(a)(2). Under this option, facilities that used electrical
equipment but that were not electric power systems would be required to
add their total estimated F-GHG emissions from electrical equipment to
their combined emissions from stationary fuel combustion units,
miscellaneous uses of carbonate, and all other applicable source
categories that are listed in Table A-3 and Table A-4 to determine
whether the facility emits 25,000 mtCO2e or more per year in
combined emissions and whether they were required to report under part
98. In other words, if the result of this calculation exceeded 25,000
mtCO2e, they would be required to report their emissions
from electrical equipment even if the F-GHG emissions from such
equipment, by themselves, were below 25,000 mtCO2e. We are
considering requiring more comprehensive reporting of emissions from
users of electrical equipment other than electric power systems because
comparisons between the consumption of SF6 reported to the
GHGRP by SF6 suppliers have generally exceeded the
consumption reported by (or estimated by the EPA for) SF6
users. It is possible that SF6 consumption by users of
electrical equipment with nameplate capacities under the current
threshold (and therefore with SF6 emissions that are likely
to fall under the 25,000 mtCO2e threshold) could account for
some of this gap, and therefore it is possible that reporting by these
facilities would at least partially explain the gap. However, we
recognize that if we move subpart DD to Table A-4, numerous facilities
that are subject to this part because of emissions from another source
category would potentially be newly required to report under subpart DD
with only a few pieces of gas-insulated equipment. One option for
addressing this concern would be not to require reporting when
emissions from the facility's electrical equipment, as calculated using
equation DD-2, fell below a threshold, such as 1,000 mtCO2e.
We request comment on these options.
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\128\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks: 1990-2019 (EPA 2021), available at: https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2019.
\129\ See Technical Support for Proposed Revisions to Subpart DD
(2021), available in the docket for this rulemaking, Docket Id. No.
EPA-HQ-OAR-2019-0424.
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O. Subpart FF--Underground Coal Mines
The EPA is proposing two technical corrections to subpart FF of
part 98 (Underground Coal Mines), for the reasons described in section
II.A.5 of this preamble. First, we are proposing to correct the term
``MCFi'' in equation FF-3 of subpart FF to revise the term
``1-(fH2O)1'' to ``1-
(fH2O)i.'' The proposed change would correct an
error inadvertently introduced in the November 29, 2013 final rule (78
FR 71967). Second, we are proposing a revision to 40 CFR 98.326(t).
Facilities are required to report the Mine Safety and Health
Administration (MSHA) identification number to the EPA. The technical
correction would add the word ``number'' after the word
``identification'' to clarify the reporting requirement.
P. Subpart GG--Zinc Production
We are proposing one revision to subpart GG of part 98 (Zinc
Production) that would improve the quality of the data collection under
the GHGRP. For the reasons described in section II.A.4 of this
preamble, we are proposing to add a reporting requirement at 40 CFR
98.336(a)(6) and (b)(6) for the total amount of EAF dust annually
consumed by all Waelz kilns at zinc production facilities. EAF dust and
other scrap materials are primary inputs at certain zinc production and
recycling facilities from which zinc is recovered. The EPA is proposing
to collect this data in order to improve verification of reported data
under the GHGRP. This data would also improve emissions estimates
developed as part of the U.S. GHG Inventory. Collection of this data
would be useful for verification of data reported through the GHGRP by
assisting with data validation. The amount of EAF dust consumed by
facilities strongly correlates with process CO2 emissions.
Therefore, the total amount of EAF dust consumed by all Waelz kilns
could be used for comparison to emissions estimates and would be useful
for verifying consistency in emissions over time. Additionally, the
U.S. GHG Inventory uses Tier 1 methods from the 2006 IPCC Guidelines to
estimate emissions from zinc produced. For primary zinc production, the
inventory uses a Waelz kiln emission factor based on zinc production
for non-EAF dust consuming facilities, and a Waelz kiln emission factor
based on EAF dust consumption for EAF-dust consuming facilities.
Currently, the EPA is only able to obtain EAF dust consumed for a small
number of facilities using Waelz kilns, which increases the uncertainty
of these emission factors. Further, for Waelz kiln-based production,
the IPCC recommends the use of emission factors based on EAF dust
consumption, since the amount of carbonaceous materials (e.g., coal or
coke) used (which drives process CO2 emissions) is more
directly dependent on the amount of EAF dust consumed, rather than the
amount of zinc produced. Collecting the total annual EAF dust consumed
for all Waelz kilns at facilities would allow the EPA to develop a more
accurate emission factor for facilities using Waelz kilns for the
Inventory.
Reporters currently estimate emissions using either a CEMS direct
measurement methodology or calculate process CO2 emissions
by determining annually the total mass of carbon-containing input
materials (including zinc-bearing material, flux, electrodes, and any
other carbonaceous materials) introduced into each kiln and furnace and
the carbon content of each material. Of these materials, the proposed
data element would only require segregation and reporting of the mass
of EAF dust consumed for all kilns. Reporters currently collect
information on the EAF dust consumed on a monthly basis as part of
their existing operations; reporters using the mass balance methodology
collect this data as a portion of the inputs to equation GG-1. We are
not proposing any changes to the mass calculation methodology;
reporters
[[Page 37008]]
would only be required to sum all EAF dust consumed on a monthly basis
for each kiln and then for all kilns at the facility for reporting and
entering the information into e-GGRT. Therefore, we do not anticipate
that the proposed data elements would require any additional monitoring
or data collection by reporters. The proposed data requirement would be
required for reporters using either the CEMS direct measurement or mass
balance calculation methodologies. We are also proposing related
confidentiality determinations for the additional data elements, as
discussed in section VI of this preamble.
Q. Subpart HH--Municipal Solid Waste Landfills
For the reasons described in section II.A.1 of this preamble, we
are proposing revisions to subpart HH of part 98 (Municipal Solid Waste
Landfills) that would improve the quality of the data collection under
the GHGRP. First, we are proposing to update the factors used in
modeling CH4 generation from waste disposed at landfills to
reflect the increased amount of inert materials that are disposed at
landfills that do not contribute to CH4 generation. The
updated factors would allow MSW landfills to more accurately model
their CH4 generation.
Subpart HH uses a first order decay model to estimate
CH4 generation from MSW landfills. This model considers the
quantity of MSW landfilled, the degradable organic carbon (DOC) content
of that MSW, and the first order decay rate (k) of the DOC. Table HH-1
of subpart HH contains DOC and k values that a reporter must use to
calculate their CH4 generation based on the different
categories of waste disposed at that landfill and the climate in which
the landfill is located. The options available under the current rule
can generally be summarized as follows:
The Bulk Waste option assumes a single stream of waste
coming into the facility that contains a mixture of organic and
inorganic wastes. The current default DOC for this waste stream is
0.20, and the default decay rate values for this bulk waste stream are
dependent on precipitation rates: 0.02 for <20 inches of rainfall per
year; 0.038 for 20-40 inches of rainfall per year; and 0.057 for >40
inches of rainfall per year.
The Modified Bulk MSW option allows facilities to break
out their waste into three different streams: bulk MSW excluding inert
and construction and demolition (C&D) wastes (effectively ``organic
MSW''); C&D waste; and inert waste. The decay rates for the ``organic
MSW'' stream are the same as those listed for the Bulk Waste option,
however the default DOC is a higher value of 0.31. This value was
calculated from the waste quantities reported in the EPA's ``Municipal
Solid Waste in the United States: 2007 Facts and Figures'' report \130\
specifically for the GHGRP considering only the organic containing
portions of MSW.
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\130\ U.S. EPA, Municipal Solid Waste in the United States: 2007
Facts and Figures, 2007. https://archive.epa.gov/epawaste/nonhaz/municipal/web/pdf/msw07-rpt.pdf. Available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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The Waste Composition option provides defaults for DOC and
k for several subcategories of waste including food waste, garden
waste, paper waste, wood waste, inert waste, etc. The DOC and k values
for different subcategories of wastes are based on the values
recommended in the 2006 IPCC Guidelines for National Greenhouse Gas
Inventories, Volume 5 Waste, Chapters 2 and 3.\131\ Reporters are
allowed to use the waste composition option for those waste streams for
which compositional data are available and use the bulk waste defaults
(DOC and k values as described in the Bulk Waste option above) for
waste streams where compositional data are not available.
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\131\ IPCC. Guidelines for National Greenhouse Gas Inventories,
Volume 5 Waste, 2006. https://www.ipcc-nggip.iges.or.jp/public/2006gl/. Available in the docket for this rulemaking, Docket Id. No.
EPA-HQ-OAR-2019-0424.
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The EPA has received comments from stakeholders in the waste
industry (i.e., Waste Management, Republic Services, National Waste &
Recycling Association, Solid Waste Association of North America, SCS
Engineers, and Weaver Consulting Group) related to the values for DOC
and k for both the Bulk Waste and Modified Bulk Waste Options listed
under Table HH-1 to subpart HH. These comments \132\ were received
during the expert and public comment review period for the U.S. GHG
Inventory. The U.S. GHG Inventory for solid waste uses directly
reported emissions values from subpart HH to estimate national
CH4 emissions from MSW landfills throughout the entire
United States, and the commenters noted that, in order to implement
these suggested revisions to the U.S. GHG Inventory, revisions must
first be made to subpart HH. Commenters argued, based on alleged
fundamental shifts in the characterization of waste disposed in
landfills and research conducted by state agencies and the
Environmental Research and Education Foundation (EREF),\133\ that: (1)
the default DOC values for Bulk Waste and Modified Bulk Waste
overestimate the organic fraction of waste in U.S. landfills and
therefore overestimate emissions from this source; and (2) that the EPA
should perform an analysis of data reported to subpart HH and update
the default k values as necessary based on the results of this
analysis. Commenters noted that the default values for k currently
listed in Table HH-1 of subpart HH for both the Bulk Waste and Modified
Bulk Waste options are based on data from the EPA's 2008 draft AP-42:
Compilation of Air Emissions Factors \134\ (which is still in draft
form) and stated these default values are likely out-of-date
considering changes in waste disposal trends in the past two decades.
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\132\ See Waste Management, Republic Services, National Waste &
Recycling Association, Solid Waste Association of North America, SCS
Engineers, and Weaver Consulting Group. Comments on the 1990-2017
Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks EPA-HQ-
OAR-2018-0853. March 14, 2019. These and other similar comments are
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-
0424.
\133\ The Environmental Research & Education Foundation (2019).
Analysis of Waste Streams Entering MSW Landfills: Estimating DOC
Values & the Impact of Non-MSW Materials. Retrieved from
www.erefdn.org. Available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2019-0424.
\134\ U.S. EPA. 2008. AP-42: Compilation of Air Emissions
Factors, Fifth Edition, Volume 1, Chapter 2.4: Municipal Solid Waste
Landfills. https://www3.epa.gov/ttn/chief/ap42/ch02/index.html. Also
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424.
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In response, the EPA performed a multivariate analysis to minimize
the difference between CH4 generation estimates back-
calculated from the reported values of equation HH-7 and the
CH4 generation predicted using equation HH-1, while
optimizing k and DOC simultaneously for each landfill included in the
analysis cohort. Six years of GHGRP data for 355 landfills were
ultimately analyzed in this cohort. These 355 landfills were subpart HH
reporters that reported a gas collection system (GCS) installed on-site
for all reporting years, reported a consistent waste categorization
option for all reporting years, and reported the same DOC and decay
rate values for all reporting years. Details of this analysis are
available in the memorandum from Meaghan McGrath, Kate Bronstein, and
Jeff Coburn, RTI International, to Rachel Schmeltz, EPA, Multivariate
analysis of data reported to the EPA's Greenhouse Gas Reporting Program
(GHGRP), Subpart HH (Municipal Solid Waste Landfills) to optimize DOC
and k values, (June 11, 2019), available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
After consideration of the comments received and the multivariate
analysis
[[Page 37009]]
performed, we are proposing to amend subpart HH to provide revised DOC
and k values that would more accurately estimate GHG emissions from the
MSW landfills. We are proposing to amend the bulk waste DOC value in
Table HH-1 from 0.20 to 0.17, which was the average optimal DOC value
for all landfills reporting under the Bulk Waste option (n=239) in the
multivariate analysis. This value is similar to the proposed bulk waste
DOC value of 0.161 the waste industry has cited within their comments
as a result of study produced by the EREF (2016). We are proposing to
use the results of the multivariate analysis in lieu of using the EREF
recommended DOC value because the multivariate analysis is more
nationally representative. EREF develop their recommended DOC value
using state-level data for a single year (2013) for 14 states. The
multivariate analysis based on subpart HH reported data uses facility-
level data covering 41 states over the course of 6 years (2012-2017).
It was not possible to use the multivariate analysis to develop an
optimal DOC value for bulk MSW waste without inerts and (C&D) waste for
the Modified Bulk Waste option due to a lack of reporters that used
this option meeting the criteria developed and noted above for the
multivariate analysis. Instead, we reanalyzed the DOC value for this
option using the same approach used to develop this factor initially
but with updated MSW composition data from 2011 to 2015 as reported by
the EPA.\135\ The average DOC value across the 5-year period
considering all MSW landfilled is 0.17, which agrees well with our
optimized DOC value for bulk MSW from the multivariate analysis. After
subtracting out inerts, the average DOC for MSW excluding inerts is
0.27.\136\ The percent reduction of the DOC value for MSW excluding
inerts is similar to the percent reduction in the average DOC for bulk
MSW as determined from the multivariate analysis. Therefore, we are
also proposing to revise the DOC value for the Modified Bulk MSW option
in Table HH-1 from 0.31 to 0.27.
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\135\ U.S. EPA. 2015. Advancing Sustainable Materials
Management--2015 Tables and Figures: Assessing Trends in Material
Generation, Recycling, Composting, Combustion with Energy Recovery
and Landfilling in the United States July 2018, available at:
https://www.epa.gov/facts-and-figures-about-materials-waste-and-recycling/advancing-sustainable-materials-management. Data set from
1960 to 2015 (see
``Materials_Municipal_Waste_Stream_1960_to_2015.xlsx'') available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-
0424).
\136\ See memorandum from Jeff Coburn, RTI International, to
Rachel Schmeltz, EPA, Modified Bulk MSW Option Update, June 18,
2019, available in the docket for this rulemaking, Docket Id. No.
EPA-HQ-OAR-2019-0424).
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The EPA is also proposing to include a DOC value for
``Uncharacterized MSW'' within the Waste Composition option in Table
HH-1. Currently, reporters using this option use the DOC provided for
the Bulk Waste option for these uncharacterized waste streams as
provided in 40 CFR 98.343(a)(2). A multivariate analysis of the
facilities that use a hybrid approach of the Waste Composition option
and the Bulk Waste option indicates that the optimal DOC value for
uncharacterized MSW is much greater than the value for bulk DOC. The
multivariate analysis indicates an optimal DOC value for
uncharacterized DOC when using the waste composition option of 0.32.
Therefore, we are proposing to include within Table HH-1 a DOC for
uncharacterized MSW of 0.32 and proposing to revise 40 CFR 98.343(a)(2)
to reference using this uncharacterized MSW DOC value rather than the
bulk MSW value for waste materials that could not be specifically
assigned to the streams listed in Table HH-1 for the Waste Composition
option. Details of this analysis are available in the memorandum,
Multivariate analysis of data reported to the EPA's Greenhouse Gas
Reporting Program (GHGRP), Subpart HH (Municipal Solid Waste Landfills)
to optimize DOC and k values, available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
We note that DOC and k values are linked. Appropriate k values are
primarily dependent on the composition of the waste and on the moisture
content of the waste within the landfill (2006 IPCC Guidelines for
National Greenhouse Gas Inventories, Volume 5 Waste, Chapter 3), which
is why subpart HH includes different k values based on annual
precipitation rates. The multivariate analysis we conducted determined
the optimal values for DOC and k values when varying both parameters.
The optimal DOC value for bulk waste would have been higher if we had
conducted a single variable analysis and had used only the k values
currently provided in Table HH-1. Because of this linkage between the
DOC and k values, the EPA is also proposing to revise the default decay
rate values in Table HH-1 for both the Bulk Waste option and the
Modified Bulk MSW option and add k value ranges for uncharacterized MSW
for the Waste Composition Option as shown in Table 4 of this preamble.
The proposed defaults represent the average optimal k values for the
cohort of landfills within each precipitation category. The proposed k
values are larger than the current defaults but provide a more accurate
estimate of the landfill's emissions based on the results of the
multivariate analysis. We also reviewed the k values used in other
countries' inventories as well as those recommended in the 2006 IPCC
Guidelines for National Greenhouse Gas Inventories. We found that the
current k values in Table HH-1 were low compared to those used in other
countries with climates similar to that in the U.S. We also found that
the k values we are proposing more closely align with those used in
countries with similar climates to the U.S. and with the defaults for
moderately decaying bulk waste provided in the 2006 IPCC Guidelines for
National Greenhouse Gas Inventories.\137\ Because our review of other
inventory k values and our multivariate analysis indicate that the
current k values in Table HH1 are too low, we are proposing to revise
these k values consistent with the results of our multivariate analysis
and consistent with our revision to the default DOC for bulk waste.
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\137\ See memorandum from Kate Bronstein and Meaghan McGrath,
RTI International to Rachel Schmeltz, EPA, Comparison of U.S.
Inventory Waste Model Decay Rate (k) Values to Other UNFCCC Annex 1
Country Defaults and Country-specific Waste Models (June 18, 2019),
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424.
Table 4--Proposed Default k Values
----------------------------------------------------------------------------------------------------------------
Current Proposed
Factor subpart HH subpart HH Units
default default
----------------------------------------------------------------------------------------------------------------
k values for Bulk Waste option and Modified Bulk MSW option
k (precipitation plus recirculated leachate <20 inches/year).... 0.02 0.055 yr-1
k (precipitation plus recirculated leachate 20-40 inches/year).. 0.038 0.111 yr-1
k (precipitation plus recirculated leachate >40 inches/year).... 0.057 0.142 yr-1
[[Page 37010]]
k value range for Waste Composition option
k (uncharacterized MSW)......................................... Not applicable 0.055 to 0.142 yr-1
----------------------------------------------------------------------------------------------------------------
Altering both the default DOC and k values for subpart HH reporters
would affect closed and open landfills in different ways. Implementing
the recommended, and higher, k values will serve to increase the
emissions calculated from equation HH-1 and equation HH-5 for open,
active landfills. The higher k values imply that the organic material
that is placed in the landfill will degrade more quickly than predicted
when using lower k-values. This tends to lead to greater calculated
emissions from active landfills (landfills actively receiving waste
during a reporting year). The higher k values also tend to predict that
less degradable waste will be in the landfill once the landfill closes
(i.e., no longer receives wastes) and the degradable waste that is
present in the closed landfill will decompose more quickly. This tends
to reduce the emissions calculated for closed landfills, which may
allow closed landfills to more quickly phase-out of the reporting
program (i.e., when reported emissions fall below the 25,000
mtCO2e threshold for 5 years consecutive years). Thus, the
proposed k values are expected to increase the calculated emissions
from active landfills, reduce calculated emissions from closed
landfills, and potentially reduce burden associated with the reporting
requirements for closed landfills (due to having fewer years of
reported emissions above the reporting threshold once the landfill is
closed). We also note that the emissions from the landfill over its
entire life (active and closed periods) is dependent only on the amount
of degradable organic material placed in the landfill, which is
dependent only on the DOC value. Thus, the lower DOC value should
reduce the cumulative emissions reported for a given landfill over all
reporting years; however, it may increase the emissions reported during
the years the landfill is actively receiving wastes.
To determine an estimate of the effect of these changes on overall
subpart HH emissions reporting, equation HH-1 methane generation from
six landfills in the final analysis cohort, three closed landfills (one
in each precipitation range) and three open landfills (one in each
precipitation range), were recalculated (as an illustrative example)
with the recommended DOC value of 0.17 and the recommended k value
corresponding to the landfill's precipitation zone.\138\ On average,
the selected closed landfills had a 21 percent decrease in methane
generation while the selected open landfills saw a 55 percent increase.
These are illustrative examples and not a quantitative nationwide
assessment of the impact of the proposed revisions to DOC and k values,
but they confirm our expectations. The nationwide impact of these
changes will likely be limited to a large extent because the large
majority (approximately 90 percent) of the emissions reported under
subpart HH are from facilities with GCS. Facilities with GCS use two
different calculation methodologies to determine methane emissions:
equation HH-6, which used the predicted methane generation from
equation HH-1 and the amount of methane recovered, and equation HH-8,
which is based solely on the quantity of methane recovered. Per 40 CFR
98.346(i)(13), facilities with GCS may then choose the equation result
that best represents emissions from the landfill to use as their total
methane emissions reported for subpart HH. About 71 percent of subpart
HH facilities in RY2020 used equation HH-8 to estimate their methane
emissions and the proposed revisions would not impact the emissions
reported for these facilities. Thus, the proposed revisions would
impact only the emissions from landfills without GCS and landfills with
GCS that elect to report emissions using equation HH-6, which is a
smaller fraction (about 35 to 40 percent) of the total methane
emissions reported subpart HH. While methane emissions reported by
active landfills not using equation HH-8 are expected to increase, the
methane emissions reported by closed landfills are expected to
decrease, and the total amount of methane reported to be generated by a
given landfill over its entire life is expected to decrease (based on
the proposed lower DOC value).
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\138\ Meaghan McGrath, Kate Bronstein, and Jeff Coburn, RTI
International, to Rachel Schmeltz, EPA, Multivariate analysis of
data reported to the EPA's Greenhouse Gas Reporting Program (GHGRP),
Subpart HH (Municipal Solid Waste Landfills) to optimize DOC and k
values, (June 11, 2019), available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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For the reasons described in section II.A.4 of this preamble, we
are proposing a reporting requirement for landfills with gas collection
and control systems to inform the development of GHG policies and
programs by providing information on the proportion of landfill gas
used in energy recovery projects. There is no anticipated significant
change in burden due to this reporting requirement because key data in
estimating the annual amount of recovered CH4 from data
reported by measurement location and destruction device are already
reported. Specifically, we are proposing to require landfills with gas
collection and control systems to indicate the percentage of recovered
CH4 that is sent to a flare or sent to a landfill gas to
energy project for each measurement location.
For landfills with gas collection and control systems, we currently
collect the following information under 40 CFR 98.346(i) related to the
gas collection and control system at the facility: total volumetric
flow of landfill gas collected for destruction, the annual average
CH4 concentration of landfill gas for destruction, and an
indication of whether destruction occurs at the landfill facility, off-
site, or both. For landfills where destruction occurs at the facility,
we also ask for information about the measurement location(s) and
destruction device(s) at the facility. This information includes the
number of destruction devices associated with each measurement
location, the annual operating hours of each measurement location and
its associated destruction devices, and the annual quantity of
recovered CH4 using equation HH-4 for each measurement
location. We do not collect specific information about destruction
devices located off-site and therefore cannot collect the annual
quantity of CH4 recovered using equation HH-4 at the
destruction device level for all facilities subject to subpart HH.
Therefore, we are proposing to collect information at the measurement
location level about the proportion of landfill gas that is flared
versus sent to a landfill gas to energy project. Specifically, we are
proposing at 40 CFR
[[Page 37011]]
98.346(i)(6)(i) to require landfills with gas collection and control
systems to indicate the percentage of recovered CH4 that is
flared or sent to a landfill gas to energy project for each measurement
location. We understand that a facility owner or operator may not know
the exact quantity of recovered CH4 sent off-site for
destruction by a flare or landfill gas to energy project. Facilities
that indicate off-site destruction in e-GGRT and do not know whether
the recovered gas sent to the off-site destruction device is sent to a
flare or landfill gas to energy project would be allowed to allocate
the off-site portion of recovered gas into an ``unknown'' option along
with an optional text description.
This information would help inform the development of GHG policies
and programs under the CAA by providing information on the amount of
recovered CH4 that is beneficially used in energy recovery
projects and will assist in verification of net CH4
emissions from landfills with gas collection and control systems. This
new requirement will also assist with QA/QC of required inputs into the
U.S. GHG inventory for MSW landfills and will inform EPA, state, and
local government officials on progress towards renewable energy targets
and GHG emission inventories. Additionally, researchers have requested
this information under the U.S. national solid waste inventory. We are
also proposing related confidentiality determinations for the new data
element, as discussed in section VI of this preamble.
R. Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids
For the reasons discussed in section II.B.3 of this preamble, the
EPA is proposing to streamline reporting requirements by eliminating
some duplicative reporting between subpart NN (Suppliers of Natural Gas
and Natural Gas Liquids) and subpart W (Petroleum and Natural Gas
Systems) by eliminating the duplicative elements from subpart W, as
discussed in section III.J.2.f of this preamble.
S. Subpart OO--Suppliers of Industrial Greenhouse Gases
For the reasons provided in section II.A.4 of this preamble, we are
proposing revisions to subpart OO of part 98 (Suppliers of Industrial
Greenhouse Gases) that would improve the quality of the data collection
under the GHGRP. First, we are proposing to add a requirement for bulk
importers of F-GHGs to include, as part of the information required for
each import in the annual report, the customs entry summary number. The
customs entry summary number is provided as part of the U.S. Customs
and Border Protection (CBP) Form 7501: Entry Summary \139\ and is
assigned for each filed CBP entry for each shipment. We are proposing
to gather this data, which is already available in supplier records, to
verify and compare the data submitted to the GHGRP with other available
customs data. The proposed customs entry summary number would provide a
means to cross-reference the data submitted and would help to ensure
the accuracy and completeness of the information reported under the
GHGRP. The proposed changes would modify 40 CFR 98.416(c)(7). Because
the information collected is readily available in supplier records and
is similar to the identifying information currently collected (i.e.,
date of import, port of entry, country, commodity code, and importer
number), there is no anticipated significant change in burden.
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\139\ CBP Form 7501 is available at the U.S. Customs and Border
Protection website (https://www.cbp.gov/trade/programs-administration/entry-summary/cbp-form-7501).
---------------------------------------------------------------------------
Additionally, the EPA is proposing to require at 40 CFR 98.416(k)
that suppliers of N2O, saturated PFCs, and SF6
identify the end uses for which the N2O, SF6, or
PFC is used and the aggregated annual quantities of N2O,
SF6, or each PFC transferred to each end use, if known. This
requirement, which is patterned after a similar requirement under
subpart PP (Suppliers of Carbon Dioxide) of part 98, would help to
inform the development of GHG policies and programs by providing
information on N2O, SF6, and PFC uses and their
relative importance. We are proposing the requirement for
N2O, SF6, and PFCs in particular because: (1) the
GWP-weighted quantities of these compounds that are supplied annually
to the U.S. economy are relatively large; and (2) the identities and
magnitudes of the uses of these compounds are less well understood than
those of other industrial GHGs such as HFCs. For example, most
N2O is believed to be used for anesthetic applications, but
the exact share used for these applications is not known.
SF6 is known to be used in electrical equipment, magnesium
production and processing, and electronics manufacturing, but the total
quantity of SF6 that is estimated to be consumed by these
applications has sometimes fallen significantly below the total
quantity of SF6 supplied annually to the U.S. economy from
2011 through 2019, indicating that significant uses of SF6
may not be accounted for. Collecting information from suppliers of
these compounds on how their customers use the compounds, and in what
quantities, would help to resolve these questions.
To inform the revision of the subpart OO electronic reporting form
in the event that this proposed amendment is finalized, we request
comment on the end use applications for which N2O,
SF6, and saturated PFCs are used and their relative
importance. The EPA is aware of the following end uses of
N2O:
(1) Analgesia or anesthesia, including medical, dental, and
veterinary uses,
(2) Oxidizer in fuel,
(3) Foaming agent (e.g., for use in aerosol whipped cream),
(4) Propellant in aerosol sprays,
(5) Electronics manufacturing, including manufacturing of
semiconductors (including light-emitting diodes), micro-electro-
mechanical systems, liquid crystal display, and photovoltaic cells.
The EPA is aware of the following end uses of SF6:
(1) Electrical equipment use (i.e., by electric transmission and
distribution systems),
(2) Electrical equipment manufacturing,
(3) Electronics manufacturing, including manufacturing of
semiconductors (including light-emitting diodes), micro-electro-
mechanical systems, liquid crystal display, and photovoltaic cells,
(4) Magnesium production and processing,
(5) Dielectrics for particle accelerators, including university and
research particle accelerators, industrial particle accelerators, and
medical particle accelerators,
(6) Radar systems,
(7) Adiabatic uses, including use in shoe soles and car tires,
(8) Sound-proof windows,
(9) Tracer gas, including leak detection,
(10) Waterproofing (e.g., of textiles and/or circuit boards),
(11) Other medical applications.
The EPA is aware of the following end uses of saturated PFCs:
(1) Electronics manufacturing, including manufacturing of
semiconductors (including light-emitting diodes), micro-electro-
mechanical systems, liquid crystal display, and photovoltaic cells,
(2) Heat transfer fluids,
(3) Electrical equipment use,
(4) Electrical equipment manufacturing,
(5) Adiabatic uses, including use in shoe soles and car tires,
(6) Cosmetic applications,
(7) Medical applications,
[[Page 37012]]
(8) Waterproofing (e.g., of textiles and/or circuit boards).
We request comment on the above list and any additional end-uses of
GHGs that should be considered for inclusion in the reporting form.
Finally, we are proposing a clarification to the reporting
requirements for importers and exporters of F-GHGs, F-HTFs, or
N2O, for the reasons provided in section II.A.5 of this
preamble. We are proposing to revise the required reporting of
``commodity code,'' which is required for importers at 40 CFR
98.416(c)(6) and for exporters at 40 CFR 98.416(d)(4), to clarify that
reporters should submit the Harmonized Tariff System (HTS) code for
each F-GHG, F-HTF, or N2O shipped. Importers and exporters
currently provide the commodity code as part of the annual summary
information provided for each import or export at the corporate level.
The majority of reporters provide a commodity code based on codes
assigned through the HTS, which assigns 10-digit codes to identify
products that are unique to U.S. markets. HTS codes start with a 6-
digit code specifying a chapter, heading, and subheading, and in full
include a specific 10-digit code including a subheading for duty and a
statistical suffix. However, in some cases the requirement has
apparently been unclear to and misread by reporters, and reporters may
identify shipments using other commodity code systems, such as the
abbreviated 6-digit codes assigned by the international Harmonized
System (HS) or Standard Industrial Classification System (SIC), or may
enter other unidentifiable data into the ``commodity code'' field.
Reporters may also enter the data in different formats (e.g., with or
without decimals). This has resulted in cases in which the data
provided in some annual reports is unclear or unable to be compared to
outside data sources for verification. In order to reduce confusion for
reporters and standardize the data received we are proposing to replace
``commodity code'' with ``Harmonized Tariff System code'' in 40 CFR
98.416(c)(6) and 40 CFR 98.416(d)(4). Reporters would enter the full
10-digit HTS code with decimals, to extend to the statistical suffix,
as it was entered on related customs forms. For example, in 2020, the
entry for ``1,1,1,2-Tetrafluoroethane (HFC-134a)'' would be
``2903.39.20.20''.\140\ The proposed clarifications would reduce the
uncertainty associated with the reported data elements and improve data
verification.
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\140\ A complete list of codes and current HTS Chapters can be
found at https://hts.usitc.gov/current.
---------------------------------------------------------------------------
We are also proposing related confidentiality determinations for
the new and revised data elements, as discussed in section VI of this
preamble.
T. Subpart PP--Suppliers of Carbon Dioxide
For the reasons discussed in section II.A.3 of this preamble, the
EPA is proposing several revisions to subpart PP of part 98 (Suppliers
of Carbon Dioxide) to improve the quality of the data collected from
this subpart. Subpart PP is intended to identify and quantify supplies
of CO2 to commercial applications, underground injection, or
geologic sequestration. Subpart PP currently requires reporting of the
annual quantities of CO2 supplied by pipeline and in
containers from natural sources (i.e., extraction wells), capture
sources, and importers/exporters. Capture sources include natural gas
processing plants, ethanol manufacturing facilities, and other types of
facilities where CO2 is captured and supplied for commercial
applications or to inject or sequester underground.
Direct air capture (DAC) is a new, innovative approach to capturing
CO2 from ambient air. Unlike conventional capture sources
where CO2 is separated during the manufacturing or treatment
phase of product stream, DAC captures CO2 from ambient air.
CO2 is separated from air using aqueous or solid sorbents
and then processed into a concentrated stream for utilization or
injection underground. Historically a niche or experimental technology,
interest in deploying DAC technology has grown significantly in recent
years as a technology to address climate change.
We are proposing to add a new paragraph 40 CFR 98.420(a)(4), to
explicitly include DAC as a capture option. In addition, we are
proposing to amend 40 CFR 98.6, to include a definition for DAC.
Specifically, we are proposing that DAC, with respect to a facility,
technology, or system, means that the facility, technology, or system
uses carbon capture equipment to capture carbon dioxide directly from
the air. DAC does not include any facility, technology, or system that
captures carbon dioxide (1) that is deliberately released from a
naturally occurring subsurface spring or (2) using natural
photosynthesis. The definition is taken directly from the definition of
DAC in the CAA at 42 U.S.C. 7403(g)(6)(B)(III).\141\ We believe these
clarifications will benefit owner/operators of DAC facilities, the
public, and other stakeholders by removing any questions or uncertainty
about the applicability of subpart PP to DAC. Moreover, the proposed
amendments will improve data quality by clarifying applicability of
subpart PP, thereby ensuring the GHGRP accounts for a growing and
potentially large component of the CO2 supply chain.
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\141\ The definition of DAC was added to the CAA as part of the
Utilizing Significant Emissions with Innovative Technologies Act
(USE IT Act), which was included in Section 102 of Division S of the
Consolidated Appropriations Act, 2021, available at https://www.congress.gov/116/bills/hr133/BILLS-116hr133enr.pdf.
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To ensure consistency among definitions applicable to subpart PP,
we are also proposing to amend the definition of ``Carbon dioxide
stream'' in 40 CFR 98.6 to include DAC in the definition. Specifically
we are proposing to add ``captured from ambient air (e.g., Direct air
capture)'' to the definition so that it reads, ``Carbon dioxide stream
means carbon dioxide that has been captured from an emission source
(e.g., a power plant or other industrial facility), captured from
ambient air (e.g., direct air capture), or extracted from a carbon
dioxide production well plus incidental associated substances either
derived from the source materials and the capture process or extracted
with the carbon dioxide.''
We are also proposing to amend other sections of subpart PP to
explicitly include DAC as a capture source for consistency with the
proposed changes to 40 CFR 98.420 and 40 CFR 98.428. Specifically, we
are proposing to amend the following sections to add references to DAC:
40 CFR 98.422; 40 CFR 98.423; 40 CFR 98.426; and 40 CFR 98.427.
In addition to these changes, we are proposing one additional
reporting requirement in 40 CFR 98.426 to improve data quality with
respect to DAC facilities. Life Cycle Analysis (LCA) has become a very
important tool in determining the net impact of DAC projects. DAC
processes potentially require substantial quantities of energy to
capture, process and supply CO2; therefore, we believe it is
important for the public and the EPA to understand the sources and
amounts of energy used by DAC facilities to power the DAC plant from
air intake at the facility through custody transfer of captured
CO2 or, if the CO2 does not leave the facility,
injection of captured CO2. We are proposing to add a new
requirement at 40 CFR 98.426(i) to require DAC facilities to report the
amounts of on-site and off-site sourced electricity, heat and combined
heat and power used to power the DAC plant from air intake at
[[Page 37013]]
the facility through the point of compressed CO2 stream
ready for supply for commercial applications or, if maintaining custody
of the CO2 stream, sequestration or injection of the
CO2. In addition, for on-site sourced electricity, heat and
combined heat and power, we are proposing that DAC facilities indicate
whether flue gas is also captured by the DAC process unit. We are
additionally proposing related confidentiality determinations for the
new data elements, as discussed in section VI of this preamble.
U. Subpart SS--Electrical Equipment Manufacture or Refurbishment
1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart SS
For the reasons discussed in section II.A of this preamble, we are
proposing several revisions to subpart SS of part 98 (Electrical
Equipment Manufacture or Refurbishment) to improve the quality of the
data collected from this subpart. Currently, this subpart requires
reporting of emissions from manufacturing and refurbishing processes
that include SF6 and PFCs. We are proposing to revise the
existing calculation, monitoring, and reporting requirements of subpart
SS (at 40 CFR 98.452, 98.453, 98.454, and 98.456) to require reporting
of additional F-GHGs as defined under 40 CFR 98.6. As discussed in
section III.N of this preamble, although SF6 and PFCs have
been the most commonly used insulating gases in the electrical power
industry, over the implementation of the reporting program the EPA has
become aware of alternative technologies and replacements for
SF6, including fluorinated gas mixtures.
Therefore, we expect that electrical equipment manufacturers and
refurbishment operations, in addition to electric power systems and
facilities, include equipment or are anticipated to include equipment
containing these alternative gas mixtures (e.g., fluoronitrile or
fluoroketone mixtures). As such, we are proposing revisions to subpart
SS in order to capture emissions from equipment using these alternative
gases that are not currently accounted for. The proposed reporting of
these additional F-GHGs would improve the accuracy of emissions
reported under subpart SS and enhance the overall quality of the data
collected under the GHGRP.
To implement these revisions, we are proposing to redefine the
source category at 40 CFR 98.450 to include equipment containing
``fluorinated GHGs (F-GHG), including but not limited to sulfur-
hexafluoride (SF6) and perfluorocarbons (PFCs).'' The
proposed changes would also apply to the threshold in 40 CFR 98.451.
Under the proposed rule, facilities would also consider additional F-
GHGs purchased by the facility in estimating emissions for comparison
to the threshold. There are no known facilities that currently use the
alternative gas mixtures exclusively or in large quantities that would
render them newly subject to the subpart; therefore, we expect the
proposed changes would result in minimal burden for reporters.
The proposed revisions to subpart SS include minor revisions to
equations SS-1 through SS-6 (which we are proposing be renumbered SS-2
through SS-7 to accommodate a new equation SS-1 as discussed in section
III.U.2 of this preamble) to incorporate the estimation of emissions
from all F-GHGs within the existing calculation methodology, updating
the monitoring and quality assurance requirements to account for
emissions from additional F-GHGs, and harmonizing revisions to the
reporting requirements such that reporters account for the mass of each
F-GHG at the facility level. We are also proposing a definition of
``insulating gas'' and proposing to add reporting of an ID number or
descriptor for each insulating gas and the name and weight percent of
each insulating gas reported. The proposed changes do not significantly
revise the existing calculation requirements. Although the revisions do
require additional monitoring and reporting requirements (including,
but not limited to, the tracking of alternative gases in a facility's
inventory, purchases of alternative gases, and the delivery of
equipment containing alternative gases), there are no known facilities
that currently manufacture large quantities of electrical transmission
and distribution equipment that use alternative gas mixtures in the
U.S.; therefore, we expect only a minimal increase in burden due to the
collection of data for any equipment containing F-GHGs that are not
SF6 or PFCs. However, we expect that the use of alternative
gases will continue to increase and collection of this data is
important to both understand emission trends and account for total
emissions from the sector. Finally, we are proposing related
confidentiality determinations for the revised data elements that
incorporate additional F-GHGs, as discussed in section VI of this
preamble.
2. Proposed Revisions to Streamline and Improve Implementation for
Subpart SS
For the reasons described in section II.B.1 of this preamble, we
are proposing to revise the applicability threshold of subpart SS. The
proposed revisions would remove the consumption-based threshold at 40
CFR 98.451 and instead require facilities to estimate total annual GHG
emissions for comparison to the 25,000 metric tons of CO2
threshold by introducing a new equation, equation SS-1. To accommodate
this new equation, we are also proposing minor harmonizing changes to
renumber existing equations SS-1 through SS-6 and related cross-
references. Subpart SS currently requires facilities that have total
annual purchases of SF6 and PFCs that exceed 23,000 pounds
to report. The EPA established the annual consumption-based threshold
of 23,000 pounds in the 2010 Final Rule for Additional Sources of
Fluorinated GHGs (75 FR 74774) as an ``equivalent threshold'' that
approximated the 25,000 metric tons of CO2 threshold.
Emissions of SF6 and PFC from the source category include
emissions from the testing, manufacturing, and installation or
commissioning of equipment, but can also occur when equipment is
decommissioned at a manufacturing facility. The current threshold was
based on an average emission rate estimated at approximately 10 percent
\142\ and the GWP for SF6 referenced in the 2009 Final Rule
from the IPCC Second Assessment Report. Since that time, the GWP for
SF6 has been updated in the GHGRP to a lower value (78 FR
71904, November 29, 2013). Further, some facilities within this
industry sector have begun to use lower GWP F-GHGs, which are currently
not accounted for in subpart SS. Therefore, we are proposing to revise
the applicability threshold to align with the proposed revisions to
require reporting of additional F-GHG beyond SF6 and PFCs.
The proposed equation SS-1 would continue to be based on the total
annual purchases of insulating gases, but would establish an updated
comparison to the threshold, and would account for the additional
[[Page 37014]]
fluorinated gases reported by industry. Potential reporters would be
required to account for the total annual purchases of all insulating
gases, and multiply by the GWP for each F-GHG and the emission factor
of 0.10 (or 10 percent). We have determined that the proposed threshold
methodology is more appropriate because it represents the actual
fluorinated gases used by a reporter. The proposed revisions would also
streamline the reporting requirements to focus Agency resources on the
substantial emission sources within the sector. Additionally, the
proposed changes would revise the inclusion of subpart SS in the
existing Table A-3 to subpart A. Because we are proposing to provide a
method for direct comparison to the 25,000 mtCO2e threshold,
we are proposing to remove subpart SS from Table A-3 and include the
subpart in Table A-4 of subpart A. Including subpart SS in Table A-4 is
consistent with other GHGRP subparts that use the 25,000
mtCO2e threshold included under 40 CFR 98.2(a)(2) to
determine applicability. Currently reporters determine the
applicability of subpart SS under 40 CFR 98.2(a)(1), which applies to
source categories listed in Table A-3. Therefore, facilities determine
the applicability of subpart SS on the basis of the current
consumption-based threshold without consideration of the combined
emissions from stationary fuel combustion sources (subpart C),
miscellaneous use of carbonates (subpart U), and other applicable
source categories towards the threshold. Moving this subpart to Table
A-4 of subpart A would require facilities to determine applicability
according to 40 CFR 98.2(a)(2) and consider the combined emissions from
stationary fuel combustion sources (subpart C), miscellaneous use of
carbonates (subpart U), and other applicable source categories. The
change from Table A-3 to Table A-4 is not expected to result in
additional reporters under subpart SS. Although most facilities subject
to subpart SS also report under subpart C, the reported subpart C
emissions are typically less than 1000 mtCO2e and are not a
significant portion of the total facility emissions.
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\142\ The 10 percent emission rate was based on the average of
``ideal'' and ``realistic'' manufacturing emission rates (4 percent
and 17 percent, respectively) identified in a paper prepared under
the auspices of the International Council on Large Electric Systems
(CIGRE) in February 2002 (O'Connell, P., F. Heil, J. Henriot, G.
Mauthe, H. Morrison, L. Neimeyer, M. Pittroff, R. Probst, J.P.
Tailebois (2002) SF6 in the Electric Industry, Status
2000, Cigre. February 2002.), available at https://www.epa.gov/sites/default/files/2016-02/documents/conf02_pittroff.pdf and in the
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
This method for estimating OEM emissions was the same method used in
EPA's Inventory of Greenhouse Gas Emissions and Sinks:1990-2006 (EPA
2008). Available at: https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2006 (accessed September 15,
2021).
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V. Subpart UU--Injection of Carbon Dioxide
The EPA is proposing one amendment to subpart UU to ensure
consistency with new proposed subpart VV (Geologic Sequestration of
Carbon Dioxide with Enhanced Oil Recovery Using ISO 27916). Subpart VV
is described further in section III.W of this preamble. The proposed
rule change adds language to 40 CFR 98.470, Definition of the source
category, to clarify that reporters who report under subpart VV for a
well or group of wells are not required to report under subpart UU for
that well or group of wells. Proposed new 40 CFR 98.470(c) is similar
to existing language in 40 CFR 98.470(b) which provides that reporters
to the Geologic Sequestration of Carbon Dioxide source category of the
GHGRP (subpart RR) for a well or group of wells are not required to
report under subpart UU for that well or group of wells.
We are proposing this revision to reduce the reporting burden on
subpart VV reporters by eliminating duplicative reporting requirements.
This proposed rule change also improves data quality by avoiding double
counting of the quantities of CO2 received and injected at
EOR and enhanced gas recovery facilities that use the CSA/ANSI ISO
27916:2019 standard and choose to report under subpart VV. This
avoidance of double counting would allow the EPA and the public to
better track and document the flow of CO2 through the
economy.
In proposing this change, we are also proposing to renumber
existing 40 CFR 98.470(c) to 40 CFR 98.470(d); however, we are not
proposing any rule language changes to this paragraph.
W. Subpart VV--Geologic Sequestration of Carbon Dioxide With Enhanced
Oil Recovery Using ISO 27916
The GHGRP is proposing to add a new subpart--subpart VV--as an
option for quantifying geologic sequestration in association with EOR
operations using the ISO standard designated as CSA/ANSI ISO
27916:2019, Carbon Dioxide Capture, Transportation and Geological
Storage--Carbon Dioxide Storage Using Enhanced Oil Recovery (CO2-EOR).
Although the title of the standard references only EOR, Clause 1.1 of
CSA/ANSI ISO 27916:2019 indicates that the standard can apply to
enhanced gas recovery as well. Thus, throughout subpart VV, as
proposed, any reference to EOR also applies to enhanced gas recovery.
Carbon capture, utilization, and sequestration (or storage) (CCUS)
refers to a set of technologies that remove CO2 from the
emissions of point sources or the atmosphere, and transport it,
compress it, and inject it deep underground, or transform it for
utilization in industrial processes or as feedstock for products.
Geologic sequestration is feasible in different types of geologic
formations including deep saline formations (formations with high
salinity formation fluids) or in oil and gas formations, where
CO2 can be injected to increase oil production through a
process referred to as EOR.
Subpart RR (Geologic Sequestration of Carbon Dioxide) is currently
the only source category within the GHGRP that provides an accounting
framework to report to the EPA the amount of CO2
geologically sequestered on an annual basis. The GHGRP's geologic
sequestration data are integral to providing transparent information to
the EPA and the public to track the value chain of CO2
supply and disposition.
The definition of the source category for subpart RR includes a
well or group of wells that inject a CO2 stream for long-
term containment in subsurface geologic formations. It also includes
wells permitted by the UIC Program as Class VI wells. Facilities that
conduct EOR are not required to report under subpart RR unless the
owner or operator chooses to opt-in to subpart RR, or the well is
permitted as a Class VI well. An operator that does not choose to opt
into subpart RR must report under subpart UU (Injection of Carbon
Dioxide) of the GHGRP.
Facilities subject to subpart RR are required to develop and
implement an EPA-approved monitoring, reporting, and verification (MRV)
plan. The major elements of the MRV plan include: (1) delineation of
active and maximum monitoring areas; (2) identification of potential
surface leakage pathways for CO2; (3) a strategy for
detecting and quantifying surface leakage of CO2; (4) a
strategy for establishing the expected baseline for monitoring
CO2 leakage; and (5) definition of site-specific variables
that will be used for estimating leakage. Once the facility has an
approved MRV plan, reporters are required to report annually the amount
of CO2 received, the data used to calculate this amount, the
source of the received CO2 (if known), the mass balance
equation inputs (amounts of CO2 injected, CO2
produced, CO2 emitted by surface leakage, CO2
emitted from equipment leaks and vented CO2 emissions), the
data used to calculate the inputs, and the amount of CO2
sequestered. Facilities are also required to submit an annual
monitoring report which implements the reporting requirements set forth
in the MRV plan.
Like subpart RR, subpart UU requires facilities to report the
quantity of CO2 received, the data used to calculate this
amount, and the source of the received CO2 (if known).
However, subpart UU does not require an MRV plan or the submission of
an annual monitoring report. Nor does it require monitoring or
reporting of the fate of the CO2 after the custody transfer
meter, and thus does
[[Page 37015]]
not provide an accounting framework of the amount of CO2
sequestered.
In January 2019, ISO published a new international standard for
CO2 storage using EOR. The standard was subsequently
endorsed by the CSA and ANSI and is designated as CSA/ANSI ISO
27916:2019, Carbon Dioxide Capture, Transportation and Geological
Storage--Carbon Dioxide Storage Using Enhanced Oil Recovery (CO2-
EOR)''.\143\ The standard establishes a protocol for documenting the
containment of CO2 injected in an EOR operation and
quantifying the amount of CO2 that is stored in association
with that operation.
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\143\ Available at https://www.iso.org/standard/65937.html and
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-
0424.
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As part of the Bipartisan Budget Act of 2018, Congress revised the
Internal Revenue Code (IRC) section 45Q tax credit for carbon oxide
sequestration (45Q).\144\ If a taxpayer meets the applicability
requirements, section 45Q provides tax credits for disposal of
qualified carbon oxide in secure geological storage or utilization. The
amount of the tax credit for disposal of qualified carbon oxide in
secure geological storage depends on whether the qualified carbon oxide
is used as a tertiary injectant in a qualified enhanced oil or natural
gas recovery project.
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\144\ See 26 CFR 1.45Q-0 through 26 CFR 1.45Q-5.
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Under a rule finalized by the Treasury Department and Internal
Revenue Service (IRS),\145\ qualified carbon oxide is considered
disposed of by the taxpayer in secure geological storage such that the
qualified carbon oxide does not escape into the atmosphere if the
qualified carbon oxide is either: (1) injected into a well that
complies with applicable UIC or other regulations, is located onshore
or offshore under submerged lands within the territorial jurisdiction
of states or federal waters, and is not used as a tertiary injectant in
a qualified enhanced oil or natural gas recovery project; and is stored
in compliance with applicable requirements under subpart RR; or (2)
injected into a well that complies with applicable UIC or other
regulations, is located onshore or offshore under submerged lands
within the territorial jurisdiction of states or federal waters, and is
used as a tertiary injectant in a qualified enhanced oil or natural gas
recovery project and stored in compliance with applicable requirements
under subpart RR or CSA/ANSI ISO 27916:2019.
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\145\ Internal Revenue Service, Treasury Department, Credit for
Carbon Oxide Sequestration, Final Regulations (88 FR 4728, January
15, 2021), available at https://www.govinfo.gov/content/pkg/FR-2021-01-15/pdf/2021-00302.pdf (accessed September 7, 2021).
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For EOR facilities that choose CSA/ANSI ISO 27916:2019 for purposes
of demonstrating secure geological storage for the IRC section 45Q tax
credit, the IRS regulations require that documentation be provided to a
qualified independent engineer or geologist, who then must certify that
the documentation provided, including the mass balance calculations as
well as information regarding monitoring and containment assurance, is
accurate and complete. Under existing GHGRP requirements, reporters
that choose CSA/ANSI ISO 27916:2019 for purposes of the section 45Q tax
credit continue reporting under subpart UU of the GHGRP if they choose
not to report under subpart RR.
Both subpart RR and CSA/ANSI ISO 27916:2019 require an assessment
and monitoring of potential leakage pathways; quantification of inputs,
losses, and storage through a mass balance approach; and documentation
of steps and approaches used to establish these quantities. However,
the inputs of the mass balance equations differ as between subpart RR
and CSA/ANSI ISO 27916:2019. Specifically, the subpart RR mass balance
equation for quantifying the amount of CO2 that is
geologically sequestered includes variables on injected CO2;
equipment leaks and vented CO2 emissions from surface
equipment between the flow meters and the wellhead; CO2
produced and/or remaining with produced oil, gas, or other fluids; and
CO2 leakage to the surface. In contrast, under CSA/ANSI ISO
27916:2019, the mass of CO2 stored is determined as the
total mass of CO2 received minus the total mass of
CO2 lost from project operations and the mass of
CO2 lost from the EOR complex. The CSA/ANSI ISO 27916:2019
standard defines the EOR complex as the project reservoir, trap, and
such additional surrounding volume in the subsurface as defined by the
operator within which injected CO2 will remain in safe,
long-term containment. Specific losses that are determined under the
CSA/ANSI ISO 27916:2019 standard include those from leakage from
production, handling, and recycling facilities; from infrastructure
(including wellheads); from venting/flaring from production operations;
and from entrainment within produced gas/oil/water when this
CO2 is not separated and reinjected. Thus, a primary
difference between subpart RR and CSA/ANSI ISO 27916:2019 relates to
the terms in their respective mass balance equations.
There are other noteworthy differences between subpart RR and CSA/
ANSI ISO 27916 as well. One is how they determine ``leakage.'' Subpart
RR quantification is based on leakage of CO2 to the surface,
that is, emissions of CO2 to the atmosphere. In contrast,
CSA/ANSI ISO 27916:2019 considers leakage to be CO2 that
migrates outside of the EOR complex.
Another difference is the time when facilities may discontinue
reporting. Under subpart RR, a facility may discontinue reporting if it
demonstrates that current monitoring and model(s) show that the
injected CO2 stream is not expected to migrate in the future
in a manner likely to result in surface leakage. Under CSA/ANSI ISO
27916:2019, the operator must demonstrate that the CO2-EOR
project is completed, based on (1) the cessation of CO2
injection, (2) the cessation of hydrocarbon production from the project
reservoir, and (3) the plugging and abandoning of wells, unless
otherwise required by the appropriate regulatory authority.
Another, and, for present purposes, perhaps the most salient
difference between subpart RR and CSA/ANSI ISO 27916:2019 is related to
public transparency. The EPA publishes final decisions under subpart RR
on its website, such as whether to approve an MRV plan or request for
discontinuation of reporting. Any interested person can appeal subpart
RR final decisions to the EPA's Environmental Appeals Board. In
addition, the EPA also verifies the data submitted in annual GHGRP
reports, including annual monitoring reports submitted under subpart
RR, and publishes non-confidential data on the EPA website. In
contrast, facilities that follow CSA/ANSI ISO 27916:2019 are not
currently subject to requirements related to public reporting and
transparency of amounts stored and associated documentation.
In comments to the IRS on the proposed IRC section 45Q regulations,
several commenters supported the IRS's adoption of the CSA/ANSI ISO
27916:2019 ISO pathway, but were concerned that the ISO standard
itself, as relied on by the IRS, does not contain the requirements for
public disclosure and transparency of information necessary to allow
the public to review the adequacy of the demonstration of secure
geologic storage. Commenters also emphasized the importance and need
for credible third-party audits and certifications, and government
oversight and enforcement.\146\ The IRS responded
[[Page 37016]]
that it is constrained by law concerning the public disclosure of
information submitted by taxpayers.
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\146\ See 85 FR 34050, 34055 (June 20, 2020).
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Some stakeholders recommended that the EPA promulgate a new subpart
to the part 98 regulations for GHGRP that would establish procedures
for documenting and reporting the amount of carbon oxide securely
stored using the CSA/ANSI ISO 27916:2019 methodology.\147\ The
reporting of this information to the EPA would ensure that the public
has access to the relevant information in the same manner that the
public currently has access to the information reported to the EPA
under subpart RR. This reporting would also provide the EPA with
complete data (that is, data from reporting under both subpart RR and
CSA/ANSI ISO 27916:2019) to fully understand the amounts of
CO2 that are geologically sequestered for EOR.
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\147\ See, e.g., Comments by Carbon Utilization Research
Council, Clean Air Task Force, ClearPath, Environmental Defense
Fund, Oxy Low Carbon Ventures, Shell Oil Company, and The Nature
Conservancy on the Proposed ``Credit for Carbon Oxide
Sequestration,'' Docket Id. No. IRS-2020-0013-0057, August 3, 2020;
Comments by Clean Air Task Force on the Proposed ``Credit for Carbon
Oxide Sequestration,'' Docket Id. No. IRS-2020-0013-0035, August 3,
2020; Comments by Shell Oil Company on the Proposed ``Credit for
Carbon Oxide Sequestration,'' Docket Id. No. IRS-2020-0013-0046,
August 4, 2020. These comments are in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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Therefore, the EPA is proposing a new source category--subpart VV--
related to the option for reporting of incidental CO2
storage associated with EOR based on the CSA/ANSI ISO 27916:2019
standard. Specifically, facilities that conduct EOR would be required
to report basic information on CO2 received under subpart
UU, or they could choose to opt-in to either subpart RR or the new
subpart to quantify amounts of CO2 that are geologically
sequestered. The EPA seeks comment on this new proposed subpart VV.
The EPA is proposing that facilities would report the amount of
CO2 stored, inputs included in the mass balance equation
used to determine CO2 stored using the CSA/ANSI ISO
27916:2019 methodology, and documentation providing the basis for that
determination as set forth in CSA/ANSI ISO 27916:2019. Specifically,
the reporting of documentation under subpart VV would involve providing
the CSA/ANSI ISO 27916:2019 EOR Operations Management Plan (OMP), which
is required to specify: (1) a geological description of the site, the
procedures for field management and operational containment during the
quantification period; (2) the initial containment assurance plan to
identify potential leakage pathways; (3) the plan for monitoring of
potential leakage pathways; and (4) the monitoring methods for
detecting and quantifying losses and how this will serve to provide the
inputs into site-specific mass balance equations. The EOR OMP sets
forth the operator's approaches for containment assurance and
monitoring and provides the level of detail on operations and reporting
that are comparable to an MRV plan submitted under subpart RR. Thus,
annual reporting under subpart VV should specify any changes made to
containment assurance and monitoring approaches and procedures in the
EOR OMP made within the reporting year.
In addition, the EPA is proposing that reporters annually report
the following information per CSA/ANSI ISO 27916:2019: (1) the quantity
of CO2 stored during the year; (2) the formula and data used
to quantify the storage, including the quantity of CO2
delivered to the CO2-EOR project and losses during the year;
(3) the methods used to estimate missing data and the amounts
estimated; (4) the approach and method for quantification utilized by
the operator, including accuracy, precision and uncertainties; (5) a
statement describing the nature of validation or verification,
including the date of review, process, findings, and responsible person
or entity; and (6) the source of each CO2 stream quantified
as storage.
The EPA is proposing to require that reporters to subpart VV
provide a copy of the independent engineer or geologist's certification
as part of reporting to subpart VV, if such a certification has been
made. The EPA notes that regulations under IRC section 45Q require the
EOR OMP and the data in the annual report be provided to a qualified
independent engineer or geologist, who then must certify that the
documentation, including the mass balance calculations as well as
information regarding monitoring and containment assurance, is accurate
and complete. However, the EPA is not proposing EPA approval of a
third-party approved and certified EOR OMP and documentation. In
contrast, subpart RR requires EPA approval of subpart RR MRV plans.
Under CSA/ANSI ISO 27916:2019, monitoring and reporting and
associated recordkeeping is required to continue until the
CO2-EOR project is terminated, at which time the monitoring,
reporting, and recordkeeping may cease. CSA/ANSI ISO 27916:2019
provides that CO2-EOR project termination is completed when
all of the following occur: CO2 injection has ceased,
hydrocarbon production from the project reservoir has ceased, and wells
have been plugged and abandoned unless otherwise required by a
regulatory authority. The EPA proposes that the time for cessation of
reporting under subpart VV be the same as under CSA/ANSI ISO
27916:2019, and that the operator notify the Administrator of its
intent to cease reporting and provide a copy of the CO2-EOR
project termination documentation.
Currently under the GHGRP, if an owner or operator chooses to opt
in to reporting under subpart RR for a CO2-EOR project, that
owner/operator is no longer required to report under subpart UU for
that CO2-EOR project, in light of the fact that
CO2 received is reported under both subparts. Because
CO2 received would be an element in the mass balance
equation under subpart VV for the mass of CO2 input, the EPA
proposes that if and when an operator begins reporting under subpart
VV, that operator will no longer be required to report under subpart UU
for that CO2-EOR project.
IV. Additional Requests for Comment
The EPA is considering future revisions to the GHG Reporting Rule
to potentially expand existing source categories or develop other new
source categories that would add calculation, monitoring, reporting,
and recordkeeping requirements related to energy consumption; ceramics
production; calcium carbide production; glyoxal, glyoxylic acid, and
caprolactam production; coke calcining; and CO2 utilization.
Based on our recent review of the data collected under the GHGRP and in
consideration of data that are needed to continue to inform the EPA's
understanding of GHG data and better inform future EPA policy and
programs, we are considering revising part 98 to include these newly
identified source categories. Therefore, the EPA is specifically
requesting comment related to the potential expansion of existing
source categories or development of new source categories described in
this section. If the Agency decides that sufficient information is
available to support a rule revision, the EPA may consider undertaking
a future action to expand or add these new source categories.
In the development of the GHGRP, the EPA considered its authorities
under CAA sections 114 and 208 and the information that would be
relevant to the EPA's carrying out a wide variety of CAA provisions
when considering source categories. As part of the process in selecting
the original list of source
[[Page 37017]]
categories to include in the GHG Reporting Rule in 2010, the EPA
considered the language of the Appropriations Act, which referred to
reporting ``in all sectors of the economy,'' and the accompanying
explanatory statement, which directed the EPA to include ``emissions
from upstream production and downstream sources to the extent the
Administrator deems it appropriate'' (74 FR 16465, April 10, 2009). To
develop the list of source categories, we followed a four-step process:
(1) we first considered all anthropogenic sources of GHG emissions or
supply; (2) we considered all of the source categories in the U.S. GHG
Inventory; (3) we reviewed the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories for source categories that may be relevant
for the United States; and (4) once the list was completed, we
systematically reviewed those source categories to ensure that they
included the most significant sources of GHG emissions and the most
significant suppliers of GHG-emitting products. We also confirmed that
the reported GHGs can be measured with an appropriate level of
accuracy.\148\ As described in sections IV.A through F of this
preamble, we are requesting comment on expanding existing source
categories or developing other new source categories based on the EPA's
current understanding of U.S. GHG trends and where we have identified
that additional data may be necessary to better understand GHG data
from these specific sectors to inform future policy.
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\148\ Refer to the preamble to the April 10, 2009 proposal (74
FR 16465) for further discussion of the EPA's rationale for its
original section of source categories to include.
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The addition of these source categories would provide data that
would help eliminate data gaps, improve the coverage of the GHGRP, and
inform the development of GHG policies and programs under the CAA. The
GHGRP data continues to additionally be used as a resource for the U.S.
GHG Inventory, providing not only annual emissions information, but
also other annual information such as activity data and emission
factors that can improve and refine national emission estimates and
trends over time. Including these additional source categories would
also allow the EPA to gather data that could improve the completeness
of the emissions estimates presented in the U.S. GHG Inventory. For
example, we are requesting comment on whether the EPA should collect
data on energy consumption, a source category for which part 98 does
not currently require reporting and which would support data analyses
related to informing voluntary energy efficiency programs, providing
information on industrial sectors where currently little data is
reported to GHGRP, and informing QA/QC of the U.S. GHG Inventory.
Inclusion of certain of these source categories would reduce potential
data gaps in the GHGRP by incorporating emission sources that are
recommended by (and for which there are existing calculation
methodologies available in) the 2006 IPCC Guidelines used to prepare
the U.S. GHG Inventory. Specifically, the IPCC 2006 Guidelines
currently identify ceramics production, calcium carbide production, and
glyoxal, glyoxylic acid, and caprolactam production as potential
sources of GHG emissions. However, emissions from these processes are
not currently estimated in the GHGRP or the U.S. GHG Inventory. The
collection of data from these source categories (e.g., ceramic
production, calcium carbide production, and glyoxal, glyoxylic acid,
and caprolactam production) would improve the coverage of the GHGRP and
provide for more accurate estimates of U.S. GHG emissions that could
then be used to inform development of EPA policies and programs.
The EPA is requesting comment on some source categories, such as
coke calciners, that we have identified because they may potentially
contribute significant emissions that are not currently reported. In
other cases, through implementation of the program, the EPA has
identified facilities representative of these source categories that
are currently reporting under another part 98 source category, and
relying on that other source category's calculation, monitoring, and
reporting requirements for the purposes of estimating total facility
GHG emissions. However, these facilities may not in fact be reporting
complete or accurate estimates of emissions because appropriate
estimation methods are currently unavailable for the source category.
We are also requesting comment on source categories where we have
identified emerging industries that utilize captured carbon emissions,
and as a result would improve our knowledge of carbon utilization.
Inclusion of specific requirements for these source categories in
part 98 would provide a means for the EPA to better estimate and
understand U.S. GHG emissions and trends that could inform future
policies. Therefore, we are soliciting comment on these source
categories and the appropriate accounting methodologies, monitoring,
and associated reporting requirements that should be considered in
development of a future proposed rulemaking. Sections IV.A through IV.F
of this preamble provide additional information on the EPA's
consideration of including these source categories in the GHGRP and the
information we are seeking.
The EPA is also considering proposing future amendments to subpart
F of part 98 (Aluminum Production) to include reporting for additional
sources of emissions, to update the cell technology types reflected in
the rule, and to revise or replace the measurement and calculation
methodologies with newer, improved methodologies. These updates are
being considered based on new information and methodologies identified
from the 2019 Refinement. Section IV.G of this preamble provides
additional information on the EPA's consideration of these amendments
and the information we are seeking.
A. Energy Consumption
Indirect GHG emissions can result from on-site energy consumption,
primarily the use of purchased electricity and thermal energy products.
In this preamble we refer broadly to purchased electricity and thermal
energy products such as steam, heat (in the form of hot water), and
cooling (in the form of chilled water) as ``purchased energy'' or as
``purchased energy products.'' These terms expressly exclude the
purchase of fuels associated with direct emissions.
In the 2009 GHGRP proposal, the EPA sought comment on, but did not
propose, reporting related to electricity consumption. See 74 FR 16479,
April 10, 2009. Comments received, as well as our responses to those
comments, are summarized in the 2009 final rule. See 74 FR 56288-56289,
October 30, 2009. We note that in 2009 some commenters expressed
concerns regarding the collection of data on purchased electricity for
several reasons. Primarily, they said it would constitute double
counting if direct emissions were collected from electric utilities and
the EPA also collected electricity consumption from facilities and
estimated emissions attributable to the facilities' electricity
consumption. Others stated that collecting information on electricity
purchases was outside the scope of the rule, that it is not useful
information in attempting to quantify emissions, that it would be
burdensome for facilities, and that it is CBI that companies are not
able to share with the EPA. In 2009, we responded to these concerns
stating that collection of electricity purchase data under the GHGRP is
consistent with the
[[Page 37018]]
Consolidated Appropriations language,\149\ and provides valuable
information to the EPA and stakeholders in the development of climate
change policy and programs. We still believe this to be true today.
Ultimately, the EPA decided at that time not to propose requirements
for facilities to report either their electricity purchases or indirect
emissions from electricity consumption. In the 2009 final rulemaking,
we stated that acquiring such data may be important in the future, and
we were exploring options for possible future data collection on
electricity purchases and indirect emissions and the uses of such data.
We also said that such a future data collection on indirect emissions
would complement the EPA's interests in energy efficiency and renewable
energy.
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\149\ Consolidated Appropriations Act, 2008, Public Law 110-161,
121 Stat. 1844, 2128. Congress reaffirmed interest in a GHG
Reporting Rule, and provided additional funding, in the 2009
Appropriations Act (Consolidated Appropriations Act, 2009, Pub. L.
110-329, 122 Stat. 3574-3716).
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In this action, we are requesting comment on whether the EPA should
expand the GHGRP so that facilities that are subject to the GHGRP would
be required to submit new, summary data elements quantifying their
consumption of purchased energy products and characterizing associated
markets and products (e.g., regulated or de-regulated electricity
markets and renewable attributes of purchased products). Under this
approach, facilities would not be required to quantify indirect
emissions, and indirect emissions would not count towards GHGRP
applicability. However, the EPA could estimate indirect emissions using
the purchased energy data. We solicit comment on this potential
approach and on advantages and disadvantages of limiting the scope of
any new reporting requirements to compiling and reporting purchased
energy records.
The EPA is seeking comment on how an energy consumption source
category should be defined, whether it should include purchased thermal
energy products, and whether or not associated reporting requirements
should differentiate purchased thermal energy products from purchased
electricity.
The EPA also seeks comment on the approach of limiting
applicability of an energy consumption source category to facilities
that are currently subject to the GHGRP. For example, should the EPA
consider adding new sector-specific requirements for operators of EAFs
or other operations that may meet all their energy needs with purchased
power and that may not trigger applicability under the GHGRP? The EPA
is seeking comment on specific industrial sectors or technologies that
may not be completely represented within the GHGRP but that should be
considered when evaluating the performance of GHGRP sources (including
usage of purchased energy) within discrete sectors.
The EPA also seeks comment on measures that would minimize the
burden of reporting parameters related to purchased energy
transactions. The EPA understands that cogeneration contracts between
host facilities and energy producers are governed by clear metering and
billing requirements. Accordingly, the EPA is seeking comment on our
understanding that monitoring and recordkeeping systems are already in
place for purchased energy transactions, and the incremental reporting
burden would be minimal. We are also seeking comment on existing
industry standards for assessing the accuracy of the monitoring systems
used for purchased energy transactions.
B. Ceramics Production
The ceramics manufacturing industry comprises a variety of products
manufactured from nonmetallic, inorganic materials, many of which are
clay-based. The major sectors of ceramic products include bricks and
roof tiles, wall and floor tiles, table and ornamental ware, sanitary
ware, refractory products, vitrified clay pipes, expanded clay
products, inorganic bonded abrasives, and technical ceramics (e.g.,
aerospace, automotive, electronic, or biomedical applications). The
general process of manufacturing ceramic products consists of raw
material processing (grinding, calcining, and drying), forming, firing,
and final processing (which may include grinding, polishing, surface
coating, annealing, and/or chemical treatment).
GHG emissions are produced during the calcination process in the
kiln or dryer and from any combustion sources. According to the IPCC
2006 Guidelines,\150\ CO2 emissions result from the
calcination of the raw material (particularly clay, shale, limestone,
dolomite, and witherite) and the use of limestone as a flux. Carbonates
are heated to high temperatures in a kiln or dryer, producing oxides
and CO2. Additionally, CO2, CH4, and
N2O emissions are produced during combustion in the kiln or
dryer and from other combustion sources on site.
---------------------------------------------------------------------------
\150\ IPCC Guidelines for National Greenhouse Gas Inventories,
Volume 3, Industrial Processes and Product Use, Mineral Industry
Emissions. 2006. https://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_2_Ch2_Mineral_Industry.pdf.
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The EPA is considering future amendments to the GHGRP to add a
source category related to ceramics production or to incorporate
ceramics into an existing subpart. Currently, under the GHGRP, ceramic
production facilities report their GHG emissions from stationary fuel
combustion sources if those emissions exceed the 25,000
mtCO2e reporting threshold. Some ceramic production
facilities should also report miscellaneous uses of carbonate if they
meet applicability requirements of subpart U of part 98 (Miscellaneous
Uses of Carbonate).\151\ Addition of a ceramics production source
category would likely include process emissions and would improve the
EPA's understanding of facility-level emissions from this source
category by adding to the completeness of the data collected under the
GHGRP, and better inform future EPA policy. Additionally, such data
would be available to inform estimates and improve completeness of the
U.S. GHG Inventory, consistent with methodological guidance and
completeness principle outlined in the 2006 IPCC guidelines.
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\151\ Subpart U of part 98 includes any equipment that uses the
carbonates limestone, dolomite, ankerite, magnesite, siderite,
rhodochrosite, or sodium carbonate and emits CO2.
Facilities are considered to emit CO2 if they consume at
least 2,000 tons per year of carbonates heated to a temperature
sufficient to allow the calcination reaction to occur.
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According to the 2018 United States Census Bureau, 815 corporations
produce ceramic products; \152\ however, only sixteen facilities owned
by nine of these corporations reported under subpart C of the GHGRP
(General Stationary Fuel Combustion Sources) for RY2019. No ceramics
manufacturers currently report under subpart U of part 98. While some
ceramics manufacturers may use some carbonates directly, it is likely
the majority of the carbonates used are those contained in clay rather
than pure carbonates. Additionally, some ceramic tile kilns may not
heat to temperatures sufficient for calcination to occur, and therefore
would not meet the applicability requirements of subpart U. For these
reasons, emissions from ceramics manufacturers may not be appropriately
captured by the current part 98. Although the nine corporations
reported nearly 1 million mtCO2e from combustion under
subpart C for RY2019, we estimate, using United States Geological
Survey (USGS) reports \153\ on the tons of clays sold or
[[Page 37019]]
used in the United States and IPCC default emission factor values, that
the total process CO2 emissions from carbonates for all
ceramic production facilities in the United States is an additional
1.16 million mtCO2e. We are considering whether adding a
ceramic production source category, as a separate source category or
combined with either the existing subpart N of part 98 or subpart U of
part 98, would provide a more accurate estimation methodology for these
emissions.
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\152\ See U.S. Census Bureau website (https://www.census.gov/naics/), accessed March 2021.
\153\ USGS 2020 Mineral Commodity Summaries. Clay. U.S.
Department of the Interior, U.S. Geological Survey, February 2020.
https://www.usgs.gov/centers/nmic/mineral-commodity-summaries.
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Methods for calculating GHG emissions from ceramic production are
available in the 2006 IPCC Guidelines,\154\ including methods based on:
(1) default emission factors that assume limestone and dolomite are the
only carbonates contained in clay and that 85 percent of carbonates
consumed are limestone and 15 percent of carbonates consumed are
dolomite; (2) facility-specific data on the quantity of limestone
versus dolomite consumed; and (3) a carbonate input approach that
accounts for all carbonates (species and amounts) and which mirrors the
methodology used for estimating CO2 emissions from glass
production in subpart N of part 98. We are considering whether
emissions could be estimated for the ceramics production source
category by modifying these methodologies to consider facility-specific
inputs. Facilities could potentially also use a CEMS to monitor
CO2 emissions from the kiln or dryer and use the CEMS data
to report GHG emissions. More information about these potential methods
can be found in the document, Technical Support Document for Ceramics:
Proposed Rule for The Greenhouse Gas Reporting Program, available in
the docket for this rulemaking (Docket Id. No EPA-HQ-OAR-2019-0424).
---------------------------------------------------------------------------
\154\ IPCC Guidelines for National Greenhouse Gas Inventories,
Volume 3, Industrial Processes and Product Use, Mineral Industry
Emissions. 2006. https://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_2_Ch2_Mineral_Industry.pdf.
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The EPA seeks comment on whether it should add a source category
related to ceramics production, and if so, seeks information that could
be related to source category definitions, calculation methodologies,
and reporting requirements. For example, we are soliciting comment on
how the source category should be defined, and whether it should be
included as a separate category or as part of an existing category,
either subpart N (Glass Production) or subpart U (Miscellaneous Uses of
Carbonate). We also seek comment on which IPCC calculation
methodologies or other methodologies, including those listed in the
document, Technical Support Document for Ceramics: Proposed Rule for
the Greenhouse Gas Reporting Program, should be used, with
consideration of what information is readily available to reporters.
Finally, we are requesting input on available monitoring methodologies
or quality assurance requirements that should be used, including what
data is readily available for reporting that would help to support
emissions estimates.
C. Calcium Carbide Production
Calcium carbide (CaC2) is used in production of
acetylene (for cutting and welding) and calcium cyanamide (for
industrial agricultural fertilizers). CaC2 is manufactured
from lime and carbon-containing raw materials (usually petroleum coke),
by heating the mixture to approximately 2,000 degrees Celsius in an
EAF. Use of carbon-containing raw materials in the production process
results in CO2 and CO emissions. In addition, any presence
of hydrogen-containing volatile compounds and sulfur in the carbon-
containing raw materials may cause formation of CH4 and
SO2 emissions. Also, production of acetylene from
CaC2 results in CO2 emissions.
The EPA is considering future amendments to the GHGRP to add a
source category related to CaC2 production (which may
potentially also include acetylene production if a facility produces
acetylene at their CaC2 production facility). The IPCC 2006
Guidelines currently identify both silicon carbide production and
calcium carbide production as potential sources of GHG emissions.\155\
Although the GHGRP currently accounts for emissions from silicon
carbide production processes, and the GHGRP collects data from silicon
carbide production under subpart BB, emissions from CaC2
production are not explicitly accounted for. Addition of a
CaC2 production source category to the GHGRP would better
align with intergovernmental approaches to estimating emissions,
improve the completeness of the data collected under the GHGRP, add to
the EPA's understanding of the GHG data, and better inform future EPA
policy. Further, such data would be available to improve the estimates
provided in the U.S. GHG Inventory, by improving completeness and
comparability of the estimates consistent with the 2006 IPCC
guidelines.
---------------------------------------------------------------------------
\155\ IPCC Guidelines for National Greenhouse Gas Inventories,
Volume 3, Industrial Processes and Product Use, Mineral Industry
Emissions. 2006. https://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_2_Ch2_Mineral_Industry.pdf.
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The EPA has identified a CaC2 production facility
currently operating in the United States that is voluntarily reporting
GHG emissions under subpart K (Ferroalloy Production) of part 98.
Annual emissions from the reporting facility range between less than
10,000 and 50,000 mtCO2e. We are considering whether adding
the calcium carbide source category, either as a separate source
category or combined with the existing silicon carbide production
category under subpart BB of part 98, would provide more accurate
applicability requirements and emissions estimation methodologies for
these types of facilities. We are also considering, where acetylene
production from CaC2 occurs at the same facility, whether we
should account for emissions from these sources.
We are considering several options for how emissions could be
estimated for CaC2 production at a facility-level based on
methods available in the 2006 IPCC Guidelines, including methods based
on: (1) default emission factors applied to activity data on petroleum
coke consumption or CaC2 production; (2) a carbon
consumption methodology that assumes a stoichiometric conversion where
two-thirds of the carbon consumed is in the CaC2 product and
one-third is emitted as CO2 (similar to the estimation
methods used for the silicon carbide production source category in
subpart BB); and (3) a carbon balance method that uses measured
quantities of carbon consumed in the process and carbon contained in
the CaC2 product. Facilities could potentially also estimate
CO2 emissions using CEMS. More information about these
potential methods and the production of CaC2 can be found in
the document, Technical Support Document for Calcium Carbide: Proposed
Rule for the Greenhouse Gas Reporting Program, available in the docket
for this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424).
The EPA seeks comment on whether it should add a source category
related to CaC2 production, and if so, seeks information
related to source category definitions, calculation methodologies, and
reporting requirements. For example, we solicit comment on how the
source category should be defined, and whether it should be included as
a separate category or, due to similarity in estimation methods, as
part of the existing silicon carbide production category. We also
request comment on whether additional CaC2 production
facilities (other than Carbide Industries
[[Page 37020]]
LLC in Louisville, KY) are currently operating in the United States. In
addition, we seek comment on which tier calculation methodology as well
as the monitoring or measurement methodologies should be used,
particularly the methodology(s) for which facilities would have
information readily available. Furthermore, we seek comment on whether
any CaC2 production facility currently operating in the
United States uses the CaC2 product to produce acetylene at
the same facility, and whether emissions from acetylene production
should be accounted for in the emission estimate methodology. Finally,
we seek input on available monitoring methodologies that should be
used, as well as input on what data are readily available for reporting
that would help to support emissions estimates.
D. Glyoxal, Glyoxylic Acid, and Caprolactam Production
Glyoxal (C2H2O2) is used in a
variety of applications including as a crosslinking agent in various
polymers for paper coatings, textile finishes, adhesives, leather
tanning, cosmetics, and oil-drilling fluids; as a sulfur scavenger in
natural gas sweetening processes; as a biocide in water treatment; as a
chemical intermediate in the production of pharmaceuticals, dyestuffs,
glyoxylic acid, and other chemicals; and to improve moisture resistance
in wood treatment. Glyoxal is also being used as a less toxic
substitute for formaldehyde in some applications such as wood adhesives
and embalming fluids. Glyoxal is commercially manufactured by either:
(1) the gas-phase catalytic oxidation of ethylene glycol with air in
the presence of a silver or copper catalyst (the LaPorte process); or
(2) the liquid-phase oxidation of acetaldehyde with nitric acid.
Glyoxylic acid (C2H2O3) is used mainly
in the synthesis of vanillin, allantoin, and several antibiotics like
amoxicillin, ampicillin, and the fungicide azoxystrobin. Glyoxylic acid
is exclusively produced by the oxidation of glyoxal with nitric acid.
Caprolactam (C6H11NO) is a monomer used in carpet
manufacturing. The addition of hydroxylamine sulphate to cyclohexanone
produces cyclohexanone oxime, which can then be converted to
caprolactam.
The production of any of these organic compounds (glyoxal,
glyoxylic acid, and caprolactam) results in N2O and
CO2 emissions. N2O emissions are created from
either oxidation or reduction steps that occur in each process. Our
knowledge of the mechanisms that generate CO2 emissions from
glyoxal and glyoxylic acid production is less understood. The IPCC 2006
Guidelines state that CO2 emissions generated from
caprolactam production are unlikely to be significant in well-managed
plants.\156\
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\156\ IPCC 2006. IPCC Guidelines for National Greenhouse Gas
Inventories, Volume 3, Industrial Processes and Product Use. Chapter
3, Chemical Industry Emissions. 2006. https://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_3_Ch3_Chemical_Industry.pdf.
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The EPA is considering future amendments to the GHGRP to add a
source category related to glyoxal, glyoxylic acid, and caprolactam
production to improve the completeness of the data collected under the
GHGRP, add to the EPA's understanding of the GHG data and better inform
future EPA policy. Emissions from these processes are not currently
estimated in U.S. GHG Inventory. Therefore, once collected, such data
would be available to and improve on the estimates provided in the U.S.
GHG Inventory, by incorporating the recommendations of the 2006 IPCC
guidelines, which currently identify glyoxal, glyoxylic acid, and
caprolactam production as potential sources of GHG emissions.\157\
Grouping these three organic compounds together into one source
category for GHGRP purposes would be reasonable because the 2006 IPCC
guidelines methodology for estimating GHG emissions from the production
of these compounds does the same.\158\
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\157\ Id.
\158\ Id.
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We are unsure whether there are any glyoxal and/or glyoxylic acid
production facilities currently operating in the United States. Based
on available 2015 data reported under the Toxic Substances Control Act
(TSCA), four facilities could be domestic manufacturers of
glyoxal.159 160 Also, although four facilities reported
glyoxylic acid data under the TSCA, each of these facilities reported
no domestically manufactured glyoxylic acid. We note that more recent
data for 2016 through 2019 are expected to be published by the TSCA,
but these data were not available at the time of writing this proposal.
Nevertheless, it is possible that there are other glyoxal and glyoxylic
acid production facilities operating in the United States, but that are
not reporting under the TSCA because their total production volume is
less than 25,000 pounds per year, or they are exempt from reporting
because they are a small manufacturer based on their total company
sales revenue. Currently, two caprolactam production facilities report
GHG emissions under subpart C of part 98 (General Stationary Fuel
Combustion Sources) (each facility reported RY2019 combustion emissions
of approximately 600,000 to 800,000 mtCO2e).
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\159\ ChemView. Compilation of data submitted under TSCA in 2012
and 2016. https://chemview.epa.gov/chemview. Accessed April 2021.
\160\ In 2015, four facilities indicated that their glyoxal
production status (i.e., as a domestic manufacturer or as an
importer) and their quantities domestically manufactured and/or
imported, were CBI. Thus, it is possible that one or more of these
four glyoxal production facilities could be a domestic manufacturer.
---------------------------------------------------------------------------
Methods for calculating N2O emissions from glyoxal,
glyoxylic acid, and caprolactam production are available in the 2006
IPCC Guidelines, including methods based on: (1) total nationwide
production quantities using default uncontrolled emission factors; (2)
plant-specific production quantities using plant-specific or default
N2O generation and control emission factors; and (3) plant-
specific production quantities and direct measurement of emissions to
calculate plant-specific emission factors.\161\ Although the 2006 IPCC
Guidelines do not provide methods for calculating CO2
emissions from glyoxal and glyoxylic acid production,\162\ we are
considering use of either a default emission factor approach for
N2O and a mass balance approach for CO2, or
development of site-specific factors for both N2O and
CO2. In the first approach, N2O emissions would
be calculated using production and the IPCC default factors, and for
CO2, the mass balance procedures would be similar to mass
balances required for existing subparts in the GHGRP such as
petrochemical production (subpart X). Specifically, site-specific
quantities of all carbon-containing feedstocks and products would be
determined, and CO2 emissions would be calculated assuming
all carbon from the feedstock that does not end up in product is
emitted as CO2. We recognize that if the N2O is
controlled using something other than thermal or catalytic destruction
(that would not convert hydrocarbons to CO2), then this mass
balance approach would not work for CO2. Alternatively,
N2O and CO2 emissions could be calculated using
site-specific production and site-specific emission factors that are
developed based on flow measurement and periodic sampling and
compositional analysis of the
[[Page 37021]]
streams to the control and exiting the control. These emission factors
would be multiplied by the site-specific production quantity to
calculate emissions. More information about these N2O and
CO2 emission calculation methods and the production of
glyoxal, glyoxylic acid, and caprolactam can be found in the document,
Technical Support Document for Glyoxal, Glyoxylic Acid, and Caprolactum
Production: Proposed Rule for The Greenhouse Gas Reporting Program,
available in the docket for this rulemaking (Docket Id. No EPA-HQ-OAR-
2019-0424).
---------------------------------------------------------------------------
\161\ IPCC 2006. IPCC Guidelines for National Greenhouse Gas
Inventories, Volume 3, Industrial Processes and Product Use. Chapter
3, Chemical Industry Emissions. 2006. https://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_3_Ch3_Chemical_Industry.pdf.
\162\ As previously mentioned, the 2006 IPCC Guidelines,
CO2 emissions generated from
C6H11NO production are likely to be
insignificant.
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The EPA seeks comment on whether it should add a source category
related to glyoxal, glyoxylic acid, and caprolactam production, and if
so, seeks information that could be related to source category
definitions, calculation methodologies, and reporting requirements. For
example, we solicit comment on how the source category should be
defined. In addition, as previously mentioned, although we are aware of
at least two caprolactam production facilities, we are unsure whether
there any glyoxal and/or glyoxylic acid production facilities currently
operating in the U.S.; therefore, we seek information about whether
these types of facilities are currently operating in the U.S. We
request comment on whether facilities have installed abatement
equipment. We also solicit comment on which tier calculation
methodologies or other methodologies, including those outlined in the
document Technical Support Document for Glyoxal, Glyoxylic Acid, and
Caprolactum Production: Proposed Rule for The Greenhouse Gas Reporting
Program, available in the docket for this rulemaking (Docket Id. No
EPA-HQ-OAR-2019-0424), should be used to determine GHG emissions from
these types of facilities and which information or inputs for these
methodologies is readily available. Furthermore, as previously
mentioned, although we are considering a mass balance approach to
determine CO2 emissions from these types of facilities, our
knowledge of the mechanisms that generate CO2 emissions from
glyoxal and glyoxylic acid production are not fully understood;
therefore, we request information on this subject. Finally, we seek
input on available monitoring methodologies and quality assurance
procedures that should be used; and input on what data are readily
available for reporting that would help to support emissions estimates.
E. Coke Calcining
Calcined petroleum coke is a nearly pure carbon material used
primarily to make anodes for the aluminum, steel, and titanium smelting
industries. The process used to produce calcined petroleum coke is
called coke calcination and is commonly performed in coke calciners
that are rotary kilns or rotary furnaces equipped with an afterburner.
Coke calcining uses ``green'' petroleum coke with low metals content
(commonly called ``anode grade petroleum coke'') as a feed material.
The coke is then heated to high temperatures in the absence of air or
oxygen for the purpose of removing impurities or volatile substances in
the green coke. Auxiliary fuel is needed to start-up the kiln or
furnace, but once the desired calcining temperature is reached, process
gas consisting of volatile organics and sulfur-containing compounds
driven from the coke are used as the primary fuel to maintain calciner
temperatures. Similarly, the coke calciner afterburner combusts
primarily the process off-gas and requires little, if any, auxiliary
fuel except during start-up. The afterburner is used to convert excess
process gas to CO2 and SO2, and a waste heat
boiler may be used to recover energy from this combustion process. The
afterburner will also likely release trace amounts of CH4
and N2O, similarly to other stationary combustion devices.
The afterburner off-gas is emitted to the atmosphere and is the primary
source of GHG emissions from this process.
Coke calcining processes may be co-located with petroleum
refineries or may be independent facilities. Currently, coke calcining
processes co-located at petroleum refineries must calculate and report
emissions from coke calciners following the methodologies specified in
subpart Y of part 98 (Petroleum Refineries). Several coke calciners not
co-located at petroleum refineries report emissions that are calculated
using the calculation methodologies under subpart C of part 98 (General
Stationary Fuel Combustion Sources). The calculation methodologies in
subparts C and Y, for facilities not using CEMS, are substantially
different, resulting in inconsistent characterization of emissions
between the two populations of sources. Specifically, the subpart C
emission calculations assume that the carbon content of the fuel burned
is represented by the default carbon content of petroleum coke and that
the carbon in the petroleum coke is fully combusted and converted to
CO2 whereas the subpart Y calculation uses a mass balance
approach to account for the fact that the carbon content in the final
product is higher than the carbon content in the petroleum coke fed to
the unit, thereby more accurately accounting for the carbon content in
the process gas actually combusted. The EPA is considering future
amendments to the GHGRP to add a coke calcining source category to
require specific calculation methodologies and reporting requirements
for coke calciners not co-located with petroleum refineries, in order
to improve the completeness of the data collected under the GHGRP and
better inform future EPA policy. Incorporating a new source category
would improve the consistency of emission calculation methodologies for
coke calcining processes units regardless of whether nor not they are
co-located with a petroleum refinery. The EPA seeks comment on whether
a separate source category for coke calcining facilities should be
added to the GHGRP.
The EPA identified 15 coke calcining facilities operating 29 coke
calcining process units in the United States. Most coke calcining
facilities are located at or near a petroleum refinery. Three of the
facilities report GHG emission under subpart Y. The remaining
facilities either do not report coke calcining emissions or report
emissions under subpart C. Based on data reported to the GHGRP for
RY2019, the typical coke calcining facility emits 150,000
mtCO2e per year. With 15 operating facilities in the U.S.,
it is estimated that these facilities emit 2.2 million
mtCO2e per year. The EPA seeks information on the total
number of facilities currently operating coke calciners in the United
States.
There are four possible calculation methodologies for determining
GHG emissions from coke calciners, shown in order of most accurate to
least: (1) use of CEMS; (2) a mass balance using the carbon content of
the green and calcined coke; (3) a mass balance using a fixed methane
content in the coke and using a mass reduction in the quantity of coke
fed to the process and the quantity of coke leaving the process; and
(4) using either default high heat values and CO2 emission
factors or assuming the reduction in the mass of coke is solely due to
the combustion of green coke fed to the calciner. More information
about these methods and the coke calcining process can be found in the
memorandum, Technical Support Document for Coke Calcining: Proposed
Rule for The Greenhouse Gas Reporting Program, available in the docket
for this rulemaking (Docket Id. No EPA-HQ-OAR-2019-0424).
[[Page 37022]]
Subpart Y allows the use of CEMS (methodology (1), as noted above).
If CEMS are not used, subpart Y requires the use of a carbon mass
balance approach using equation Y-13 (methodology (2), as noted above).
Facilities using equation Y-13 must measure the mass of petroleum coke
in and out of the process and the carbon content of the coke in and out
of the process. Subpart Y also requires estimating CH4 and
N2O emissions based on the CO2 emissions, and the
ratio of the CH4 or N2O emission factor for
``petroleum products'' in Table C-2 of subpart C and the CO2
emission factor for petroleum coke in Table C-1 of subpart C of part
98. If a new subpart for coke calcining is developed, the EPA seeks
comment on the appropriate calculation method(s) to require. The EPA is
also seeking comment on whether coke calcining facilities are already
collecting the necessary information to estimate GHG emissions using
methodologies (2), (3), and (4), as described in this section. We are
also seeking comment on appropriate monitoring for the four
methodologies described in the Technical Support Document for Coke
Calcining: Proposed Rule for The Greenhouse Gas Reporting Program,
available in the docket for this rulemaking (Docket Id. No EPA-HQ-OAR-
2019-0424). Finally, we are seeking input on appropriate missing data
and quality assurance procedures.
F. CO2 Utilization
As mentioned in the previous section, CCUS refers to a set of
technologies that capture CO2 from the emissions of large
point sources or ambient air, transport it, compress it, and either
utilize it or inject it in deep underground for safe and secure
storage. CO2 utilization is a quickly growing area of
interest among stakeholders and there is currently a lack of publicly
available and nationally consistent GHG data regarding CO2
utilization. As technologies scale up and markets develop for
CO2 utilization, the potential for GHG mitigation through
CO2 utilization is expected to greatly expand. There are a
broad range of CO2 utilization pathways (i.e., technological
approaches for carbon utilization), with each utilization pathway
having its own set of specific characteristics in terms of products
manufactured, technical maturity, market potential, economics,
potential to displace existing products or sources of CO2,
and lifecycle GHG impact.
The EPA is considering amendments to part 98 to add a source
category related to CO2 utilization. While part 98 has
source categories related to Suppliers of Carbon Dioxide (subpart PP),
Injection of Carbon Dioxide (subpart UU) and Geologic Sequestration of
Carbon Dioxide (subpart RR), it does not have a source category that is
solely related to CO2 utilization. The inclusion of
CO2 utilization as a source category in part 98 could fill a
critical informational gap and inform future policy and programs under
the CAA.
The EPA seeks comment on whether we should add a source category
related to CO2 utilization, and if so, seeks information
related to source category definition; calculation, monitoring and QA/
QC methodologies; and reporting requirements.
The EPA seeks comment on how the source category would be defined.
In order to define the source category, the EPA seeks information to
contextualize potential reporters and understand how this reporting
would relate to other source categories of the GHGRP. For example, the
EPA seeks comment on different types of end products that utilize
CO2 (currently and potentially), the amount of captured
CO2 used per unit of production or manufacture (gallons,
metric tons, etc.) for different processes (currently and potentially),
including processes that do not result in manufacture of marketable
product (e.g., ex-situ mineralization for storage only). Additionally,
the EPA seeks comment on the total amount of captured CO2
being used in the end use per year for different manufacturing
processes or utilization pathways (currently and potentially),\163\
whether there should be a threshold for reporting, and if so, how that
threshold should be defined. The EPA seeks information on the total
number of facilities (currently and potentially), and how many
facilities would be reporting under different potential thresholds. The
EPA requests comment on whether particular CO2 utilization
pathways should be included in the source category, and if so, how
should those pathways be defined. The EPA also requests comment on
whether the source category should include reporting of not only
CO2, but also other greenhouse gases.
---------------------------------------------------------------------------
\163\ The EPA notes that aggregated totals of primary end uses
for CO2 captured and produced are available on the GHGRP
website at https://www.epa.gov/ghgreporting/supply-underground-injection-and-geologic-sequestration-carbon-dioxide.
---------------------------------------------------------------------------
The EPA seeks comment on what calculation methodologies should be
used for purposes of part 98 reporting. For example, most source
categories reporting under part 98 focus on reporting of direct
emissions. Taking a similar approach for CO2 utilization
would exclude emissions associated with the end use of the
CO2 in the product. A full accounting of all GHGs from
cradle to grave, including the potential to displace an existing
product or other existing source of CO2, would be needed to
understand the product's life cycle and total GHGs emitted. To that
end, the EPA seeks input regarding whether a GHG LCA should be
required, and if so, what information, protocols, guidance, and/or
models would be required to conduct the LCA, who should validate it,
what information would need to be reported to support the LCA
validation, and to what extent LCA information is already reported
through other GHGRP subparts.
In addition to calculation methodologies, the EPA seeks comment on
what monitoring requirements should be in place and what methodologies
are recommended for monitoring and QA/QC. LCA is also relevant with
regard to monitoring, as CO2 can be stored and emitted at
various stages of the product's lifecycle, and the length of
CO2 storage varies between CO2 utilization
pathways and end products. The EPA also seeks comment on how permanence
of the CO2 storage should be defined and addressed if LCA
were not required. Similarly, the EPA seeks comment on information that
could be used for, and the feasibility of developing, sequestration
lifetimes for various products that result from different utilization
pathways. For both calculation and monitoring of CO2
utilization under part 98 reporting, the EPA seeks comment on QA/QC
practices to ensure consistent and accurate estimates.
Finally, the EPA requests comment on the reporting requirements
related to CO2 utilization. CO2 utilization
technologies can vary widely (e.g., biological, chemical, or physical
processes), and many technologies are still emerging. The EPA seeks
input on how to manage reporting of these highly variable and emerging
technologies. For example, we are seeking comment on whether different
technology categories should have different calculation, monitoring,
and reporting requirements. Additionally, the EPA requests comment
regarding specific data elements to be reported. This includes the
amount of CO2 utilized, types of greenhouse gases to be
reported (i.e., reporting of not only CO2, but also other
greenhouse gases), and end uses of the CO2. It also includes
emissions of greenhouse gases throughout the lifecycle of a product,
and more specifically emissions of greenhouse gases during the
utilization process, the ultimate fate of the CO2 used, and
the
[[Page 37023]]
sequestration lifetime of the utilized CO2. EPA also seeks
comment on whether the source of CO2 used in the utilization
process should be reported, and if so, what information on the source
should be reported (e.g., captured versus extracted, sector or type of
facility from which the CO2 was captured and sourced, and/or
facility-specific information for where CO2 was captured and
sourced).
G. Aluminum Production
The EPA is considering proposing to amend subpart F of part 98
(Aluminum Production) to add reporting of low voltage emissions and
cell-start-up emissions. The EPA is also considering updating cell
technology categories to be consistent with the 2019 Refinement. The
EPA is also considering updating or replacing the 2008 Protocol \164\
(used for development of the current emissions measurement methodology)
based on the 2020 International Aluminium Institute (IAI) ``Good
Practice Guidance: Measuring Perfluorocarbons'' \165\ (hereafter
referred to as ``2020 IAI Good Practice Guidance'') and the 2008 U.S.
EPA/IAI ``Protocol for Measurement of Tetrafluoromethane
(CF4) and Hexafluoroethane (C2F6)
Emissions from Primary Aluminum Production'' \166\ developed by the
IAI. Low voltage anode effects (LVAEs), where the cell voltage does
exceed the voltage threshold, have been identified as a source of
CF4 emissions and can be a significant portion of the
emissions in modern high-amperage cells with many large anodes.
Emissions from LVAEs would be better characterized by measuring
emission factors specifically for low voltage emissions. Emissions of
CF4 from LVAEs have not previously been included due to a
lack of data and methodology for their estimation. However, the 2019
Refinement provides several methods for estimating LVAE emissions. The
2019 Refinement also provides methods for potentially more accurately
characterizing cell start-up emissions and high voltage anode effect
emissions (HVAEs) through the addition of new non-linear Tier 3
methods. The 2020 IAI Good Practice Guidance provides additional
guidance on measurement frequency, calculation of emission factors
using new Tier 3 calculation methods available in the 2019 Refinement
and updating methods to account for both low voltage and high voltage
emissions of PFCs. In addition to improving the accuracy of emissions
reported the GHGRP and adding to the EPA's understanding of facility-
level emissions from this source category, the collection of low
voltage and start-up emissions data would also improve emissions
estimates for the U.S. GHG Inventory and better inform future EPA
policy. Currently the U.S. GHG Inventory uses a Tier 1 emission factor
to estimate LVAE emissions, based on production technology and high
voltage emission estimates, which may overestimate low voltage
emissions. However, the LVAE data is still somewhat limited. Additional
studies would help to assess how frequently measurements must be made
to maintain an accurate accounting of smelter emissions, including low
voltage emissions. Studies are also needed to assess the relative
advantages in robustness and accuracy of the non-linear method for
calculating HVAE PFC emissions. The EPA requests comment on the extent
to which low voltage emissions have been characterized and if data is
available to develop guidance on low voltage emission measurements
needed to develop robust LVAE emission factors. The EPA also requests
comment on the use of the non-linear method as an alternative to the
slope coefficient and overvoltage methods currently allowed in subpart
F. The EPA is also requesting comment on the methods and protocols in
the 2020 IAI Good Practice Guidance.
---------------------------------------------------------------------------
\164\ U.S. Environmental Protection Agency & International
Aluminium Institute. (2008). Protocol for Measurement of
Tetrafluoromethane (CF4) and Hexafluoroethane
(C2F6) Emissions from Primary Aluminum
Production. Available in the docket for this rulemaking (Docket Id.
No. EPA-HQ-OAR-2019-0424).
\165\ Available at https://international-aluminium.org/resource/good-practice-guidance-measuring-perfluorocarbons/ and in the docket
for this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424).
\166\ Available at https://international-aluminium.org/resource/good-practice-guidance-measuring-perfluorocarbons/ and in the docket
for this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424).
---------------------------------------------------------------------------
V. 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 publish any amendments before the end of
2022. We are proposing that these amendments would become effective on
January 1, 2023 and that reporters would implement the changes
beginning with reports prepared for RY2023 and submitted April 1, 2024.
We have determined that it would be feasible for existing reporters
to implement the proposed changes for RY2023 because the revisions
primarily include improvements to the rule that are consistent with the
current data collection and calculation methodologies. Some of the
proposed amendments would clarify and improve the existing rule in
order to enhance the quality and accuracy of the data collected. These
revisions primarily provide additional clarifications or flexibility
regarding the existing regulatory requirements, do not add new
monitoring or sampling requirements, and do not substantially affect
the information that must be collected (i.e., require new data
collection). In the limited cases where we are proposing to require the
collection of additional data, such as from subpart W (Petroleum and
Natural Gas Systems) facilities, we are proposing to allow reporters to
use BAMM for the first annual report submitted for RY2023 (as discussed
in section III.J of this preamble), which would provide additional time
for facilities to adapt to new monitoring requirements and, for
example, install the appropriate equipment. Where calculation equations
are proposed to be modified, the changes clarify equation terms or
simplify the calculations, and do not require any additional data
monitoring. In these cases, we anticipate that facilities would have
any additional inputs for calculations available in company records or
could easily calculate the required input from existing process
knowledge and engineering estimates, or from available company records.
Therefore, these types of changes are not anticipated to add
significant burden for reporters. Although we are proposing one change
to require additional reporting under subpart C (for separate reporting
of biogenic emissions from the combustion of tires), because we are
simultaneously proposing removal of the ``less than 10 percent''
restriction on using the default biogenic CO2 factor to
estimate biogenic emissions in 40 CFR 98.33(e)(3)(iv), the new
reporting would not require any additional monitoring or data
collection. As such, all reporters who combust tires would be able to
use the default biogenic CO2 factor, and would not need to
conduct quarterly flue-gas testing, to establish the biogenic fraction
of emissions.
In several instances we are proposing to require reporting of
additional data elements to improve verification of annual reports,
provide a more complete picture of GHG emissions or supply, or develop
factors that may inform the U.S. GHG Inventory. As provided in section
III of this preamble, in these instances we anticipate that the data is
already available in company records (e.g., production or material use
data, or data on product or equipment type). In most
[[Page 37024]]
cases the data we are requesting can be calculated using data that is
already required to be entered into the EPA's reporting system, is
already maintained in keeping with existing facility data permits
(e.g., hours of operation an abatement device was not in use), or may
be estimated using emission factors or engineering judgment. For
example, where we are proposing to add reporting of unit specific data
for subpart C (General Stationary Fuel Combustion Sources) reporters
using the aggregation of units or common pipe configurations,
facilities already collect data on the maximum rated heat input
capacity of individual units in each aggregation of units or common
pipe configuration (greater than or equal to 10 mmBtu/hr) to determine
the reported cumulative maximum rated heat input capacity, and would be
able to determine the other data elements requested (i.e., unit type
and estimate of the fraction of annual heat input) from their existing
company records.
Additionally, although we are proposing the addition of calculation
and reporting requirements under new subpart VV (Geologic Sequestration
of Carbon Dioxide with Enhanced Oil Recovery Using ISO 27916), we do
not anticipate that the new subpart would expand the existing coverage
of facilities subject to the GHGRP, but would only apply to those
reporters that currently report under subpart UU (Injection of Carbon
Dioxide) and that choose to report amounts of CO2 stored
under the proposed subpart VV. It is anticipated that these facilities
already follow the calculation requirements and data gathering
prescribed under CSA/ANSI ISO 27916:2019 (e.g., as discussed in section
III.W of this preamble, to quantify storage for the IRC section 45Q tax
credit); would not perform any additional calculation, monitoring, or
quality assurance procedures under the proposed requirements; and that
the information submitted to the GHGRP would be obtained and provided
from readily available data. These facilities will also retain the
option to continue to report under existing subpart UU with no changes.
Therefore, we have determined that it would be feasible for facilities
who opt to report under proposed subpart VV to implement the proposed
changes for RY2023.
Other proposed changes streamline and improve implementation by
simplifying or clarifying calculation, monitoring, and recordkeeping,
or reporting. These types of changes are intended to simplify or
provide flexibility in the requirements that reporters must meet and do
not require additional data collection. For these reasons, we believe
that a proposed effective date of January 1, 2023 is reasonable.
Reporters are not required to submit RY2023 reports until April 1,
2024, which is over a year after we expect a final rule based on this
proposal to be finalized, if finalized, thus providing an opportunity
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.
We are proposing one change that would impact the date of submittal
of a non-annual report. For subpart I, we are proposing to revise the
frequency of submittal of the technology assessment reports required
under 40 CFR 98.96(y). The proposed change would revise the frequency
of submittal from three years to five years. Under the current rule,
semiconductor manufacturing facilities are required to submit their
next technology assessment report by March 31, 2023 (concurrent with
their RY2022 annual report). The proposed change would affect the due
date of the following technology assessment report, moving the due date
from March 31, 2023 to March 31, 2025. Because the proposed change
would decrease the frequency of submissions and extend the timeframe
for reporters to collect and compile data for the next submittal, we
have determined that the proposed changes would be feasible to
implement by this date.
We are likewise proposing that the proposed CBI determinations
discussed in section VI of this preamble would become effective on
January 1, 2023. The majority of the determinations are for new or
revised data elements that would be included in annual GHG reports
prepared for RY2023 and submitted April 1, 2024. However, there are
some circumstances, discussed in detail in section VI of this preamble,
where the proposed determinations cover data included in annual GHG
reports submitted for prior years. In either case, 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, 2023.
VI. Proposed Confidentiality Determinations for Certain Data Elements
A. Overview and Background
Part 98 requires reporting of numerous data elements to
characterize, quantify, and verify GHG emissions and related
information. 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 rulemakings
dealing with confidentiality determinations for data reported under
part 98. For more information on previous confidentiality
determinations for part 98 data elements, see the following documents:
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 I, W, DD,
QQ, RR, SS, UU; except for those data elements that are inputs to
emission equations. Also finalized confidentiality determinations for
new data elements added to subparts II and TT in the November 29, 2011
Technical Corrections document (76 FR 73886).
78 FR 68162; November 13, 2013. Finalized confidentiality
determinations for new data elements added to subpart I.
78 FR 69337, November 29, 2013. Finalized determinations
for new and revised data elements in 15 subparts, except for those data
elements assigned to the ``Inputs to Emission Equations'' data
category.
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.
79 FR 70352, November 25, 2014. Finalized confidentiality
determinations for new and substantially revised data elements in
subpart W.
79 FR 73750, December 11, 2014. Finalized confidentiality
determinations for certain reporting requirements in subpart L.
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
[[Page 37025]]
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 and for certain existing data elements in 4 subparts.
In this document, we are proposing confidentiality determinations
or ``emission data'' designations for:
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; and
Existing reporting requirements for which the EPA is
proposing to amend existing confidentiality determinations. This
includes cases where the EPA is proposing to amend confidentiality
determinations to align with determinations established in 40 CFR part
84 under the American Innovation and Manufacturing Act of 2020 (AIM
Act).
We are also aware that a few confidentiality determinations
finalized in a previous rulemaking were not clear, and we are now
clarifying the previous determinations. Further, we propose to
designate certain new or substantially revised data elements as
``inputs to emission equations'' falling within the definition of
``emission data'' (see section VI.C of this preamble for a discussion
of ``inputs to emission equations''), and we are proposing to require
reporting of those data elements. Table 5 of this preamble provides the
number of affected data elements and the affected subparts for each of
these proposed actions.
Table 5 of this preamble also describes the effective date of these
proposed actions. The majority of the determinations would apply at the
same time as the proposed schedule described in section V of this
preamble. In the cases where the EPA is proposing a determination for
existing data elements where one was not previously made, or where the
EPA is clarifying an existing determination, the proposed determination
would be effective on January 1, 2023 for RY2023 as well as all prior
years that the data was collected. For the data elements where we are
proposing to amend previous determinations to align with rulemakings
establishing 40 CFR part 84 under the AIM Act, the proposed
confidentiality determinations would apply only prospectively, starting
with RY2022 for the reasons described in section VI.D of this preamble.
Table 5--Summary of Proposed Actions Related to Data Confidentiality
----------------------------------------------------------------------------------------------------------------
Proposed actions related to data Number of data
confidentiality elements \a\ Subparts Effective year
----------------------------------------------------------------------------------------------------------------
New or substantially revised reporting 283 C, G, H, I, N, P, Q, S, W, RY2023.
requirements for which the EPA is X, Y, BB, DD, GG, HH, OO,
proposing a confidentiality PP, SS, VV.
determination or ``emission data''
designation.
Existing reporting requirements for 33 A, I, K, W, HH............ RY2023, and all prior
which the EPA is proposing a years the data was
confidentiality determination or collected.
``emission data'' designation because
the EPA did not previously make a
confidentiality determination or
``emission data'' designation.
Existing reporting requirements for 33 A, RR, UU................. RY2023.
which the EPA is proposing to amend an
existing confidentiality determination.
Existing reporting requirements for 12 A, L, MM, NN.............. RY2023, and all prior
which the EPA is clarifying the current years the data was
confidentiality determination. collected.
New or substantially revised reporting 125 C, I, W, DD, SS........... RY2023.
requirements that the EPA is proposing
be designated as ``inputs to emission
equations'' and for which the EPA is
proposing reporting determinations.
Existing reporting requirements for 9 OO........................ RY2022.
which the EPA is proposing to amend an
existing confidentiality determination
to align with determinations under the
AIM Act.
----------------------------------------------------------------------------------------------------------------
\a\ These data elements are listed in the memoranda: (1) Proposed Confidentiality Determinations and Emission
Data Designations for Data Elements in Proposed Revisions to the Greenhouse Gas Reporting Rule, (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, and (3) Proposed Determinations that would Align the
Greenhouse Gas Reporting Program with the Determinations Made under the AIM Act Regulations, available in the
docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424).
Finally, we are confirming that, except for the cases discussed in
detail in this proposal, part 98 data elements previously determined to
be entitled to confidential treatment through rulemaking will continue
to be treated as such under the standard for confidentiality set forth
in Food Marketing Institute v. Argus Leader Media, 139 S. Ct. 2356
(2019).
[[Page 37026]]
B. Proposed Confidentiality Determinations and Emissions Data
Designations
1. Proposed Approach
The EPA's past approach for evaluating reporting requirements for
confidentiality was established in the 2011 Final CBI Rule (76 FR
30782, May 26, 2011). This approach was based on the requirements of 40
CFR part 2, which included an assessment of whether disclosure of the
data would cause a likelihood of substantial competitive harm. As set
forth in the 2011 Final CBI Rule, the EPA categorized all reporting
requirements into 22 data categories and reviewed them for
confidentiality as follows:
12 data categories were established and designated as
either ``CBI'' or ``not CBI'' (hereafter referred to as ``categorical
confidentiality determinations''), and all data elements assigned to
one of these 12 data categories were also assigned the confidentiality
determination of ``CBI'' or ``not CBI'' for that category;
5 data categories were established that were not assigned
any categorical confidentiality determinations; instead, for each data
element in these categories, the EPA made individual determinations
through rulemaking for each data element;
4 data categories were established and designated as
``emission data'' (as defined in 40 CFR 2.301(a)(2)(i)) and all data
elements assigned to these four data categories were assigned a
categorical designation of ``emission data,'' which under CAA section
114 are not entitled to confidential treatment; \167\ therefore, no
data assigned to these four categories were further evaluated for
confidentiality; and
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\167\ See section I.C of the preamble for the July 7, 2010 CBI
proposal (75 FR 39094, July 7, 2010) for further discussion of CAA
section 114 requirements. The term ``emission data'' is defined at
40 CFR 2.301(a)(2)(i).
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1 data category, ``Inputs to Emission Equations,'' was
proposed on July 7, 2010 (75 FR 39094) to be ``emissions data.''
Evaluation of data elements assigned to this data category was first
conducted in the October 24, 2014 final rule (79 FR 63750). Refer to
section VI.C of this preamble for further discussion of the EPA's
evaluation and treatment of data assigned to the ``Inputs to Emission
Equations'' data category.
Since the 2011 Final CBI Rule, we have followed the approach
outlined above in all rulemakings for evaluating reporting requirements
for confidentiality. However, in this document we are proposing to
revise our approach to assessing data for confidentiality in response
to Food Marketing Institute v. Argus Leader Media, 139 S. Ct. 2356
(2019) (hereafter referred to as Argus Leader).\168\ In Argus Leader,
the U.S. Supreme Court issued an opinion addressing the meaning of the
word ``confidential'' in Exemption 4 of the Freedom of Information Act,
5 U.S.C. Section 552(b)(4)(2012 and Supp. V. 2017) stating that
``confidential'' must be given its ``ordinary'' meaning, which is
information that is ``private'' or ``secret.'' As a result, starting
with the date of the Argus Leader ruling, the EPA no longer assesses
data elements using the rationale of whether disclosure will cause a
likelihood of substantial competitive harm when making confidentiality
determinations. Instead, the EPA assesses whether the information is
customarily and actually treated as private by the reporter and whether
the EPA has given an assurance at the time the information was
submitted that the information will be kept confidential or not
confidential.
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\168\ Available in the docket for this rulemaking (Docket Id.
No. EPA-HQ-OAR-2019-0424).
---------------------------------------------------------------------------
We are proposing that the Argus Leader decision does not impact our
approach to designating data elements as ``inputs to emission
equations'' or our previous approach for designating new and revised
reporting requirements as ``emission data.'' For a discussion of the
EPA's rationale for why the Argus Leader decision does not impact our
previous approach for handling ``inputs to emission equations,'' refer
to section VI.C of this preamble. The Argus Leader decision does not
apply to data elements designated as ``emission data,'' because section
114(c) of the CAA precludes ``emission data'' from being considered
confidential and requires that such data be available to the public.
Therefore, the Argus Leader decision does not impact our previous
approach for designating new and revised reporting requirements as
``emission data.'' 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) \169\ (hereafter referred to
as ``emission data categories''). As discussed in section II.B of the
July 7, 2010 proposal (75 FR 39100), the four emission data categories
include the following categories of data reported by direct emitters
(i.e., ``emission data'' does not apply to suppliers reporting under
the GHGRP as discussed in section II.C.2 of the preamble for the 2011
Final CBI Rule (76 FR 30782, May 26, 2011)):
---------------------------------------------------------------------------
\169\ 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).''
---------------------------------------------------------------------------
Category 1: Facility and Unit Identifier Information;
Category 2: Emissions;
Category 3: Calculation Methodology and Methodological
Tier; and
Category 4: Data Elements Reported for Periods of Missing
Data that are Not Inputs to Emission Equations.
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.'' Note that the
proposed ``emission data'' designations discussed in section VI.B.2 of
this preamble involve assignment to only the first three emission data
categories in the bulleted list above (i.e., we are not proposing that
any reported elements be assigned to the ``Data Elements Reported for
Periods of Missing Data that are Not Inputs to Emission Equations''
data category).
For reporting elements that the EPA does not designate as
``emission data'' or ``inputs to emission equations,'' the EPA is
proposing a revised approach for assessing data confidentiality. We
propose to assess each individual reporting element according to the
Argus Leader criteria (i.e., whether the information is customarily and
actually treated as private by the reporter); therefore, we are not
proposing to assign the data elements to any data category established
by the 2011 Final CBI Rule. Refer to section VI.B.2 of this preamble
for further discussion of the EPA's evaluation of data elements
according to the Argus Leader criteria and proposed confidentiality
determinations.
2. Proposed Confidentiality Determinations and ``Emission Data''
Designations
In this section, we discuss the proposed confidentiality
determinations
[[Page 37027]]
and ``emission data'' designations for: (1) 283 new or substantially
revised data elements, (2) 33 existing data elements (i.e., not
proposed to be substantially revised) for which we have not previously
finalized a confidentiality determination or ``emission data''
designation, and (3) 33 existing data elements for which we are
amending an existing confidentiality determination. We are also
clarifying 12 previous confidentiality determinations, as discussed in
section VI.B.2.d of this preamble.
Further, we are confirming that, except for the specific situations
discussed in sections VI.B.2.c and VI.D of this preamble, the data
elements previously determined to be entitled to confidential treatment
in the following rulemakings will continue to be treated as such under
the new confidentiality standard set forth in Argus Leader:
2011 Final CBI Rule;
77 FR 48072, August 13, 2012;
78 FR 68162; November 13, 2013;
78 FR 69337, November 29, 2013;
79 FR 63750, October 24, 2014;
79 FR 70352, November 25, 2014;
79 FR 73750, December 11, 2014;
80 FR 64262, October 22, 2015;
81 FR 86490, November 30, 2016; and
81 FR 89188, December 9, 2016.
a. Proposed Confidentiality Determinations and ``Emission Data''
Designations for New or Substantially Revised Data Reporting Elements
For the 283 new and substantially revised data elements, the EPA is
proposing ``emission data'' designations for 90 data elements and
confidentiality determinations for 193 data elements. The EPA is
proposing to designate 90 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 VI.B.1 of this preamble), as follows:
44 data elements that are proposed to be reported under
subparts G, P, S, W, and VV are proposed to be assigned to the
``Emissions'' emission data category;
25 data elements that are proposed to be reported under
subparts C, Q, and W are proposed to be assigned to the ``Facility and
Unit Identifier Information'' emission data category; and
21 data elements that are proposed to be reported under
subparts I, W, and SS 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, available in
the docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424),
for a list of these 88 specific data elements proposed to be designated
as ``emission data,'' the proposed emission data category assignments
for each data element, and the EPA's rationales for the proposed
emission data category assignments.
The remaining 193 new and substantially revised data elements not
proposed to be designated as ``emission data,'' or ``inputs to emission
equations,'' are proposed to be reported under subparts H, N, Q, S, W,
X, Y, BB, DD, GG, HH, OO, PP, SS, and VV. This proposal assesses each
individual reporting element according to the Argus Leader criteria as
discussed in section VI.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, to see a list of these 193 specific data elements
with this status receiving a determination, the proposed
confidentiality determination for each data element, and the EPA's
rationales for the proposed confidentiality determinations.
b. Proposed Confidentiality Determinations and ``Emission Data''
Designations for Existing Part 98 Data Reporting Elements for Which No
Determination Has Been Previously Established
We are also proposing confidentiality determinations and ``emission
data'' designations for 33 data elements currently in subparts A, I, K,
W, and HH for which no confidentiality determination or ``emission
data'' designation has been previously finalized under part 98. We
reviewed previous rulemakings and found the following instances where a
confidentiality determination or ``emission data'' designation had not
been made:
For subparts A, K, and HH, three data elements were added
in the 2009 Final Rule following public comment. The EPA did not make
confidentiality determinations in that rulemaking and has not finalized
determinations for these data elements in subsequent rulemakings.
Also for subpart A, one data element was added in the
August 13, 2012 rulemaking (77 FR 48072) following public comment. The
EPA did not make a confidentiality determination in that rulemaking and
has not finalized a determination for the data element in a subsequent
rulemaking.
For subpart I, one data element was added in the final
rulemaking published on August 13, 2012 (77 FR 48072), and one data
element was revised in the final rulemaking published on November 13,
2013 (78 FR 68162). For the data element added on August 13, 2012, the
EPA had not proposed a confidentiality determination and, therefore,
did not finalize a determination in the final rule. For the data
element revised on November 13, 2013, the EPA retained a previous
decision for the previous version of the data element not to assign a
confidentiality determination to the data element (see the final
rulemaking on August 13, 2012, 77 FR 48072). Since the EPA did not
evaluate either data element for confidentiality in those two
rulemakings or in subsequent rulemakings, the EPA has not previously
finalized a confidentiality determination for the data element.
Also for subpart A, one data element was added in the
final rulemaking published on December 11, 2014 (79 FR 73750) following
public comment. The EPA had not proposed a confidentiality
determination or ``emission data'' designation for the data element and
therefore did not finalize confidentiality determinations in the final
rule.
For Subpart W, 21 data elements were added or
substantially revised in the final rulemaking published on November 25,
2014 (79 FR 70352) following public comment. Additionally, 5 data
elements were added in the final rulemaking published on October 22,
2015 (80 FR 64242) following public comment. The EPA had not proposed a
confidentiality determination or ``emission data'' designation for
these new or revised data elements, and therefore did not finalize
confidentiality determinations in the final rules.
Of these 33 data elements, we propose to designate 26 data elements
as ``emission data'' and therefore they would not be entitled to
confidential treatment by assigning the data elements to three emission
data categories (established in the 2011 Final CBI Rule as discussed in
section VI.B.1 of this preamble), as follows:
11 data elements in subparts A and W are proposed to be
assigned to the ``Emissions'' emission data category;
14 data elements in subparts A and W are proposed to be
assigned to the
[[Page 37028]]
``Facility and Unit Identifier Information'' emission data category;
and
1 data element in subpart I is proposed to be assigned to
the ``Calculation Methodology and Methodological Tier'' emission data
category.
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, available in
the docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424),
for a list of these 26 specific 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 the proposed
emission data category assignments.
For the remaining 7 existing reported data elements in subparts A,
I, K, W, and HH for which no confidentiality determination or
``emission data'' designation has been previously finalized under part
98, we propose to assess each individual data element according to the
Argus Leader criteria as discussed in section VI.B.1 of this preamble.
Refer to Table 4 in the memorandum, Proposed Confidentiality
Determinations and Emission Data Designations for Data Elements in
Proposed Revisions to the Greenhouse Gas Reporting Rule (available in
the docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424),
for a list of each of these seven specific data elements with this
status receiving a determination, the proposed confidentiality
determination for each data element, and the EPA's rationales for the
proposed confidentiality determinations.
c. Proposed Confidentiality Determinations for Existing Part 98 Data
Reporting Elements for Which a Previous Determination Is Proposed To Be
Amended
We are proposing to amend the confidentiality determinations
previously finalized under part 98 for five existing data elements in
subpart A, 16 data elements in subpart RR, and 12 data elements in
subpart UU. In amending the confidentiality determinations, we propose
to evaluate each individual data element according to the Argus Leader
criteria as discussed in section VI.B.1 of this preamble. Three of
these data elements from subpart A (40 CFR 98.3(c)(5)(ii)(A) through
(C)) were added to subpart A in the December 9, 2016 rulemaking (81 FR
89188). The EPA finalized confidentiality determinations for these
three data elements in that rule. We are now proposing to amend those
finalized confidentiality determinations from ``emissions data'' to
``not CBI'' for the data reported by suppliers under subpart OO. We are
amending the previous determinations, because no data reported by
suppliers meet the definition of ``emission data'' for the purposes of
the GHGRP.\170\ Two more data elements from subpart A (40 CFR
98.3(c)(5)(ii)) for both subparts LL and MM) were added to subpart A in
the 2009 Final Rule. The EPA finalized confidentiality determinations
for the data elements in the 2011 Final CBI Rule (76 FR 30782). We are
proposing to amend the existing determinations because those
determinations did not take into account situations where the data may
already be publicly available.
---------------------------------------------------------------------------
\170\ See section II.C.2 of the preamble for the 2011 Final CBI
Rule (76 FR 30782, May 26, 2011) for further discussion of the EPA's
determination that the supplier data elements do not meet the
definition of emission data.
---------------------------------------------------------------------------
With respect to subparts RR and UU, we are proposing to amend the
confidentiality determinations for 16 data elements in subpart RR where
previously no categorical CBI determinations were made and for 12 data
elements in subpart UU where the EPA previously determined the data
elements to be CBI. More specifically, we are proposing to change the
confidentiality determinations for the 16 Subpart RR and 12 subpart UU
data elements to ``Not CBI'' consistent with the Argus Leader criteria.
Subpart RR and UU reporters must report the quantities of
CO2 received at the custody transfer meter. Subpart RR
reporters must also report the quantities of CO2 produced at
the separator flow meter if they are actively producing oil or natural
gas or any other fluids. The EPA originally proposed that the
quantities of CO2 received and CO2 produced
including the mass and volumetric flow and CO2
concentrations used to calculate these values would not be CBI (77 FR
1434, January 10, 2012). Following review of public comment, however,
the EPA in its final rulemaking (77 FR 48072, August 13, 2012)
determined that the quantities of CO2 received and
CO2 produced could contain sensitive information for some
facilities that report under subparts RR and UU, thus presenting the
potential for competitive harm to the submitter if the information was
released. At the time, the EPA was not aware that this information
could be found publicly. The EPA, therefore, made categorical
determinations of ``CBI'' for the 12 subpart UU data elements and did
not make categorical determinations for the 16 subpart RR data
elements.
We have revisited the original confidentiality determinations for
these data elements under the Argus Leader standard and have determined
that the EPA's original basis for the confidentiality determinations is
not valid. The EPA has now determined that company and facility-level
data for CO2 received and CO2 produced are often
available to the public through company websites and annual reports,
company filings with the Securities and Exchange Commission,
presentations at conferences and other events, and third-party
analyses. In addition, oil and gas production to the well level is
reported to state oil and gas commissions and is widely available to
the public through the commission websites and records as well as
through third parties. General rules-of-thumb for the quantity of
CO2 required to produce a barrel of oil are often used in
the oil and gas industry to estimate CO2 quantities received
and injected. Since the EPA has now found that this information is
largely publicly available, we are determining in the proposed rule
that the quantities of CO2 received and CO2
produced submitted under subparts RR and UU cannot be entitled to
confidential treatment under the standard set forth by the Argus Leader
decision.
Refer to Table 5 in the memorandum, Proposed Confidentiality
Determinations and Emission Data Designations for Data Elements in
Proposed Revisions to the Greenhouse Gas Reporting Rule, available in
the docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424)
for a list of each of the 33 data elements with this status receiving a
determination, the proposed confidentiality determination for each data
element, and the Agency's rationale for each proposed determination.
d. Clarification of Previous Confidentiality Determinations
We are clarifying the confidentiality determinations previously
finalized under 40 CFR part 98 for 12 data elements currently in
subparts A, LL (Suppliers of Coal-based Liquid Fuels), MM (Suppliers of
Petroleum Productions), and NN. These 12 data elements were added in
the 2009 Final Rule, and confidentiality determinations were finalized
in the 2011 Final CBI Rule (76 FR 30782). For these 12 data elements,
there were discrepancies regarding the finalized confidentiality
determinations in the 2011 Final CBI Rule (76 FR 30782) between the
confidentiality determination specified in the preamble to the final
rule and the
[[Page 37029]]
confidentiality determination specified in the April 29, 2011
memorandum to the rulemaking.\171\ We are clarifying which explanation
of the Agency's confidentiality determination for each of the 12 data
elements was correct, and we are providing explanations for the
discrepancies between the determination specified in the preamble to
the final rule and the supporting memorandum. These clarifications do
not change the EPA's treatment of these 12 data elements; the
confidentiality determinations being clarified are consistent with how
the EPA has treated these reported data since promulgation of the May
26, 2011 final rule. This clarification will be effective for all
previous and future reporting years. However, due to the conflict in
the previous rules, we are providing a new opportunity to comment on
the Agency's treatment of these data. Refer to Table 6 in the
memorandum, Proposed Confidentiality Determinations and Emission Data
Designations for Data Elements in Proposed Revisions to the Greenhouse
Gas Reporting Rule, available in the docket for this rulemaking (Docket
Id. No. EPA-HQ-OAR-2019-0424), for a list of the 12 data elements with
this status, the clarified confidentiality determinations for each data
element, and an explanation of the discrepancy in the documentation of
their confidentiality determinations.
---------------------------------------------------------------------------
\171\ See April 29, 2011 memorandum ``Final Data Category
Assignments and Confidentiality Determinations for Part 98 Reporting
Elements,'' available in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
C. Proposed Reporting Determinations for Inputs to Emission Equations
As discussed in section I.C of the preamble to the October 24, 2014
rule (79 FR 63750), the EPA organizes data assigned to the ``Inputs to
Emission Equations'' data category into two subcategories. The first
subcategory includes ``inputs to emission equations'' entered into e-
GGRT's Inputs Verification Tool (IVT). These ``inputs to emission
equations'' are entered into IVT to satisfy the EPA's verification
requirements. These data must be maintained as 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 ``inputs to emission equations'' meet the criteria
necessary for them to be entered into the IVT system. The second
subcategory includes ``inputs to emission equations'' that must be
included in the annual report submitted to the EPA. This is done in
circumstances where the EPA has determined that the data elements
assigned to the ``Inputs to Emission Equations'' category 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 held as confidential.
As stated in section VI.B.1 of this preamble, the EPA is
determining that the Argus Leader decision does not impact our approach
for handling of data elements assigned to the ``Inputs to Emission
Equations'' data category. Data assigned to this data category and
subcategorized by the Agency as ``inputs to emission equations''
entered into IVT do not become federal records for the purposes of part
98 reporting, so no confidentiality determination needs to be made for
data elements determined to fall within this subcategory of data. Since
this subcategory of data is only entered into the IVT system and not in
the annual report sent directly to the EPA, the Argus Leader decision
does not affect the approach to these data or the criteria the Agency
uses to determine whether these data should be considered to fall
within this subcategory. Likewise, for the same reason, the Argus
Leader decision does not impact actions in previous rulemakings
designating certain data as ``inputs to emission equations'' to be
entered into the IVT system.
In continuation of this past approach, we are proposing to assign
125 new or substantially revised data elements in subparts I, W, DD,
and SS to the ``Inputs to Emission Equations'' data category. Based on
our evaluation of each data element assigned to the ``Inputs to
Emission Equations'' data category, we determined that none of these
125 evaluated data meet the criteria necessary for them to be entered
into the IVT system; therefore, we propose that all 125 of these data
elements be reported to the EPA and would be considered ``emission
data.'' These ``inputs to emission equations'' once received by the EPA
would not qualify to be held as confidential. 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, available in the docket
for this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424) for a list of
the 125 data elements proposed to be reported that are being designated
as ``inputs to emission equations,'' and the EPA's rationale for the
proposed reporting determinations. The table also includes a discussion
of the criteria that we established in 2011 for evaluating whether data
assigned to the ``Inputs to Emission Equations'' data category should
be entered into the IVT system. In our evaluation we found that even if
the 2011 criteria were based on the standard for confidential treatment
set forth in the Supreme Court's 2019 Argus Leader decision, it would
not impact our determination that these 125 data elements should be
directly reported to EPA instead of entered into IVT.
Note that this proposal also includes proposed revisions to
calculation methodologies in direct emitter subparts G, P, S, and Y
that would require reporters under these subparts to enter new or
substantially revised ``inputs to emission equations'' in IVT. These
new and substantially revised data elements are not proposed to be
included in the reporting section of those subparts but would instead
be retained as records. Since the EPA is not proposing to include these
data in the annual report, the data elements are not included in the
evaluation discussed in this section. Refer to section III of this
preamble for discussion of all proposed revisions to the recordkeeping
sections of subparts G, P, S, and Y.
D. Proposed Revision to Confidentiality Determinations for Existing 40
CFR Part 98 Data Elements Affected by the AIM Implementation Rule
On October 5, 2021, the EPA finalized the AIM Implementation Rule
(86 FR 55116), which establishes a program to phase down
hydrofluorocarbon production and consumption (hereafter referred to as
the ``AIM Act'') at 40 CFR part 84 (hereafter referred to as ``Part
84''). There are cases where similar or identical data will be
collected under both the AIM Act under Part 84 and the GHGRP under part
98. For some of these overlapping data, the EPA had previously
determined under part 98 that the data would be treated as confidential
when collected under the GHGRP. However, pursuant to the AIM Act, the
EPA subsequently determined that the overlapping data elements
collected under the AIM Act would not be provided confidential
treatment. Refer to section X.C of the AIM Implementation Rule for the
Agency's rationale for these determinations (86 FR 55191).
Specifically, the AIM Implementation Rule determined that 12 data
elements would not be eligible for confidential treatment when reported
under the AIM Act where the data had previously been determined to be
entitled to confidential treatment under the GHGRP.
To align the GHGRP with the AIM Act, we are proposing to amend the
confidentiality determinations made
[[Page 37030]]
under the GHGRP for these 12 overlapping data elements. As these 12
data elements are not eligible for confidential treatment and will be
publicly released under the AIM Act, there is no basis for treating the
data as confidential under the GHGRP. Therefore, we are proposing that
the data no longer be entitled to confidential treatment when reported
under the GHGRP. We are proposing to amend the confidentiality
determinations for these 12 overlapping data elements for only those
reporting years that the data are collected under the AIM Act and only
those GHGs covered by the AIM Act. First, regarding the reporting
years, the EPA has been collecting many of these 12 data elements under
the GHGRP since 2010, whereas the EPA will only begin collecting data
under the AIM Act for activities beginning in 2022. Therefore, we are
not proposing to amend the confidentiality determinations for any years
prior to 2022 that the data were collected under the GHGRP. Instead, we
propose to amend the part 98 confidentiality determinations
prospectively, such that these 12 data elements would not be treated as
confidential for the annual reports covering RY2022 and future years.
Second, regarding GHGs, the AIM Act requires reporting of 18 GHGs,
whereas the GHGRP covers a much broader set of GHGs. We are proposing
to amend the part 98 confidentiality determinations for these 12 data
elements only for reported data associated with the exact GHGs covered
under the AIM Act as listed in appendix A of part 84.
The 12 overlapping data elements for which we are proposing to
amend the confidentiality determination include data elements currently
reported under subparts A and OO of part 98. A list of these 12
affected data elements and the proposed determinations are specifically
listed in Table 1 in the memorandum titled Proposed Determinations that
would Align the Greenhouse Gas Reporting Program with the
Determinations Made under the AIM Act Regulations available in the
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
The AIM Implementation Rule also included one HFC data element to
be used in the administration of the AIM Act that is only reported
under part 98 but not under the AIM Act, specifically under 40 CFR
98.416(a). This data element is ``Annual quantities of fluorinated
greenhouse gases [other than HFCs regulated under the AIM Act],
identified by type, intentionally produced on a facility line that also
produces HFC[hyphen]23.'' \172\ The Agency will invoke the modification
provisions of 40 CFR 2.301(d)(4) to make an individual determination on
this specific data element. Once that process is completed, the Agency
may make a conforming change to the confidentiality determination for
that data category in the final version of this rulemaking. Note that
the determination affects only fluorinated greenhouse gases that are
produced on a facility line that also produces HFC-23.
---------------------------------------------------------------------------
\172\ See pg. 12 of ``Memorandum--Classification of Data
Reported Under the HFC Phasedown Rule'' available at Docket Id. No.
EPA-HQ-OAR-2021-0044-0227 and in the docket to for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
E. Request for Comments on Proposed Category Assignments,
Confidentiality Determinations, or Reporting Determinations
By proposing confidentiality determinations prior to data reporting
through this proposal and rulemaking process, we provide potential
reporters an opportunity to submit comments, particularly comments
identifying data elements proposed by the Agency to be ``not CBI'' that
reporters consider to be customarily and actually treated as private.
Likewise, we provide potential reporters an opportunity to submit
comments on whether there are disclosure concerns for ``inputs to
emission equations'' that we propose would be included in the annual
reports and subsequently released by the EPA. This opportunity to
submit comments is intended to provide reporters with the opportunity
that is 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 rulemaking
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 data.
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 be not 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), 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),
[[Page 37031]]
publisher, publication date, and International Standard Book Number
(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, under subpart FF, we are proposing to revise a
data element to clarify the term ``Mine Safety and Health
Administration (MSHA) number'' to be ``Mine Safety and Health
Administration (MSHA) identification number'' (see 40 CFR 98.246(t)).
This proposed change would not impact the data collected, 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 impact 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 impact the previous confidentiality determination or
reporting determination.
VII. Impacts of the Proposed Amendments
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 to understand new source
categories or new emission sources for specific sectors 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 would
result in an overall increase in burden for reporters. The proposed
revisions would increase burden in cases where the proposed amendments
add or revise reporting requirements or require additional emissions
data to be reported. We anticipate a decrease in burden where the
proposed revisions would adjust or improve the estimation methodologies
for determining applicability, simplify calculation methodologies or
monitoring requirements, or simplify the data that must be reported. In
several cases, we are proposing changes where we anticipate increased
clarity or more flexibility for reporters that could result in a
potential decrease in burden, but we are unable to quantify this
decrease.
As discussed in section V of this preamble, we are proposing to
implement these changes for RY2023 reports. Costs have been estimated
over the three years following the year of implementation. The
incremental implementation costs for all subparts for each reporting
year are summarized in Table 6 of this preamble. The estimated annual
average labor burden is $1,417,494 per year. The incremental burden by
subpart is shown in Table 6 of this preamble.
Table 6--Total Incremental Labor Burden for Reporting Years 2023-2025
[$2017/year]
----------------------------------------------------------------------------------------------------------------
Cost summary RY2023 RY2024 RY2025 Annual average
----------------------------------------------------------------------------------------------------------------
Burden by Year (all subparts)................... $1,417,591 $1,416,802 $1,418,090 $1,417,494
----------------------------------------------------------------------------------------------------------------
There is an additional annual incremental burden of $7,281 for
capital and operation and maintenance (O&M) costs, which reflects
changes to applicability and monitoring for subparts I, P, W, UU, and
VV. Including capital and O&M costs, the total annual average burden is
$1,424,775 over the next 3 years.
The incremental burden by subpart is shown in Table 7 of this
preamble. Note that subparts with proposed revisions that would not
result in any changes to burden (e.g., subparts FF and NN) are excluded
from this table.
Table 7--Total Incremental Burden by Subpart
[$2017/year] \a\
----------------------------------------------------------------------------------------------------------------
Labor costs
-------------------------------- Capital and
Subpart Subsequent O&M
Initial year years
----------------------------------------------------------------------------------------------------------------
C--General Stationary Fuel Combustion Sources
Facilities Reporting only to Subpart C.......................... $70,732 $70,732
Facilities Reporting to Subpart C plus another subpart.......... 94,999 94,999
G--Ammonia Manufacturing........................................ 250 250
H--Cement Production............................................ 3,655 3,655
I--Electronics Manufacturing \b\................................ 19,056 17,839 $50
[[Page 37032]]
N--Glass Production............................................. 818 818
P--Hydrogen Production.......................................... 628 628 (1,536)
Q--Iron and Steel Production.................................... 1,454 1,454
S--Lime Manufacturing........................................... 1,351 1,351
W--Petroleum and Natural Gas Systems............................ 1,211,076 1,211,076 8,667
X--Petrochemical Production..................................... 528 528
Y--Petroleum Refineries......................................... 801 801
BB--Silicon Carbide Production.................................. 20 20
DD--Electrical Equipment Use.................................... 7,106 7,106
GG--Zinc Production............................................. 20 20
HH--Municipal Solid Waste Landfills............................. 3,297 3,297
OO--Suppliers of Industrial Greenhouse Gases.................... 810 810
PP--Suppliers of Carbon Dioxide................................. 629 629
SS--Electrical Equipment Manufacture or Refurbishment........... 338 338
UU \c\.......................................................... (1,831) (1,831) (100)
VV \d\.......................................................... 1,833 3,355 200
-----------------------------------------------
Total \e\................................................... 1,417,591 1,417,446 7,281
----------------------------------------------------------------------------------------------------------------
\a\ Includes estimated increase or decrease in costs following implementation of revisions in RY2023.
\b\ Average subsequent year labor costs for Subpart I. Subpart I subsequent year costs include $17,252 in Year 2
and $17,526 in Year 3.
\c\ Annual burden includes labor costs and annual O&M savings for two reporters who will begin submitting
reports under proposed subpart VV in each year.
\d\ Subsequent year labor costs include $2,848 in Year 2 and $3,862 in Year 3. O&M costs are based on $100 in
Year 1, $200 in Year 2, and $300 in Year 3.
\e\ Subsequent year labor costs include $1,416,802 in Year 2 and $1,418,090 in Year 3.
A full discussion of the cost and emission impacts 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-2019-0424.
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is a significant regulatory action that was submitted
to the OMB for review. This action involves proposed amendments that
raise novel legal or policy issues. Any changes made in response to OMB
recommendations have been documented in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424.
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 EPA ICR number 2300.19. You can
find a copy of the ICR in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2019-0424, and it is briefly summarized here.
The EPA does not anticipate that the proposed amendments would
result in substantial burden, based on the changes to the reporting
requirements, in any of the subparts for which amendments are being
proposed. In many cases, the proposed amendments to the requirements
would reduce the reporting burden by clarifying or improving the
estimation methodologies for determining applicability, simplifying
calculation methodologies or providing flexibility for monitoring
requirements, or simplifying the data that must be reported. The
estimated annual average burden is 16,366 hours and $1,424,775 over the
3 years covered by this information collection. The burden costs
include $1,424,772 from revisions implemented in the first year,
$1,424,082 from revisions implemented in the second year, and
$1,425,471 from revisions implemented in the third year. Further
information on the EPA's assessment on the impact on burden can be
found in the memorandum, Assessment of Burden Impacts for Proposed
Revisions for the Greenhouse Gas Reporting Rule in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
Respondents/affected entities: Owners and operators of facilities
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 section 114.
Estimated number of respondents: 10,041 (affected by proposed
amendments).
Frequency of response: Annually.
Total estimated burden: 16,366 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $1,424,775, includes $7,281 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 rule. The EPA will respond to any ICR-related
comments in the final rule. 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
[[Page 37033]]
collection by selecting ``Currently under Review--Open for Public
Comments'' or by using the search function. OMB must receive comments
no later than August 22, 2022.
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 across all sectors encompassed by the rule, small
governmental jurisdictions and small non-profits. In the development of
40 CFR part 98, the EPA determined that some small businesses are
affected because their production processes emit GHGs that must be
reported, because they have stationary combustion units on site that
emit GHGs that must be reported, or because they have fuel supplier
operations for which supply quantities and GHG data must be reported.
Small governments and small non-profits are generally affected because
they have regulated landfills or stationary combustion units on site,
or because they own an LDC. In the promulgation of the rule, the EPA
took several steps to reduce the impact on small entities. For example,
the EPA determined appropriate thresholds that reduced the number of
small businesses reporting. In addition, the EPA conducted several
meetings with industry associations to discuss regulatory options and
the corresponding burden on industry, such as recordkeeping and
reporting. Except as discussed below, the proposed revisions would not
revise these thresholds for existing subparts, therefore, we do not
expect any additional small entities will be impacted under the
proposed rule revisions. The proposed rule amendments predominantly
apply to existing reporters and are amendments that would improve the
existing emissions estimation methodologies; implement requirements to
collect additional data to understand new source categories or
emissions sources; improve the EPA's understanding of the sector-
specific processes or other factors that influence GHG emission rates
and improve verification of collected data; and provide additional data
to complement or inform other EPA programs under the CAA and to more
broadly inform climate programs and policies. We are also proposing
revisions that clarify or update provisions that have been unclear, or
that streamline or simplify requirements, for example, by increasing
flexibility for reporters or removing redundant requirements. In
general, these changes are improvements or clarifications of
requirements that do not require new data monitoring and would not
significantly increase reporter burden, or are changes that require
data that is readily available and may be obtained from company records
or estimated from existing inputs or data elements already collected
under part 98.
In evaluating the impacts of the proposed revisions, we assessed
the costs and impacts to small entities in three areas, including
revisions to subpart applicability, changes to existing monitoring or
calculation methodologies, and revisions to reporting and recordkeeping
requirements for data provided to the program. First, we evaluated the
costs to entities who may be affected by changes to applicability. In
general, this is the area that would be most likely to have greater
impacts, as facilities assume substantially higher cost when they
become newly applicable to the full set of requirements under part 98
versus the costs associated with an incremental change in an existing
requirement. Only the proposed revisions to applicability to subpart I
(discussed in section III.E.2 of this preamble) are anticipated to
potentially impact new reporters that have not previously reported to
the GHGRP. The SBA size standard for facilities falling under the NAICS
code 334413 (Semiconductor and Related Device Manufacturing) is 1,250
employees. In the subpart I initial promulgation package, we originally
assessed the impact of complying with subpart I requirements on all
small entities by calculating a cost-to-sales ratio for six enterprise
size ranges using the average total annualized reporting costs to the
average annual sales receipts for each establishment (85 FR 74813,
December 1, 2010). Based on this analysis, the cost-to-sales ratio for
all entity sizes except for the smallest sized enterprises (1 to 20
employee range) was less than one percent. The EPA further concluded
that although the cost-to-sales ratio for the 1 to 20 employee range
for semiconductor and related device manufacturing was greater than one
percent (i.e., 1.16 percent); facilities with emissions greater than
25,000 mtCO2e per year are unlikely to be included in the 1
to 20 employees size category. Under this proposed action, we estimate
there is one (1) affected facility that does not currently report under
the GHGRP that may be required to report. The affected facility is
included in the 100 to 499 employee range. Although the affected
facility meets the SBA size standard for a small business and would
potentially incur costs from becoming newly subject the GHGRP ($18,736
in the first year and $17,032 in subsequent years), the costs-to-sales
ratio for a facility in this size range would be anticipated to be less
than 0.10%. Therefore, we have determined there would not be a
significant economic impact on a substantial number of small entities
from the proposed revisions to subpart I.
Next, we evaluated the costs and impacts to small entities
associated with revisions to monitoring and calculation methodologies
to each subpart. For those subparts where the EPA is proposing
revisions to update or streamline monitoring and calculation
methodologies (i.e., subparts C, G, I, P, and S), we estimate no change
or a decrease in burden; therefore, there would be no significant
economic impacts on small entities from these proposed revisions. For a
subset of subpart W reporters, the proposed monitoring revisions would
result in a modest increase in labor costs of $430 per affected
reporter, and $12 operation and maintenance costs per reporter.
Detailed small business analyses were performed for subpart W in the
initial promulgation package from 2011 (75 FR 74458, November 30, 2010)
for the eight original industry segments and in the 2015 amendments to
subpart W for three additional industry segments (80 FR 64262, October
22, 2015). Both analyses stated that the rule will not have a
significant economic impact on a substantial number of small entities,
because we concluded that small businesses are unlikely be
impacted.\173\ Furthermore, because the costs associated with the
proposed monitoring revisions are minimal, no significant small entity
impacts are anticipated for facilities subject to the proposed subpart
W amendments. Because the EPA does not foresee an increase in the
number of reporters or any changes in the affected industry
[[Page 37034]]
segments from the proposed revisions, we have determined that the
previous small business analyses still apply and there will not be a
significant economic impact on a substantial number of small entities
from the proposed revisions to monitoring for subpart W.
---------------------------------------------------------------------------
\173\ The original analyses, in section III.D of the 2011
package (75 FR 74458, November 30, 2010), stated, ``smaller
enterprises have very small operations (such as a single family
owning a few production wells) that are unlikely to cross the 25,000
metric tons CO2e reporting threshold.'' The second
analysis, in section IV.B of the preamble to the 2015 proposed
amendments (79 FR 76267; December 9, 2014), stated, ``The petroleum
and natural gas industry has a large number of enterprises, the
majority of them in the 1-20 employee range. However, a large
fraction of production comes from large corporations and not those
with less than 20 employee enterprises. The smaller enterprises in
most cases deal with very small operations (such as a single family
owning a few production wells) that are unlikely to cross the 25,000
metric tons CO2e threshold.''
---------------------------------------------------------------------------
Finally, we evaluated the costs associated with revisions to
recordkeeping and reporting, specifically revisions to the data
elements that are reported in e-GGRT or entered into IVT, for each
subpart (C, G, H, I, N, P, Q, S, W, X, Y, BB, DD, GG, HH, OO, PP, and
SS). Based on the detailed small business analyses performed for each
subpart in the initial promulgation packages (74 FR 56370, October 10,
2009; 75 FR 39738, July 12, 2010; 75 FR 75075, December 1, 2010; and 75
FR 74813, December 1, 2010), the costs associated with the reporting
program are estimated to be less than one percent of sales in all firm
size categories, with the exception of a small number of entities in
the 1 to 20 employee range, which we determined to be unlikely to meet
the regulatory thresholds and unlikely to be covered by the rule. With
the exception of subpart W, the impacts from the proposed revisions to
reporting and recordkeeping in this action for each subpart are less
than $100 per entity, with an average annual burden increase of $46 per
entity. For subpart C reporters, the highest average burden increase is
$44 per facility. Because these costs are minimal, we have determined
that the proposed revisions are unlikely to result in costs exceeding
more than one percent of sales in any firm size category. For subpart
W, the total annual average costs from the proposed revisions to
reporting and recordkeeping are $412 per facility. However, as noted
above in this section, we do not anticipate any small entities are
currently subject to or reporting under subpart W. Further, the
proposed revisions to reporting and recordkeeping under subpart W are
unlikely to result in costs exceeding more than one percent of sales in
any firm size category. Therefore, we have determined there are no
significant economic impacts for any potential small entities subject
to the revisions to reporting or recordkeeping requirements.
We have therefore concluded that this proposed action will have no
significant regulatory burden for any directly regulated small entities
and thus that this proposed action would not have a significant
economic impact on a substantial number of small entities. Details of
this analysis are presented 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-
2019-0424. 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.
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
implements mandate(s) specifically and explicitly set forth in CAA
section 114(a)(1) without the exercise of any policy discretion by the
EPA.
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.
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 stationary combustion units, cement production facilities,
landfills, and petroleum and natural gas facilities that may be owned
by tribal governments that emit GHGs. However, it will only have tribal
implications where the tribal entity owns a facility that directly
emits GHGs above threshold levels; therefore, relatively few
(approximately 8) tribal facilities would be affected. This regulation
is not anticipated to impact facilities or suppliers of additional
sectors owned by tribal governments. Further, the proposed rule
amendments are amendments that would improve the existing emissions
estimation methodologies; implement requirements to collect additional
data to understand new source categories or new emission sources for
specific sectors; improve the EPA's understanding of the sector-
specific processes or other factors that influence GHG emission rates
and improve verification of collected data; provide additional data to
complement or inform other EPA programs; clarify or update provisions
that have been unclear; or that streamline or simplify requirements. In
general, these changes are improvements or clarifications of
requirements that for the most part would not require new equipment,
sampling, or monitoring, and instead, would only require reporters to
provide data that is readily available and may be obtained from company
records or estimated from existing inputs or data elements already
collected under part 98. Therefore, these proposed changes do not
significantly change the part 98 requirements that may apply to tribal
facilities because they generally do not require new equipment,
sampling, or monitoring, and would not substantially increase reporter
burden, impose significant direct compliance costs for tribal
facilities, or preempt tribal law.
Although few facilities subject to part 98 are likely to be owned
by tribal governments, the EPA previously sought opportunities to
provide information to tribal governments and representatives during
the development of the proposed and final rules for part 98 subparts
that were promulgated on October 30, 2009 (74 FR 52620), July 12, 2010
(75 FR 39736), November 30, 2010 (75 FR 74458), and December 1, 2010
(75 FR 74774 and 75 FR 75076). Consistent with the 2011 EPA Policy on
Consultation and Coordination with Indian Tribes,\174\ the EPA
previously consulted with tribal officials early in the process of
developing part 98 regulations to permit them to have meaningful and
timely input into its development and to provide input on the key
regulatory requirements established for these facilities. A summary of
these consultations is provided in section VIII.F of the preamble to
the final rule published on October 30, 2009 (74 FR 52620), section V.F
of the preamble to the final rule published on July 12, 2010 (75 FR
39736), section IV.F of the preamble to the re-proposal of subpart W
(Petroleum and Natural Gas Systems) published on April 12, 2010 (75 FR
18608), section IV.F of the preambles to the final rules published on
December 1, 2010 (75 FR 74774 and 75 FR 75076). As described in this
section, the proposed rule does not significantly revise the
established regulatory requirements and would not
[[Page 37035]]
substantially change the equipment, monitoring, or reporting activities
conducted by these facilities, or result in other substantial impacts
for tribal facilities.
---------------------------------------------------------------------------
\174\ EPA Policy on Consultation and Coordination with Indian
Tribes, May 4, 2011. Available at: https://www.epa.gov/sites/default/files/2013-08/documents/cons-and-coord-with-indian-tribes-policy.pdf.
---------------------------------------------------------------------------
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 improve
the existing emissions estimation methodologies; implement requirements
to collect additional data to understand new source categories or new
emission sources for specific sectors; improve the EPA's understanding
of factors that influence GHG emission rates; improve verification of
collected data; and provide additional data to complement or inform
other EPA programs. We are also proposing revisions that clarify or
update provisions that have been unclear, or that streamline or
simplify requirements, alleviate burden through revision,
simplification, or removal of certain calculation, monitoring,
recordkeeping, or reporting requirements. In general, these changes
would not substantially impact 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, or
where the EPA has determined that the current determination is no
longer appropriate. These proposed amendments and confidentiality
determinations do not make any changes to the existing monitoring,
calculation, and reporting requirements under part 98 that would affect
the supply, distribution, or use of energy.
I. National Technology Transfer and Advancement Act and 1 CFR Part 51
This action involves technical standards. The EPA proposes to allow
the use of an alternate method, ASTM E415-17, Standard Test Method for
Analysis of Carbon and Low-Alloy Steel by Spark Atomic Emission
Spectrometry (2017), for the purposes of subpart Q (Iron and Steel
Production) monitoring and reporting. The EPA currently allows for the
use of standard methods based on atomic emission spectrometry in other
sections of part 98, including under 40 CFR 98.144(b) where it can be
used to determine the composition of coal, coke, and solid residues
from combustion processes by glass production facilities. Therefore,
the EPA is allowing ASTM E415-17 to be used in subpart Q. ASTM E415-17
uses spark atomic emission vacuum spectrometry to determine 21 alloying
and residual elements in carbon and low-alloy steels. The method is
designed for chill-cast, rolled, and forged specimens. 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 ($50). 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 is also
proposing to add new subpart VV for certain EOR operations that choose
to use the ISO standard designated as CSA/ANSI ISO 27916:2019, Carbon
Dioxide Capture, Transportation and Geological Storage--Carbon Dioxide
Storage Using Enhanced Oil Recovery (CO2-EOR) (2019), as a means of
quantifying geologic sequestration. The method quantifies
CO2 that is stored in association with EOR operations,
focusing on the safe, long-term containment of CO2 within
the EOR complex. CSA/ANSI ISO 27916:2019 identifies and quantifies
CO2 losses (including fugitive emissions) and quantifies the
amount of CO2 stored in association with the CO2-EOR
project. It also shows how allocation rations can be used to account
for the anthropogenic portion of the stored CO2. Anyone may
access the standard on the ANSI/ISO website (https://webstore.ansi.org/SDO/ISO/) for additional information. The standard is available to
everyone at a cost determined by ANSI/ISO ($225). ANSI/ISO also offers
memberships or subscriptions for reduced costs. Because the proposed
standard is optional, the cost of obtaining this standard is not a
significant financial burden. 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 believes 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 affect the level of protection
provided to human health or the environment because it is a rule
addressing information collection and reporting procedures.
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
40 CFR Part 9
Environmental protection, Administrative practice and procedure,
Reporting and recordkeeping requirements
40 CFR Part 98
Environmental protection, Administrative practice and procedure,
Greenhouse gases, Incorporation by reference, Reporting and
recordkeeping requirements, Suppliers.
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 9--OMB APPROVALS UNDER THE PAPERWORK REDUCTION ACT
0
1. The authority citation for part 9 continues to read as follows:
Authority: 7 U.S.C. 135 et seq., 136-136y; 15 U.S.C. 2001, 2003,
2005, 2006, 2601-2671; 21 U.S.C. 331j, 346a, 31 U.S.C. 9701; 33
U.S.C. 1251 et seq., 1311, 1313d, 1314, 1318, 1321, 1326, 1330,
1342, 1344, 1345 (d) and (e), 1361; E.O. 11735, 38 FR 21243, 3 CFR,
[[Page 37036]]
1971-1975 Comp. p. 973; 42 U.S.C. 241, 242b, 243, 246, 300f, 300g,
300g-1, 300g-2, 300g-3, 300g-4, 300g-5, 300g-6, 300j-1, 300j-2,
300j-3, 300j-4, 300j-9, 1857 et seq., 6901-6992k, 7401-7671q, 7542,
9601-9657, 11023, 11048.
0
2. Amend Sec. 9.1 by adding an undesignated center heading and an
entry for ``98.1-98.489'' in numerical order to read as follows:
Sec. 9.1 OMB approvals under the Paperwork Reduction Act.
* * * * *
------------------------------------------------------------------------
OMB control
40 CFR citation No.
------------------------------------------------------------------------
* * * * *
------------------------------------------------------------------------
Mandatory Greenhouse Gas Reporting
------------------------------------------------------------------------
98.1-98.489............................................. 2060-0629
* * * * *
------------------------------------------------------------------------
PART 98--MANDATORY GREENHOUSE GAS REPORTING
0
3. The authority citation for part 98 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart A--General Provision
0
4. 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 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
5. Amend Sec. 98.2 by revising paragraphs (f)(1) and (i)(1) and (2)
and adding paragraph (k) to read as follows:
Sec. 98.2 Who must report?
* * * * *
(f) * * *
(1) Calculate the mass in metric tons per year of CO2,
N2O, each fluorinated GHG, and each fluorinated heat
transfer fluid that is imported and the mass in metric tons per year of
CO2, N2O, each fluorinated GHG, and each
fluorinated heat transfer fluid that is exported during the year.
* * * * *
(i) * * *
(1) If reported CO2e emissions, calculated in accordance
with Sec. 98.3(c)(4)(i), are less than 25,000 metric tons per year for
five consecutive years, then the owner or operator may discontinue
complying with this part provided that the owner or operator submits a
notification to the Administrator that announces the cessation of
reporting and explains the reasons for the reduction in emissions. The
notification shall be submitted no later than March 31 of the year
immediately following the fifth consecutive year of emissions less than
25,000 tons CO2e per year. The owner or operator must
maintain the corresponding records required under Sec. 98.3(g) for
each of the five consecutive years prior to notification of
discontinuation of reporting and retain such records for three years
following the year that reporting was discontinued. The owner or
operator must resume reporting if annual CO2e emissions,
calculated in accordance with paragraph (b)(4) of this section, in any
future calendar year increase to 25,000 metric tons per year or more.
(2) If reported CO2e emissions, calculated in accordance
with Sec. 98.3(c)(4)(i), were less than 15,000 metric tons per year
for three consecutive years, then the owner or operator may discontinue
complying with this part provided that the owner or operator submits a
notification to the Administrator that announces the cessation of
reporting and explains the reasons for the reduction in emissions. The
notification shall be submitted no later than March 31 of the year
immediately following the third consecutive year of emissions less than
15,000 tons CO2e per year. The owner or operator must
maintain the corresponding records required under Sec. 98.3(g) for
each of the three consecutive years and retain such records for three
years prior to notification of discontinuation of reporting following
the year that reporting was discontinued. The owner or operator must
resume reporting if annual CO2e emissions, calculated in
accordance with paragraph (b)(4) of this section, in any future
calendar year increase to 25,000 metric tons CO2e per year
or more.
* * * * *
(k) To calculate GHG quantities for comparison to the 25,000 metric
ton CO2e per year threshold under paragraph (a)(4) of this
section for facilities that destroy fluorinated GHGs or fluorinated
heat transfer fluids, the owner or operator shall calculate the mass in
metric tons per year of CO2e destroyed as described in
paragraphs (k)(1) through (k)(3) of this section.
(1) Calculate the mass in metric tons per year of each fluorinated
GHG or fluorinated heat transfer fluid that is destroyed during the
year.
(2) Convert the mass of each destroyed fluorinated GHG or
fluorinated heat transfer fluid from paragraph (k)(1) of this section
to metric tons of CO2e using Equation A-1 of this section.
(3) Sum the total annual metric tons of CO2e in
paragraph (k)(2) of this section for all destroyed fluorinated GHGs and
destroyed fluorinated heat transfer fluids.
0
6. Amend Sec. 98.3 by revising paragraphs (b)(2) and (h)(4) to read as
follows:
Sec. 98.3 What are the general monitoring, reporting, recordkeeping
and verification requirements of this part?
* * * * *
(b) * * *
(2) For a new facility or supplier that begins operation on or
after January 1, 2010 and becomes subject to the rule in the year that
it becomes operational, report emissions starting the first operating
month and ending on December 31 of that year. Each subsequent annual
report must cover emissions for the calendar year, beginning on January
1 and ending on December 31.
* * * * *
(h) * * *
(4) Notwithstanding paragraphs (h)(1) and (2) of this section, upon
request by the owner or operator, the Administrator may provide
reasonable extensions of the 45-day period for submission of the
revised report or information under paragraphs (h)(1) and (2). If the
Administrator receives a request for extension of the 45-day period, by
email to an address prescribed by the Administrator prior to the
expiration of the 45-day period, the extension request is deemed to be
automatically granted for 30 days. The Administrator may grant an
additional extension beyond the automatic 30-day extension if the owner
or operator submits a request for an additional extension and the
request is received by
[[Page 37037]]
the Administrator prior to the expiration of the automatic 30-day
extension, provided the request demonstrates that it is not practicable
to submit a revised report or information under paragraphs (h)(1) and
(2) within 75 days. The Administrator will approve the extension
request if the request demonstrates to the Administrator's satisfaction
that it is not practicable to collect and process the data needed to
resolve potential reporting errors identified pursuant to paragraph
(h)(1) or (2) within 75 days. The Administrator will only approve an
extension request for a total of 180 days after the initial
notification of a substantive error.
* * * * *
0
7. Amend Sec. 98.4 by revising 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. Within 90 days after any change in the owners and operators of
the facility or supplier (including the addition of a new owner or
operator), the designated representative or any alternate designated
representative shall submit a certificate of representation that is
complete under this section except that such list shall be amended to
reflect the change. If the designated representative or alternate
designated representative determines at any time that an owner or
operator of the facility or supplier is not included in such list and
such exclusion is not the result of a change in the owners and
operators, the designated representative or any alternate designated
representative shall submit, within 90 days of making such
determination, a certificate of representation that is complete under
this section except that such list shall be amended to include such
owner or operator.
* * * * *
(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 and the provisions specified in paragraph (n)(5) of
this section apply to all types of change in owner or operator for such
facilities.
(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), a certificate of representation that is complete
under this section shall be submitted to reflect the new owner or
operator within 90 days after the change in the owner or operator and
according to the procedure specified in paragraph (b) of this section.
If the new owner or operator already had emission sources listed in the
applicable paragraph of Sec. 98.232 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. 98.2(a) and Sec. 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.
(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, a
certificate of representation that is complete under this section shall
be submitted for the acquired facility to reflect the new owner or
operator. 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.
(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 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
listed in the applicable paragraph of Sec. 98.232 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.
(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
[[Page 37038]]
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 listed in the
applicable paragraph of Sec. 98.232 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 facility are sold to
multiple owners or operators, 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 transaction that all of the facility's
emission sources were acquired by multiple 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) Each owner or operator involved in a transaction that results
in a change to the owner or operator of a facility shall, as part of
the acquisition agreement or ownership transfer contract, agree upon
the entity 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. That responsible entity will select a
representative who will submit revisions to annual GHG reports under
Sec. 98.3(h) for that facility. If the selected individual is not the
designated representative for the facility, the individual must be
designated as the alternate designated representative or an agent for
the facility.
0
8. Amend Sec. 98.6 by:
0
a. Revising the definitions for ``Carbon dioxide stream'',
``Dehydrator'', and ``Dehydrator vent emissions;''
0
b. Removing the definition for ``Desiccant'';
0
c. Adding a definition for ``Direct air capture (DAC)'' in alphabetical
order; and
0
d. Revising the definition for ``Vapor recovery system''.
The revisions and addition read follows:
Sec. 98.6 Definitions.
* * * * *
Carbon dioxide stream means carbon dioxide that has been captured
from an emission source (e.g., a power plant or other industrial
facility, captured from ambient air (e.g., direct air capture), or
extracted from a carbon dioxide production well plus incidental
associated substances either derived from the source materials and the
capture process or extracted with the carbon dioxide.
* * * * *
Dehydrator means a device in which a liquid absorbent (e.g.,
ethylene glycol, diethylene glycol, or triethylene glycol) directly
contacts a natural gas stream to absorb water vapor.
Dehydrator vent emissions means natural gas and CO2
released from a natural gas dehydrator system absorbent (typically
glycol) regenerator 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.
* * * * *
Direct air capture (DAC), with respect to a facility, technology,
or system, means that the facility, technology, or system uses carbon
capture equipment to capture carbon dioxide directly from the air.
Direct air capture does not include any facility, technology, or system
that captures carbon dioxide:
(1) That is deliberately released from a naturally occurring
subsurface spring or
(2) Using natural photosynthesis.
* * * * *
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
9. Amend Sec. 98.7 as follows:
0
a. Revise the introductory text;
0
b. In paragraph (c)(1), remove the text ``, incorporation by reference
(IBR)'' and add, in its place, the text ``; IBR'';
0
c. Redesignate paragraph (e)(38) as paragraph (e)(39);
0
d. Add new paragraph (e)(38) and paragraph (g)(6); and
0
e. In addition to the previous amendments to this section, remove the
text ``, IBR'' and add, in its place, the text ``; IBR'' wherever it
appears throughout this section.
The revision and additions read as follows:
Sec. 98.7 What standardized methods are incorporated by reference
into this part?
Certain material is incorporated by reference into this part with
the approval of the Director of the Federal Register under 5 U.S.C.
552(a) and 1 CFR part 51. To enforce any edition other than that
specified in this section, the EPA must publish a document in the
Federal Register and the material must be available to the public. All
approved incorporation by reference (IBR) material is available for
inspection at the EPA and at the National Archives and Records
Administration (NARA). Contact EPA at: EPA Docket Center, Public
Reading Room, EPA WJC West, Room 3334, 1301 Constitution Ave. NW,
Washington, DC; phone: 202-566-1744. For information on the
availability of this material at NARA, email [email protected], or
go to www.archives.gov/federal-register/cfr/ibr-locations.html. The
material may be obtained from the following source(s):
* * * * *
(e) * * *
(38) ASTM E415-17, Standard Test Method for Analysis of Carbon and
Low-Alloy Steel by Spark Atomic Emission Spectrometry; IBR approved for
Sec. 98.174(b).
* * * * *
(g) * * *
(6) CSA/ANSI ISO 27916:19, Carbon dioxide capture, transportation
and geological storage--Carbon dioxide storage using enhanced oil
recovery (CO2-EOR). Edition 1. January 2019; IBR approved
for Sec. Sec. 98.480(a), 98.481(a) and (b), 98.482, 98.483, 98.484,
98.485, 98.486(g), 98.487, 98.488(a)(5), and 98.489.
* * * * *
0
10. Amend table A-1 to subpart A of part 98 by:
0
a. Adding under the heading ``Other Fluorinated Compounds'' the entry
``Carbonyl fluoride'' after the entry ``2-Bromo-2-chloro-1,1,1-
trifluoroethane (Halon-2311/Halothane);''
0
b. Removing the heading ``Fluorinated GHG Group \d\'' and adding in its
place the heading ``Fluorinated GHG Group \e\''
0
c. Revising the entry ``Unsaturated perfluorocarbons (PFCs),
unsaturated HFCs, unsaturated hydrochlorofluorocarbons (HCFCs),
unsaturated halogenated ethers, unsaturated halogenated esters,
fluorinated aldehydes, and fluorinated ketones'' under the revised
heading ``Fluorinated GHG Group; \e\''
0
d. Redesignating footnote ``d'' as footnote ``e;'' and
[[Page 37039]]
0
e. Adding new footnote ``d'' and footnote ``f.''
The additions and revisions read as follows:
* * * * *
Table A-1 to Subpart A of Part 98--Global Warming Potentials
----------------------------------------------------------------------------------------------------------------
Global
warming
Name CAS No. Chemical formula potential
(100 yr.)
----------------------------------------------------------------------------------------------------------------
* * * * * * *
----------------------------------------------------------------------------------------------------------------
Other Fluorinated Compounds
----------------------------------------------------------------------------------------------------------------
* * * * * * *
Carbonyl fluoride............................. 353-50-4 COF2............................ \d\ 0.14
----------------------------------------------------------------------------------------------------------------
Fluorinated GHG Group \e\
----------------------------------------------------------------------------------------------------------------
* * * * * * *
Unsaturated perfluorocarbons (PFCs), unsaturated HFCs, unsaturated hydrochlorofluorocarbons 1
(HCFCs), unsaturated halogenated ethers, unsaturated halogenated esters, unsaturated
bromofluorocarbons, unsaturated chlorofluorocarbons, unsaturated bromochlorofluorocarbons,
unsaturated hydrobromofluorocarbons, unsaturated hydrobromochlorofluorocarbons, fluorinated
aldehydes, and fluorinated ketones \f\
* * * * * * *
----------------------------------------------------------------------------------------------------------------
* * * * *
\d\ This compound was added to Table A-1 in the final rule published on [Date of publication of the final rule
in the Federal Register] and effective on January 1, 2023.
\e\ For electronics manufacturing (as defined in Sec. 98.90), the term ``fluorinated GHGs'' in the definition
of each fluorinated GHG group in Sec. 98.6 shall include fluorinated heat transfer fluids (as defined in
Sec. 98.98), whether or not they are also fluorinated GHGs.
\f\ This fluorinated GHG group was updated in the final rule published on [Date of publication of the final rule
in the Federal Register] and effective on January 1, 2023.
0
11. Amend table A-3 to subpart A of part 98 by:
0
a. Revising the entry ``Electrical transmission and distribution
equipment use at facilities where the total nameplate capacity of SF6
and PFC containing equipment exceeds 17,820 pounds, as determined under
Sec. 98.301 (subpart DD).'';
0
b. Removing the entry for ``Electrical transmission and distribution
equipment manufacture or refurbishment (subpart SS).''; and
0
c. Adding the entry ``Geologic Sequestration of Carbon Dioxide with
Enhanced Oil Recovery Using ISO 27916 (subpart VV).'' at the end of the
table.
The revision and addition read as follows:
* * * * *
Table A-3 to Subpart A of Part 98--Source Category List for Sec.
98.2(a)(1)
------------------------------------------------------------------------
-------------------------------------------------------------------------
* * * * * * *
Additional Source Categories \a\ Applicable in Reporting Year 2011 and
Future Years
Electrical transmission and distribution equipment use at facilities
where the total estimated emissions from fluorinated GHGs, as
determined under Sec. 98.301 (subpart DD), are equivalent to 25,000
metric tons CO2e or more per year.
* * * * * * *
Geologic Sequestration of Carbon Dioxide with Enhanced Oil Recovery
Using ISO 27916 (subpart VV).
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.
* * * * *
0
12. Amend table A-4 to subpart A of part 98 by adding the entry
``Electrical transmission and distribution equipment manufacture or
refurbishment, as determined under Sec. 98.451 (subpart SS).'' after
the entry ``Industrial wastewater treatment (subpart II).'' to read as
follows:
Table A-4 to Subpart A of Part 98--Source Category List for Sec.
98.2(a)(2)
------------------------------------------------------------------------
-------------------------------------------------------------------------
* * * * * * *
Additional Source Categories \a\ Applicable in Reporting Year 2011 and
Future Years
* * * * * * *
Electrical transmission and distribution equipment manufacture or
refurbishment, as determined under Sec. 98.451 (subpart SS).
[[Page 37040]]
* * * * * * *
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.
* * * * *
Subpart C--General Stationary Fuel Combustion Sources
0
13. Amend Sec. 98.33 by:
0
a. Revising parameters ``CC'' and ``MW'' of Equation C-5 in paragraph
(a)(3)(iii) introductory text;
0
b. Adding paragraphs (a)(3)(iii)(A) and (B);
0
c. Revising paragraph (b)(1)(vii);
0
d. Revising parameter ``EF'' of Equations C-8 in paragraph (c)(1)
introductory text, C-8a in paragraph (c)(1)(i), C-8b in paragraph
(c)(1)(ii), C-9a in paragraph (c)(2), C-9b in paragraph (c)(3), and C-
10 in paragraph (c)(4) introductory text;
0
e. Revising paragraphs (c)(6)(i), (c)(6)(ii) introductory text, and
(c)(6)(ii)(A) and (C);
0
f. Removing and reserving paragraph (c)(6)(ii)(B);
0
g. Revising parameter ``R'' of Equation C-11 in paragraph (d)(1); and
0
h. Revising the introductory text of paragraphs (e), (e)(1), (e)(2)(v),
and (e)(3) and paragraph (e)(3)(iv).
The additions and revisions read as follows:
Sec. 98.33 Calculating GHG emissions.
* * * * *
(a) * * *
(3) * * *
(iii) * * *
CC = Annual average carbon content of the gaseous fuel (kg C per kg
of fuel). The annual average carbon content shall be determined
using the procedures specified in paragraphs (a)(3)(iii)(A)(1) and
(a)(3)(iii)(A)(2) of this section.
MW = Annual average molecular weight of the gaseous fuel (kg per kg-
mole). The annual average molecular weight shall be determined using
the procedures specified in paragraphs (a)(3)(iii)(A)(3) and
(a)(3)(iii)(A)(4) of this section.
* * * * *
(A) The minimum required sampling frequency for determining the
annual average carbon content (e.g., monthly, quarterly, semi-annually,
or by lot) is specified in Sec. 98.34. The method for computing the
annual average carbon content for Equation C-5 is a function of unit
size and how frequently you perform or receive from the fuel supplier
the results of fuel sampling for carbon content. The methods are
specified in paragraphs (a)(3)(iii)(A)(1) and (2) of this section, as
applicable.
(1) If the results of fuel sampling are received monthly or more
frequently, then for each unit with a maximum rated heat input capacity
greater than or equal to 100 mmBtu/hr (or for a group of units that
includes at least one unit of that size), the annual average carbon
content for Equation C-5 shall be calculated using Equation C-5a of
this section. If multiple carbon content determinations are made in any
month, average the values for the month arithmetically.
[GRAPHIC] [TIFF OMITTED] TP21JN22.000
Where:
(CC)annual = Weighted annual average carbon content of
the fuel (kg C per kg of fuel).
(CC)I = Measured carbon content of the fuel, for sample
period ``i'' (which may be the arithmetic average of multiple
determinations), or, if applicable, an appropriate substitute data
value (kg C per kg of fuel).
(Fuel)i = Volume of the fuel (scf) combusted during the sample
period ``i'' (e.g., monthly, quarterly, semi-annually, or by lot)
from company records.
(MW)i = Measured molecular weight of the fuel, for sample period
``i'' (which may be the arithmetic average of multiple
determinations), or, if applicable, an appropriate substitute data
value (kg per kg-mole).
MVC = Molar volume conversion factor at standard conditions, as
defined in Sec. 98.6. Use 849.5 scf per kg-mole if you select 68
[deg]F as standard temperature and 836.6 scf per kg-mole if you
select 60 [deg]F as standard temperature.
n = Number of sample periods in the year.
(2) If the results of fuel sampling are received less frequently
than monthly, or, for a unit with a maximum rated heat input capacity
less than 100 mmBtu/hr (or a group of such units) regardless of the
carbon content sampling frequency, the annual average carbon content
for Equation C-5 shall either be computed according to paragraph
(a)(3)(iii)(A)(1) of this section or as the arithmetic average carbon
content for all values for the year (including valid samples and
substitute data values under Sec. 98.35).
(B) The minimum required sampling frequency for determining the
annual average molecular weight (e.g., monthly, quarterly, semi-
annually, or by lot) is specified in Sec. 98.34. The method for
computing the annual average molecular weight for Equation C-5 is a
function of unit size and how frequently you perform or receive from
the fuel supplier the results of fuel sampling for molecular weight.
The methods are specified in paragraphs (a)(3)(iii)(B)(1) and
(a)(3)(iii)(B)(2) of this section, as applicable.
(1) If the results of fuel sampling are received monthly or more
frequently, then for each unit with a maximum rated heat input capacity
greater than or equal to 100 mmBtu/hr (or for a group of units that
includes at least one unit of that size), the annual average molecular
weight for Equation C-5 shall be calculated using Equation C-5b of this
section. If multiple molecular weight determinations are made in any
month, average the values for the month arithmetically.
[GRAPHIC] [TIFF OMITTED] TP21JN22.001
Where:
(MW)annual = Weighted annual average molecular weight of
the fuel (kg per kg-mole).
(MW)i = Measured molecular weight of the fuel, for sample
period ``i'' (which may be the arithmetic average of multiple
[[Page 37041]]
determinations), or, if applicable, an appropriate substitute data
value (kg per kg-mole).
(Fuel)i = Volume of the fuel (scf) combusted during the
sample period ``i'' (e.g., monthly, quarterly, semi-annually, or by
lot) from company records.
MVC = Molar volume conversion factor at standard conditions, as
defined in Sec. 98.6. Use 849.5 scf per kg-mole if you select 68
[deg]F as standard temperature and 836.6 scf per kg-mole if you
select 60 [deg]F as standard temperature.
n = Number of sample periods in the year.
(2) If the results of fuel sampling are received less frequently
than monthly, or, for a unit with a maximum rated heat input capacity
less than 100 mmBtu/hr (or a group of such units) regardless of the
molecular weight sampling frequency, the annual average molecular
weight for Equation C-5 shall either be computed according to paragraph
(a)(3)(iii)(A)(3) of this section or as the arithmetic average
molecular weight for all values for the year (including valid samples
and substitute data values under Sec. 98.35).
* * * * *
(b) * * *
(1) * * *
(vii) May be used for the combustion of MSW and/or tires in a unit,
provided that no more than 10 percent of the unit's annual heat input
is derived from those fuels, combined.
* * * * *
(c) * * *
(1) * * *
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 compressor drivers
at facilities subject to subpart W of this part, which must use the
applicable CH4 emission factor from Table W-9 to subpart
W of this part.
* * * * *
(i) * * *
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 compressor drivers
at facilities subject to subpart W of this part, which must use the
applicable CH4 emission factor from Table W-9 to subpart
W of this part.
* * * * *
(ii) * * *
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 compressor drivers
at facilities subject to subpart W of this part, which must use the
applicable CH4 emission factor from Table W-9 to subpart
W of this part.
* * * * *
(2) * * *
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 compressor drivers
at facilities subject to subpart W of this part, which must use the
applicable CH4 emission factor from Table W-9 to subpart
W of this part.
* * * * *
(3) * * *
EF = Fuel-specific emission factor for CH4 or
N2O, from Table C-2 of this subpart (kg CH4 or
N2O per mmBtu), except for natural gas compressor drivers
at facilities subject to subpart W of this part, which must use the
applicable CH4 emission factor from Table W-9 to subpart
W of this part.
* * * * *
(4) * * *
EF = Fuel-specific emission factor for CH4 or
N2O, from Table C-2 of this subpart (kg CH4 or
N2O per mmBtu), except for natural gas compressor drivers
at facilities subject to subpart W of this part, which must use the
applicable CH4 emission factor from Table W-9 to subpart
W of this part.
* * * * *
(6) * * *
(i) If the mass, volume, or heat input of each component fuel in
the blend is determined before the fuels are mixed and combusted,
calculate and report CH4 and N2O emissions
separately for each component fuel, using the applicable procedures in
this paragraph (c).
(ii) If the mass, volume, or heat input of each component fuel in
the blend is not determined before the fuels are mixed and combusted, a
reasonable estimate of the percentage composition of the blend, based
on best available information, is required. Perform the following
calculations for each component fuel ``i'' that is listed in Table C-2:
(A) Multiply (% Fuel)i, the estimated mass, volume, or heat input
percentage of component fuel ``i'' (expressed as a decimal fraction),
by the total annual mass, volume, or heat input of the blended fuel
combusted during the reporting year, to obtain an estimate of the
annual value for component ``i'';
* * * * *
(C) Calculate the annual CH4 and N2O
emissions from component ``i'', using Equation C-8 (fuel mass or
volume), C-8a (fuel heat input), C-8b (fuel heat input), C-9a (fuel
mass or volume), or C-10 (fuel heat input) of this section, as
applicable;
* * * * *
(d) * * *
(1) * * *
R = The number of moles of CO2 released per mole of
sorbent used (R = 1.00 when the sorbent is CaCO3 and the
targeted acid gas species is SO2).
* * * * *
(e) Biogenic CO2 emissions from combustion of biomass
with other fuels. Use the applicable procedures of this paragraph (e)
to estimate biogenic CO2 emissions from units that combust a
combination of biomass and fossil fuels (i.e., either co-fired or
blended fuels). Separate reporting of biogenic CO2 emissions
from the combined combustion of biomass and fossil fuels is required
for those biomass fuels listed in Table C-1 of this section, MSW, and
tires. In addition, when a biomass fuel that is not listed in Table C-1
is combusted in a unit that has a maximum rated heat input greater than
250 mmBtu/hr, if the biomass fuel accounts for 10% or more of the
annual heat input to the unit, and if the unit does not use CEMS to
quantify its annual CO2 mass emissions, then, pursuant to
Sec. 98.33(b)(3)(iii), Tier 3 must be used to determine the carbon
content of the biomass fuel and to calculate the biogenic
CO2 emissions from combustion of the fuel. Notwithstanding
these requirements, in accordance with Sec. 98.3(c)(12), separate
reporting of biogenic CO2 emissions is optional for the 2010
reporting year for units subject to subpart D of this part and for
units that use the CO2 mass emissions calculation
methodologies in part 75 of this chapter, pursuant to paragraph (a)(5)
of this section. However, if the owner or operator opts to report
biogenic CO2 emissions separately for these units, the
appropriate method(s) in this paragraph (e) shall be used.
(1) You may use Equation C-1 of this subpart to calculate the
annual CO2 mass emissions from the combustion of the biomass
fuels listed in Table C-1 of this subpart, in a unit of any size,
including units equipped with a CO2 CEMS, except when the
use of Tier 2 is required as specified in paragraph (b)(1)(iv) of this
section. Determine the quantity of biomass combusted using one of the
following procedures in this paragraph (e)(1), as appropriate, and
document the selected procedures in the Monitoring Plan under Sec.
98.3(g):
* * * * *
(2) * * *
(v) Calculate the biogenic percentage of the annual CO2
emissions expressed as a decimal fraction, using Equation C-14 of this
section:
* * * * *
(3) You must use the procedures in paragraphs (e)(3)(i) through
(iii) of this section to determine the annual biogenic CO2
emissions from the
[[Page 37042]]
combustion of MSW, except as otherwise provided in paragraph (e)(3)(iv)
of this section. These procedures also may be used for any unit that
co-fires biomass and fossil fuels, including units equipped with a
CO2 CEMS.
* * * * *
(iv) In lieu of following the procedures in paragraphs (e)(3)(i)
through (iii) of this section, the procedures of this paragraph may be
used for the combustion of tires regardless of the percent of the
annual heat input provided by tires. The calculation procedure in this
paragraph may be used for the combustion of MSW if the combustion of
MSW provides no more than 10 percent of the annual heat input to the
unit or if a small, batch incinerator combusts no more than 1,000 tons
per year of MSW.
(A) Calculate the total annual CO2 emissions from
combustion of MSW and/or tires in the unit, using the applicable
methodology in paragraphs (a)(1) through (3) of this section for units
using Tier 1, Tier 2, or Tier 3; otherwise use the Tier 1 calculation
methodology in paragraph (a)(1) of this section for units using either
the Tier 4 or Alternative Part 75 calculation methodologies to
calculate total CO2 emissions.
(B) Multiply the result from paragraph (e)(3)(iv)(A) of this
section by the appropriate default factor to determine the annual
biogenic CO2 emissions, in metric tons. For MSW, use a
default factor of 0.60 and for tires, use a default factor of 0.24.
* * * * *
0
14. Amend Sec. 98.34 by revising paragraphs (c)(6) and (d) to read as
follows:
Sec. 98.34 Monitoring and QA/QC requirements.
* * * * *
(c) * * *
(6) For applications where CO2 concentrations in process
and/or combustion flue gasses are lower or higher than the typical
CO2 span value for coal-based fuels (e.g., 20 percent
CO2 for a coal fired boiler), cylinder gas audits of the
CO2 monitor under appendix F to part 60 of this chapter may
be performed at 40-60 percent and 80-100 percent of CO2
span, in lieu of the prescribed calibration levels of 5-8 percent and
10-14 percent CO2 by volume.
* * * * *
(d) Except as otherwise provided in Sec. 98.33(e)(3)(iv), when
municipal solid waste (MSW) is either the primary fuel combusted in a
unit or the only fuel with a biogenic component combusted in the unit,
determine the biogenic portion of the CO2 emissions using
ASTM D6866-16 Standard Test Methods for Determining the Biobased
Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon
Analysis) and ASTM D7459-08 Standard Practice for Collection of
Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-
Derived Carbon Dioxide Emitted from Stationary Emissions Sources (both
incorporated by reference, see Sec. 98.7). Perform the ASTM D7459-08
sampling and the ASTM D6866-16 analysis at least once in every calendar
quarter in which MSW is combusted in the unit. Collect each gas sample
during normal unit operating conditions for at least 24 total (not
necessarily consecutive) hours, or longer if the facility deems it
necessary to obtain a representative sample. Notwithstanding this
requirement, if the types of fuels combusted and their relative
proportions are consistent throughout the year, the minimum required
sampling time may be reduced to 8 hours if at least two 8-hour samples
and one 24-hour sample are collected under normal operating conditions,
and arithmetic average of the biogenic fraction of the flue gas from
the 8-hour samples (expressed as a decimal) is within 5
percent of the biogenic fraction from the 24-hour test. There must be
no overlapping of the 8-hour and 24-hour test periods. Document the
results of the demonstration in the unit's monitoring plan. If the
types of fuels and their relative proportions are not consistent
throughout the year, an optional sampling approach that facilities may
wish to consider to obtain a more representative sample is to collect
an integrated sample by extracting a small amount of flue gas (e.g., 1
to 5 cc) in each unit operating hour during the quarter. Separate the
total annual CO2 emissions into the biogenic and non-
biogenic fractions using the average proportion of biogenic emissions
of all samples analyzed during the reporting year. Express the results
as a decimal fraction (e.g., 0.30, if 30 percent of the CO2
is biogenic). When MSW is the primary fuel for multiple units at the
facility, and the units are fed from a common fuel source, testing at
only one of the units is sufficient.
* * * * *
0
15. Amend Sec. 98.36 by:
0
a. Revising paragraphs (c)(1) introductory text, (c)(1)(ii) and (vi),
(c)(3) introductory text, and (c)(3)(vi);
0
b. Adding paragraph (c)(3)(xi); and
0
c. Revising paragraphs (e)(2)(ii)(C) and (e)(2)(xi).
The revisions and addition read as follows:
Sec. 98.36 Data reporting requirements.
* * * * *
(c) * * *
(1) Aggregation of units. If a facility contains two or more units
(e.g., boilers or combustion turbines), each of which has a maximum
rated heat input capacity of 250 mmBtu/hr or less, you may report the
combined GHG emissions for the group of units in lieu of reporting GHG
emissions from the individual units, provided that the use of Tier 4 is
not required or elected for any of the units and the units use the same
tier for any common fuels combusted. Compressor drivers that calculate
emissions using an applicable CH4 emission factor from Table
W-9 to subpart W of this part, must be reported as their own
aggregation of units configuration, according to design class (i.e.,
two-stroke lean-burn, four-stroke lean-burn, and four-stroke rich-
burn). You may not have a combination of one design class of compressor
driver (using one Table W-9 CH4 emission factor) and other
combustion units (e.g., using a Table C-2 CH4 emission
factor or another Table W-9 CH4 emission factor) in the same
aggregation of units configuration. If this option is selected, the
following information shall be reported instead of the information in
paragraph (b) of this section:
* * * * *
(ii) For each unit in the group greater than or equal to 10 mmBtu/
hr, the unit type, maximum rated heat input capacity, and an estimate
of the total annual heat input (expressed as a decimal fraction). To
determine the total annual heat input decimal fraction for a unit,
divide the actual heat input for that unit (all fuels) by the sum of
the actual heat input for all units (all fuels), including units less
than 10 mmBtu/hr. Estimates of the actual heat inputs may be based on
company records. If all units in this configuration are less than 10
(mmBtu/hr), this requirement does not apply.
* * * * *
(vi) Annual CO2 mass emissions and annual
CH4, and N2O mass emissions, aggregated for each
type of fuel combusted in the group of units during the report year,
expressed in metric tons of each gas and in metric tons of
CO2e. If any of the units burn biomass, report also the
annual CO2 emissions from combustion of all biomass fuels
combined, expressed in metric tons.
* * * * *
[[Page 37043]]
(3) Common pipe configurations. When two or more stationary
combustion units at a facility combust the same type of liquid or
gaseous fuel and the fuel is fed to the individual units through a
common supply line or pipe, you may report the combined emissions from
the units served by the common supply line, in lieu of separately
reporting the GHG emissions from the individual units, provided that
the total amount of fuel combusted by the units is accurately measured
at the common pipe or supply line using a fuel flow meter, or, for
natural gas, the amount of fuel combusted may be obtained from gas
billing records. For Tier 3 applications, the flow meter shall be
calibrated in accordance with Sec. 98.34(b). If a portion of the fuel
measured (or obtained from gas billing records) at the main supply line
is diverted to either: A flare; or another stationary fuel combustion
unit (or units), including units that use a CO2 mass
emissions calculation method in part 75 of this chapter; or a chemical
or industrial process (where it is used as a raw material but not
combusted), and the remainder of the fuel is distributed to a group of
combustion units for which you elect to use the common pipe reporting
option, you may use company records to subtract out the diverted
portion of the fuel from the fuel measured (or obtained from gas
billing records) at the main supply line prior to performing the GHG
emissions calculations for the group of units using the common pipe
option. If the diverted portion of the fuel is combusted, the GHG
emissions from the diverted portion shall be accounted for in
accordance with the applicable provisions of this part. When the common
pipe option is selected, the applicable tier shall be used based on the
maximum rated heat input capacity of the largest unit served by the
common pipe configuration, except where the applicable tier is based on
criteria other than unit size. For example, if the maximum rated heat
input capacity of the largest unit is greater than 250 mmBtu/hr, Tier 3
will apply, unless the fuel transported through the common pipe is
natural gas or distillate oil, in which case Tier 2 may be used, in
accordance with Sec. 98.33(b)(2)(ii). As a second example, in
accordance with Sec. 98.33(b)(1)(v), Tier 1 may be used regardless of
unit size when natural gas is transported through the common pipe, if
the annual fuel consumption is obtained from gas billing records in
units of therms or mmBtu. Compressor drivers that calculate emissions
using an applicable CH4 emission factor from Table W-9 to
subpart W of this part, must be reported as their own common pipe
configuration, according to design class (i.e., two-stroke lean-burn,
four-stroke lean-burn, and four-stroke rich-burn). You may not have a
combination of one design class of compressor driver (using one Table
W-9 CH4 emission factor) and other combustion units (e.g.,
using a Table C-2 CH4 emission factor or another Table W-9
CH4 emission factor) in the same common pipe configuration.
When the common pipe reporting option is selected, the following
information shall be reported instead of the information in paragraph
(b) of this section:
* * * * *
(vi) If any of the units burns biomass, the annual CO2
emissions from combustion of all biomass fuels from the units served by
the common pipe, expressed in metric tons.
* * * * *
(xi) For each unit in the group greater than or equal to 10 mmBtu/
hr, the unit type, maximum rated heat input capacity, and an estimate
of the total annual heat input (expressed as a decimal fraction). To
determine the total annual heat input decimal fraction for a unit,
divide the actual heat input for that unit (all fuels) by the sum of
the actual heat input for all units (all fuels), including units less
than 10 mmBtu/hr. Estimated heat input values may be based on company
records. If all units in this configuration are less than 10 (mmBtu/
hr), this requirement does not apply.
* * * * *
(e) * * *
(2) * * *
(ii) * * *
(C) The annual average, and, where applicable, monthly high heat
values used in the CO2 emissions calculations for each type
of fuel combusted during the reporting year, in mmBtu per short ton for
solid fuels, mmBtu per gallon for liquid fuels, and mmBtu per scf for
gaseous fuels. Report an HHV value for each calendar month in which HHV
determination is required. If multiple values are obtained in a given
month, report the arithmetic average value for the month.
* * * * *
(xi) When ASTM methods D7459-08 and D6866-16 (both incorporated by
reference, see Sec. 98.7) are used in accordance with Sec. 98.34(e)
to determine the biogenic portion of the annual CO2
emissions from a unit that co-fires biogenic fuels (or partly-biogenic
fuels, including tires) and non-biogenic fuels, you shall report the
results of each quarterly sample analysis, expressed as a decimal
fraction (e.g., if the biogenic fraction of the CO2
emissions is 30 percent, report 0.30).
* * * * *
0
16. Amend Sec. 98.37 by revising paragraphs (b) introductory text,
(b)(9) through (11), (14), (18), (20), (22), and (23) to read as
follows:
Sec. 98.37 Records that must be retained.
* * * * *
(b) For each stationary fuel combustion source that elects to use
the verification software specified in Sec. 98.5(b) rather than report
data specified in paragraphs (b)(9)(iii), (c)(2)(ix), (e)(2)(i),
(e)(2)(ii)(A), (e)(2)(ii)(C), (e)(2)(ii)(D), (e)(2)(iv)(A),
(e)(2)(iv)(C), (e)(2)(iv)(F), and (e)(2)(ix)(D) through (F) of this
section, you must keep a record of the file generated by the
verification software for the applicable data specified in paragraphs
(b)(1) through (37) of this section. Retention of this file satisfies
the recordkeeping requirement for the data in paragraphs (b)(1) through
(37) of this section.
* * * * *
(9) Measured high heat value of each solid fuel, for month (which
may be the arithmetic average of multiple determinations), or, if
applicable, an appropriate substitute data value (mmBtu per ton)
(Equation C-2b of Sec. 98.33). Annual average HHV of each solid fuel
(mmBtu per ton) (Equation C-2a of Sec. 98.33).
(10) Measured high heat value of each liquid fuel, for month (which
may be the arithmetic average of multiple determinations), or, if
applicable, an appropriate substitute data value (mmBtu per gallons)
(Equation C-2b). Annual average HHV of each liquid fuel (mmBtu per
gallons) (Equation C-2a of Sec. 98.33).
(11) Measured high heat value of each gaseous fuel, for month
(which may be the arithmetic average of multiple determinations), or,
if applicable, an appropriate substitute data value (mmBtu per scf)
(Equation C-2b). Annual average HHV of each gaseous fuel (mmBtu per
scf) (Equation C-2a of Sec. 98.33).
* * * * *
(14) Volume of each gaseous fuel combusted during month (scf)
(Equation C-2b, Equation C-5a, Equation C-5b).
* * * * *
(18) Annual average carbon content of each solid fuel (percent by
weight, expressed as a decimal fraction) (Equation C-3). Where
applicable, monthly carbon content of each solid fuel (which may be the
arithmetic
[[Page 37044]]
average of multiple determinations), or, if applicable, an appropriate
substitute data value (percent by weight, expressed as a decimal
fraction) (Equation C-2b--see the definition of ``CC'' in Equation C-
3).
* * * * *
(20) Annual average carbon content of each liquid fuel (kg C per
gallon of fuel) (Equation C-4). Where applicable, monthly carbon
content of each liquid fuel (which may be the arithmetic average of
multiple determinations), or, if applicable, an appropriate substitute
data value (kg C per gallon of fuel) (Equation C-2b--see the definition
of ``CC'' in Equation C-3).
* * * * *
(22) Annual average carbon content of each gaseous fuel (kg C per
kg of fuel) (Equation C-5). Where applicable, monthly carbon content of
each gaseous (which may be the arithmetic average of multiple
determinations), or, if applicable, an appropriate substitute data
value (kg C per kg of fuel) (Equation C-5a).
(23) Annual average molecular weight of each gaseous fuel (kg/kg-
mole) (Equation C-5). Where applicable, monthly molecular weight of
each gaseous (which may be the arithmetic average of multiple
determinations), or, if applicable, an appropriate substitute data
value (kg/kg-mole) (Equation C-5b).
* * * * *
0
17. Amend table C-2 to subpart C of part 98 by revising the entry
``Natural Gas'' to read as follows:
---------------------------------------------------------------------------
\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 compressor drivers. For natural gas-
fired compressor drivers at facilities subject to subpart W of this
part, reporters must use the applicable CH4 emission
factor from Table W-9 to subpart W of this part.
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
* * * * * * *
------------------------------------------------------------------------
* * * * *
Subpart G--Ammonia Manufacturing
0
18. Amend Sec. 98.72 by revising paragraph (a) to read as follows:
Sec. 98.72 GHGs to report.
* * * * *
(a) CO2 process emissions from steam reforming of a
hydrocarbon or the gasification of solid and liquid raw material,
reported for each ammonia manufacturing unit following the requirements
of this subpart.
* * * * *
0
19. Amend Sec. 98.73 by revising the introductory text and paragraph
(b) to read as follows:
Sec. 98.73 Calculating GHG emissions
You must calculate and report the annual net CO2 process
emissions from each ammonia manufacturing unit using the procedures in
either paragraph (a) or (b) of this section.
* * * * *
(b) Calculate and report under this subpart process CO2
emissions using the procedures in paragraphs (b)(1) through (4) of this
section, as applicable.
(1) Gaseous feedstock. You must calculate, from each ammonia
manufacturing unit, the CO2 process emissions from gaseous
feedstock according to Equation G-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.002
Where:
CO2,G = Annual CO2 emissions arising from
gaseous feedstock consumption (metric tons).
Fdstkn = Volume of the gaseous feedstock used in month n
(scf of feedstock).
CCn = Carbon content of the gaseous feedstock, for month
n (kg C per kg of feedstock), determined according to 98.74(c).
MW = Molecular weight of the gaseous feedstock (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at
standard conditions).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
n = Number of month.
(2) Liquid feedstock. You must calculate, from each ammonia
manufacturing unit, the CO2 process emissions from liquid
feedstock according to Equation G-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.003
Where:
CO2,L = Annual CO2 emissions arising from
liquid feedstock consumption (metric tons).
Fdstkn = Volume of the liquid feedstock used in month n
(gallons of feedstock).
[[Page 37045]]
CCn = Carbon content of the liquid feedstock, for month n
(kg C per gallon of feedstock) determined according to 98.74(c).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
n = Number of month.
(3) Solid feedstock. You must calculate, from each ammonia
manufacturing unit, the CO2 process emissions from solid
feedstock according to Equation G-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.004
Where:
CO2,S = Annual CO2 emissions arising from
solid feedstock consumption (metric tons).
Fdstkn = Mass of the solid feedstock used in month n (kg
of feedstock).
CCn = Carbon content of the solid feedstock, for month n
(kg C per kg of feedstock), determined according to 98.74(c).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
n = Number of month.
(4) Net CO2 process emissions. You must calculate the
annual net CO2 process emissions at each ammonia
manufacturing unit according to Equation G-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.005
Where:
CO2,net = Annual net CO2 process emissions
from each ammonia manufacturing unit (metric tons).
CO2,p = Annual CO2 process emissions arising
from feedstock consumption based on feedstock type ``p'' (metric
tons/yr) as calculated in paragraphs (b)(1) through (3) of this
section.
P = Index for feedstock type; 1 indicates gaseous feedstock; 2
indicates liquid feedstock; and 3 indicates solid feedstock.
CO2,urea,n = Amount of carbon dioxide collected from
ammonia production and consumed on site for urea production, in
month n (metric tons).
MeOHn = Mass of methanol intentionally produced as a
desired product for month n (metric tons).
44/32 = Ratio of molecular weights, CO2 to methanol.
* * * * *
0
20. Amend Sec. 98.76 by revising the introductory text and paragraphs
(b)(1) and (13) to read as follows:
Sec. 98.76 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
and (b) of this section, as applicable for each ammonia manufacturing
unit.
* * * * *
(b) * * *
(1) Annual net CO2 process emissions (metric tons) for
each ammonia manufacturing unit.
* * * * *
(13) Annual amount of CO2 collected from ammonia
production (metric tons) and consumed on site for urea production and
the method used to determine the CO2 consumed in urea
production.
* * * * *
0
21. Amend Sec. 98.77 by revising paragraph (c) introductory text and
adding paragraphs (c)(8) and (9) to read as follows:
Sec. 98.77 Records that must be retained.
* * * * *
(c) You must keep a record of the file generated by the
verification software specified in Sec. 98.5(b) for the applicable
data specified in paragraphs (c)(1) through (9) of this section.
Retention of this file satisfies the recordkeeping requirement for the
data in paragraphs (c)(1) through (9) of this section.
* * * * *
(8) Quantity of CO2 collected from ammonia production
and consumed on site for urea production in month (Equation G-4 of
Sec. 98.73).
(9) Quantity of methanol intentionally produced as a desired
product in month (metric tons) (Equation G-4).
Subpart H--Cement Production
0
22. Amend Sec. 98.83 by:
0
a. Revising paragraph (d)(1);
0
b. Revising parameters ``CKDCaO,'' ``CKDCaO,''
``CKDMgO,'' and ``CKDMgO'' of Equation H-4 in
paragraph (d)(2)(ii)(A); and
0
c. Revising paragraph (d)(3).
The revisions read as follows:
Sec. 98.83 Calculating GHG emissions.
* * * * *
(d) * * *
(1) Calculate CO2 process emissions from all kilns at
the facility using Equation H-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.006
Where:
CO2 CMF = Annual process emissions of CO2 from
cement manufacturing, metric tons.
CO2 Cli,m = Total annual emissions of CO2 from
clinker production from kiln m, metric tons.
CO2 rm,m = Total annual emissions of CO2 from
raw materials from kiln m, metric tons.
K = Total number of kilns at a cement manufacturing facility.
(2) * * *
(ii) * * *
(A) * * *
CKDCaO = Quarterly total CaO content of CKD not recycled
to the kiln, wt-fraction.
CKDncCaO = Quarterly non-calcined CaO content of CKD not
recycled to the kiln, wt-fraction.
* * * * *
CKDMgO = Quarterly total MgO content of CKD not recycled
to the kiln, wt-fraction.
CKDncMgO = Quarterly non-calcined MgO content of CKD not
recycled to the kiln, wt-fraction.
* * * * *
(3) CO2 emissions from raw materials from each kiln. Calculate
CO2 emissions from raw materials using Equation H-5 of this
section:
[[Page 37046]]
[GRAPHIC] [TIFF OMITTED] TP21JN22.007
Where:
rm = The amount of raw material i consumed annually from kiln m,
tons/yr (dry basis) or the amount of raw kiln feed consumed annually
from kiln m, tons/yr (dry basis).
CO2,rm,m = Annual CO2 emissions from raw materials from
kiln m.
TOCrm = Organic carbon content of raw material i from
kiln m or organic carbon content of combined raw kiln feed (dry
basis) from kiln m, as determined in Sec. 98.84(c) or using a
default factor of 0.2 percent of total raw material weight.
M = Number of raw materials or 1 if calculating emissions based on
combined raw kiln feed.
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion factor to convert tons to metric tons.
* * * * *
0
23. Amend Sec. 98.86 by adding paragraphs (a)(4) through (13) and
(b)(19) through (28) to read as follows:
Sec. 98.86 Data reporting requirements.
* * * * *
(a) * * *
(4) Annual arithmetic average of total CaO content of clinker at
the facility, wt-fraction.
(5) Annual arithmetic average of non-calcined CaO content of
clinker at the facility, wt-fraction.
(6) Annual arithmetic average of total MgO content of clinker at
the facility, wt-fraction.
(7) Annual arithmetic average of non-calcined MgO content of
clinker at the facility, wt-fraction.
(8) Annual arithmetic average of total CaO content of CKD not
recycled to the kiln(s) at the facility, wt-fraction.
(9) Annual arithmetic average of non-calcined CaO content of CKD
not recycled to the kiln(s) at the facility, wt-fraction.
(10) Annual arithmetic average of total MgO content of CKD not
recycled to the kiln(s) at the facility, wt-fraction.
(11) Annual arithmetic average of non-calcined MgO content not
recycled to the kiln(s) at the facility, wt-fraction.
(12) Annual facility CKD not recycled to the kiln(s), tons.
(13) The amount of raw kiln feed consumed annually at the facility,
tons (dry basis).
(b) * * *
(19) Annual arithmetic average of total CaO content of clinker at
the facility, wt-fraction.
(20) Annual arithmetic average of non-calcined CaO content of
clinker at the facility, wt-fraction.
(21) Annual arithmetic average of total MgO content of clinker at
the facility, wt-fraction.
(22) Annual arithmetic average of non-calcined MgO content of
clinker at the facility, wt-fraction.
(23) Annual arithmetic average of total CaO content of CKD not
recycled to the kiln(s) at the facility, wt-fraction.
(24) Annual arithmetic average of non-calcined CaO content of CKD
not recycled to the kiln(s) at the facility, wt-fraction.
(25) Annual arithmetic average of total MgO content of CKD not
recycled to the kiln(s) at the facility, wt-fraction.
(26) Annual arithmetic average of non-calcined MgO content of CKD
not recycled to the kiln(s) at the facility, wt-fraction.
(27) Annual facility CKD not recycled to the kiln(s), tons.
(28) The amount of raw kiln feed consumed annually at the facility,
tons (dry basis).
Subpart I--Electronics Manufacturing
0
24. Amend Sec. 98.91 by revising paragraphs (a) introductory text and
(a)(1) through (3), and parameters ``Ei'' and ``i'' of
Equation I-4 in paragraph (a)(4) to read as follows:
Sec. 98.91 Reporting threshold.
(a) You must report GHG emissions under this subpart if electronics
manufacturing production processes, as defined in Sec. 98.90, are
performed at your facility and your facility meets the requirements of
either Sec. 98.2(a)(1) or (a)(2). To calculate total annual GHG
emissions for comparison to the 25,000 metric ton CO2e per
year emission threshold in Sec. 98.2(a)(2), follow the requirements of
Sec. 98.2(b), with one exception. Rather than using the calculation
methodologies in Sec. 98.93 to calculate emissions from electronics
manufacturing production processes, calculate emissions of each
fluorinated GHG from electronics manufacturing production processes by
using paragraph (a)(1), (2), or (3) of this section, as appropriate,
and then sum the emissions of each fluorinated GHG and account for
fluorinated heat transfer fluid emissions by using paragraph (a)(4) of
this section.
(1) If you manufacture semiconductors or MEMS you must calculate
annual production process emissions resulting from the use of each
input gas for threshold applicability purposes using either the default
emission factors shown in Table I-1 to this subpart and Equation I-1A
of this subpart, or the consumption of each input gas, the default
emission factors shown in Table I-2 to this subpart, and Equation I-1B
of this subpart.
[GRAPHIC] [TIFF OMITTED] TP21JN22.008
Where:
Ei = Annual production process emissions of gas i for
threshold applicability purposes (metric tons CO2e).
S = 100 percent of annual manufacturing capacity of a facility as
calculated using Equation I-5 of this subpart (m\2\).
EFi = Emission factor for gas i (kg/m\2\) shown in Table
I-1 to this subpart.
GWPi = Gas-appropriate GWP as provided in Table A-1 to
subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Emitted gas.
[GRAPHIC] [TIFF OMITTED] TP21JN22.009
Ei = Annual production process emissions resulting from
the use of input gas i for threshold applicability purposes (metric
tons CO2e).
Ci = Annual GHG (input gas i) purchases or consumption
(kg). Only gases that are used in semiconductor or MEMS
manufacturing processes listed at Sec. 98.90(a)(1) through (a)(4)
must be considered for threshold applicability purposes.
(1-Ui), BCF4, and BC2F6
= Default emission factors for the gas consumption-based
[[Page 37047]]
threshold applicability determination listed in Table I-2 to this
subpart.
GWPi = Gas-appropriate GWP as provided in Table A-1 to
subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.
(2) If you manufacture LCDs, you must calculate annual production
process emissions resulting from the use of each input gas for
threshold applicability purposes using either the default emission
factors shown in Table I-1 to this subpart and Equation I-2 of this
subpart or the consumption of each input gas, the default emission
factors shown in Table I-2 to this subpart, and Equation I-1B of this
subpart.
[GRAPHIC] [TIFF OMITTED] TP21JN22.010
Where:
Ei = Annual production process emissions of gas i for
threshold applicability purposes (metric tons CO2e).
S = 100 percent of annual manufacturing capacity of a facility as
calculated using Equation I-5 of this subpart (m\2\).
EFi = Emission factor for gas i (g/m\2\).
GWPi = Gas-appropriate GWP as provided in Table A-1 to
subpart A of this part.
0.000001 = Conversion factor from g to metric tons.
i = Emitted gas.
[GRAPHIC] [TIFF OMITTED] TP21JN22.011
Where:
Ei = Annual production process emissions resulting from
the use of input gas i for threshold applicability purposes (metric
tons CO2e).
Ci = Annual GHG (input gas i) purchases or consumption
(kg). Only gases that are used in LCD manufacturing processes listed
at Sec. 98.90(a)(1) through (a)(4) must be considered for threshold
applicability purposes.
(1-Ui), BCF4, and BC2F6
= Default emission factors for the gas consumption-based threshold
applicability determination listed in Table I-2 to this subpart.
GWPi = Gas-appropriate GWP as provided in Table A-1 to
subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.
(3) If you manufacture PVs, you must calculate annual production
process emissions resulting from the use of each input gas i for
threshold applicability purposes using gas-appropriate GWP values shown
in Table A-1 to subpart A of this part, the default emission factors
shown in Table I-2 to this subpart, and Equation I-3 of this subpart.
[GRAPHIC] [TIFF OMITTED] TP21JN22.012
Where:
Ei = Annual production process emissions resulting from
the use of input gas i for threshold applicability purposes (metric
tons CO2e).
Ci = Annual fluorinated GHG (input gas i) purchases or
consumption (kg). Only gases that are used in PV manufacturing
processes listed at Sec. 98.90(a)(1) through (a)(4) must be
considered for threshold applicability purposes.
(1-Ui), BCF4, and BC2F6
= Default emission factors for the gas consumption-based threshold
applicability determination listed in Table I-2 to this subpart.
GWPi = Gas-appropriate GWP as provided in Table A-1 to
subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.
(4) * * *
Ei = Annual production process emissions of gas i for
threshold applicability purposes (metric tons CO2e), as
calculated in Equations I-1a, I-1b, I-2a, I-2b, or I-3 of this
subpart.
i = Emitted gas.
* * * * *
0
25. Amend Sec. 98.92 by revising paragraph (a) to read as follows:
Sec. 98.92 GHGs to report.
(a) You must report emissions of fluorinated GHGs (as defined in
Sec. 98.6), N2O, and fluorinated heat transfer fluids (as
defined in Sec. 98.98). The fluorinated GHGs and fluorinated heat
transfer fluids that are emitted from electronics manufacturing
production processes include, but are not limited to, those listed in
Table I-21 to this subpart. You must individually report, as
appropriate:
* * * * *
0
26. Amend Sec. 98.93 by:
0
a. Revising paragraph (a)(1) introductory text;
0
b. Revising parameters ``Eij'' and ``N'' of Equation I-6 in
paragraph (a)(1) introductory text;
0
c. Revising Equation I-7 in paragraph (a)(1) introductory text;
0
d. Revising parameters ``BEijk'' and ``N'' of Equation I-7
in paragraph (a)(1) introductory text;
0
e. Revising paragraphs (a)(1)(i) and (ii) and (a)(2) and (6);
0
f. Adding paragraph (a)(7);
0
g. Revising the introductory text of paragraphs (e) and (i);
0
h. Removing and reserving paragraphs (i)(1) and (2);
0
i. Revising paragraph (i)(3) introductory text and (i)(3)(i), (iii)
through (vi), and (viii)).
0
j. Adding paragraph (i)(3)(ix);
0
k. Revising paragraph (i)(4); and
0
l. Removing paragraph (i)(5).
The revisions and additions read as follows:
Sec. 98.93 Calculating GHG emissions.
(a) * * *
(1) If you manufacture semiconductors, you must adhere to the
procedures in paragraphs (a)(1)(i) through (iii) of this section. You
must calculate annual emissions of each input gas and of each by-
product gas using Equations I-6, I-7, and I-9 of this subpart. If your
fab uses less than 50 kg of a fluorinated GHG in one reporting year,
you may calculate emissions as equal to your fab's annual consumption
for that specific gas as calculated in Equation I-11 of this subpart,
plus any by-product emissions of that gas calculated under paragraph
(a) of this section.
* * * * *
Eij = Annual emissions of input gas i from process sub-
type or process type j as calculated in Equation I-8A of this
subpart (metric tons).
N = The total number of process sub-types j that depends on the
electronics manufacturing fab and emission calculation methodology.
If Eij is calculated for a process type j in Equation I-
8A of this subpart, N = 1.
* * * * *
[[Page 37048]]
[GRAPHIC] [TIFF OMITTED] TP21JN22.013
* * * * *
BEkij = Annual emissions of by-product gas k formed from
input gas i used for process sub-type or process type j as
calculated in Equation I-8B of this subpart (metric tons).
N = The total number of process sub-types j that depends on the
electronics manufacturing fab and emission calculation methodology.
If BEkij is calculated for a process type j in Equation
I-8B of this subpart, N = 1.
* * * * *
(i) You must calculate annual fab-level emissions of each
fluorinated GHG used for the plasma etching/wafer cleaning process type
using default utilization and by-product formation rates as shown in
Table I-3 or I-4 of this subpart, and by using Equations I-8A and I-8B
of this subpart.
[GRAPHIC] [TIFF OMITTED] TP21JN22.014
Where:
Eij = Annual emissions of input gas i from process sub-
type or process type j, on a fab basis (metric tons).
Cij = Amount of input gas i consumed for process sub-type
or process type j, as calculated in Equation I-13 of this subpart,
on a fab basis (kg).
Uij = Process utilization rate for input gas i for
process sub-type or process type j (expressed as a decimal
fraction).
Aij = Fraction of input gas i used in process sub-type or
process type j with abatement systems, on a fab basis (expressed as
a decimal fraction).
Dij = Fraction of input gas i destroyed or removed when
fed into abatement systems by process tools where process sub-type,
or process type j is used, on a fab basis, calculated by taking the
tool weighted average of the claimed DREs for input gas on i on
tools that use process type or process sub-type j (expressed as a
decimal fraction). This is zero unless the facility adheres to the
requirements in Sec. 98.94(f).
UTij = The average uptime factor of all abatement systems
connected to process tools in the fab using input gas i in process
sub-type or process type j, as calculated in Equation I-15 of this
subpart, on a fab basis (expressed as a decimal fraction).
0.001 = Conversion factor from kg to metric tons.
i = Input gas.
j = Process sub-type or process type.
[GRAPHIC] [TIFF OMITTED] TP21JN22.015
Where:
BEkij = Annual emissions of by-product gas k formed from
input gas I from process sub-type or process type j, on a fab basis
(metric tons).
Bijk = By-product formation rate of gas k created as a
by-product per amount of input gas i (kg) consumed by process sub-
type or process type j (kg). For non-carbon containing input gases
used in chamber cleaning process sub-types, this is zero when the
combination of input gas and chamber cleaning process sub-type is
never used to clean chamber walls on equipment that process carbon-
containing films during the year (e.g., when NF3 is used
in remote plasma cleaning processes to only clean chambers that
never process carbon-containing films during the year).
Cij = Amount of input gas i consumed for process sub-
type, or process type j, as calculated in Equation I-13 of this
subpart, on a fab basis (kg).
akij = Fraction of input gas I used for process sub-type,
or process type j with abatement systems, on a fab basis (expressed
as a decimal fraction).
Dkij = Fraction of by-product gas k destroyed or removed
in when fed into abatement systems by process tools where process
sub-type or process type j is used, on a fab basis, calculated by
taking the tool weighted average of the claimed DREs for by-product
gas k on tools that use input gas i in process type or process sub-
type j (expressed as a decimal fraction). This is zero unless the
facility adheres to the requirements in Sec. 98.94(f).
UTkij = The average uptime factor of all abatement
systems connected to process tools in the fab emitting by-product
gas k, formed from input gas I in process sub-type or process type
j, on a fab basis (expressed as a decimal fraction). For this
equation, UTkij is assumed to be equal to UTij
as calculated in Equation I-15 of this subpart.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.
j = Process sub-type or process type.
k = By-product gas.
(ii) You must calculate annual fab-level emissions of each
fluorinated GHG used for each of the process sub-types associated with
the chamber cleaning process type, including in-situ plasma chamber
clean, remote plasma chamber clean, and in-situ thermal chamber clean,
using default utilization and by-product formation rates as shown in
Table I-3 or I-4 of this subpart, and by using Equations I-8A and I-8B
of this subpart.
* * * * *
(2) If you manufacture MEMS or PVs and use semiconductor tools and
processes, you may use Sec. 98.3(a)(1) to calculate annual fab-level
emissions for those processes. For all other tools and processes used
to manufacture MEMs, LCD and PV, you must calculate annual fab-level
emissions of each fluorinated GHG used for the plasma etching and
chamber cleaning process types using default utilization and by-product
formation rates as shown in Table I-5, I-6, or I-7 of this subpart, as
appropriate, and by using Equations I-8A and I-8B of this subpart. If
default values are not available for a particular input gas and process
type or sub-type combination in Tables I-5, I-6, or I-7, you must
follow the procedures in paragraph (a)(6) of this section. If your fab
uses less than 50 kg of a fluorinated GHG in one reporting year, you
may calculate emissions as equal to your fab's annual consumption for
that specific gas as calculated in Equation I-11 of this subpart, plus
any by-product emissions of that gas calculated under this paragraph
(a).
* * * * *
(6) If you are required, or elect, to perform calculations using
default emission factors for gas utilization and by-product formation
rates according to the procedures in paragraph (a)(1) or (a)(2) of this
section, and default values are not available for a particular input
gas and process type or sub-type combination in Tables I-3, I-4, I-5,
I-6, or I-7, you must use a utilization rate (Uij) of 0.2
(i.e., a 1-Uij of 0.8) and by-product formation rates of
0.15 for CF4 and 0.05 for C2F6 and use
Equations I-8A and I-8B of this subpart.
[[Page 37049]]
(7) If your fab employs hydrocarbon-fuel-based emissions control
systems (including, but not limited to, abatement systems as defined at
Sec. 98.98) to control emissions from tools that use either
NF3 in remote plasma cleaning processes or F2 as
an input gas in any process type or sub-type, you must calculate the
amount CF4 produced within and emitted from such systems
using Equation I-9 using default utilization and by-product formation
rates as shown in Table I-3 or I-4 of this subpart. A hydrocarbon-fuel-
based emissions control system is assumed not to form CF4
from F2 if the electronics manufacturer can certify that the
rate of conversion from F2 to CF4 is <0.1% for
that hydrocarbon-fuel-based emissions control system.
[GRAPHIC] [TIFF OMITTED] TP21JN22.016
Where:
EABCF4 = Emissions of CF4 from hydrocarbon-
fuel-based emissions control systems when direct reaction between
hydrocarbon fuel and F2 is not certified not to occur by
the emissions control system manufacturer or electronics
manufacturer, kg.
CF2,j = Amount of F2 consumed for process type
or sub-type j, as calculated in Equation I-13 of this subpart, on a
fab basis (kg).
UF2,j = Process utilization rate for F2 for
process type or sub-type j (expressed as a decimal fraction).
AF2,j = Within process sub-type or process type j,
fraction of F2 used in process tools with hydrocarbon-
fuel-based abatement systems that are not certified not to form
CF4, on a fab basis, where the numerator is the number of
tools that are equipped with hydrocarbon-fuel-based emissions
control systems that are not certified not to form CF4
that use F2 in process type j and the denominator is the
total number of tools in the fab that use F2 in process
type j (expressed as a decimal fraction).
UTF2,j = The average uptime factor of all abatement
systems connected to process tools in the fab using F2 in process
sub-type or process type j (expressed as a decimal fraction).
ABCF4,F2 = Mass fraction of F2 in process
exhaust gas that is converted into CF4 by direct reaction
with hydrocarbon fuel in a combustion abatement system. The default
value of ABCF4,F2=0.116.
CNF3,RPC = Amount of NF3 consumed in remote
plasma cleaning processes, as calculated in Equation I-13 of this
subpart, on a fab basis (kg).
BF2, NF3 = By-product formation rate of F2
created as a by-product per amount of NF3 (kg) consumed
in remote plasma cleaning processes (kg).
aNF3,RPC = Within remote plasma cleaning processes,
fraction of NF3 used in process tools with hydrocarbon-
fuel-based abatement systems that are not certified not to form
CF4, where the numerator is the number of tools running
remote plasma cleaning processes that are equipped with hydrocarbon-
fuel-based emissions control systems that are not certified not to
form CF4 that use NF3 and the denominator is
the total number of tools that run remote plasma clean processes in
the fab that use NF3 (expressed as decimal fraction).
UTNF3,RPC,F2 = The average uptime factor of all abatement
systems connected to process tools in the fab emitting by-product
gas F2, formed from input gas NF3 in remote
plasma cleaning processes, on a fab basis (expressed as a decimal
fraction). For this equation, UTNF3,RPC,F2 is assumed to
be equal to UTNF3,RPC as calculated in Equation I-15 of
this subpart.
j = Process type or sub-type.
* * * * *
(e) You must calculate the amount of input gas i consumed, on a fab
basis, for each process sub-type or process type j, using Equation I-13
of this subpart. Where a gas supply system serves more than one fab,
Equation I-13 is applied to that gas which has been apportioned to each
fab served by that system using the apportioning factors determined in
accordance with Sec. 98.94(c). If you elect to calculate emissions
using the stack test method in paragraph (i) of this section and to use
this paragraph to calculate the fraction each fluorinated input gas i
exhausted from tools with abatement systems and the fraction of each
by-product gas k exhausted from tools with abatement systems, you may
substitute ``The set of tools with abatement systems'' for ``Process
sub-type or process type'' in the definition of ``j'' in Equation I-13
of this subpart.
* * * * *
(i) Stack Test Method. As an alternative to the default emission
factor method in paragraph (a) of this section, you may calculate fab-
level fluorinated GHG emissions using fab-specific emission factors
developed from stack testing. In this case, you must comply with the
stack test method specified in paragraph (i)(3) of this section.
(1)-(2) [Reserved]
(3) Stack system stack test method. For each stack system in the
fab, measure the emissions of each fluorinated GHG from the stack
system by conducting an emission test. In addition, measure the fab-
specific consumption of each fluorinated GHG by the tools that are
vented to the stack systems tested. Measure emissions and consumption
of each fluorinated GHG as specified in Sec. 98.94(j). Develop fab-
specific emission factors and calculate fab-level fluorinated GHG
emissions using the procedures specified in paragraph (i)(3)(i) through
(viii) of this section. All emissions test data and procedures used in
developing emission factors must be documented and recorded according
to Sec. 98.97.
(i) You must measure the fab-specific fluorinated GHG consumption
of the tools that are vented to the stack systems during the emission
test as specified in Sec. 98.94(j)(3). Calculate the consumption for
each fluorinated GHG for the test period.
* * * * *
(iii) You must calculate a fab-specific emission factor for each
fluorinated GHG input gas consumed (in kg of fluorinated GHG emitted
per kg of input gas i consumed) in the tools that vent to stack
systems, as applicable, using Equations I-19A and I-19B or I-19A and I-
19c of this subpart. Use Equation I-19A to calculate the controlled
emissions for each fluorinated GHG that would result during the
sampling period if the utilization rate for the input gas were equal to
0.2 (Eimax,f). If [sum]sEi,s (the
total measured emissions of the fluorinated GHG across all stack
systems, calculated based on the results of Equation I-17) is less than
or equal to Eimax,f calculated in I-19A, use Equation I-19B
to calculate the emission factor for that fluorinated GHG. If
[sum]sEi,s is larger than the Eimax,f
calculated in I-19A, use Equation I-19C to calculate the emission
factor and treat the difference between the total measured emissions
[sum]sEi,s and the maximum expected controlled
emissions Eimax,f as a by-product of the other input gases,
using Equation I-20 of this subpart.
[[Page 37050]]
[GRAPHIC] [TIFF OMITTED] TP21JN22.017
Where:
Eimax,f = Maximum expected controlled emissions of gas i
from its use an input gas during the stack testing period, from fab
f (max kg emitted).
Activityif = Consumption of fluorinated GHG input gas i,
for fab f, in the tools vented to the stack systems being tested,
during the sampling period, as determined following the procedures
specified in Sec. 98.94(j)(3) (kg consumed).
UTf = The total uptime of all abatement systems for fab
f, during the sampling period, as calculated in Equation I-23 of
this subpart (expressed as decimal fraction). If the stack system
does not have abatement systems on the tools vented to the stack
system, the value of this parameter is zero.
aif = Fraction of input gas i emitted from tools with
abatement systems in fab f (expressed as a decimal fraction), as
calculated in Equation I-24C.
dif = Fraction of fluorinated GHG input gas i destroyed
or removed when fed into abatement systems by process tools in fab
f, as calculated in Equation I-24A of this subpart (expressed as
decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
[GRAPHIC] [TIFF OMITTED] TP21JN22.018
Where:
EFif = Emission factor for fluorinated GHG input gas i,
from fab f, representing 100 percent abatement system uptime (kg
emitted/kg input gas consumed).
Eis = Mass emission of fluorinated GHG input gas i from
stack system s during the sampling period (kg emitted).
Activityif = Consumption of fluorinated GHG input gas i,
for fab f during the sampling period, as determined following the
procedures specified in Sec. 98.94(j)(3) (kg consumed).
UTf = The total uptime of all abatement systems for fab
f, during the sampling period, as calculated in Equation I-23 of
this subpart (expressed as decimal fraction). If the stack system
does not have abatement systems on the tools vented to the stack
system, the value of this parameter is zero.
aif = Fraction of fluorinated GHG input gas i exhausted
from tools with abatement systems in fab f (expressed as a decimal
fraction), as calculated in Equation I-24C.
dif = Fraction of fluorinated GHG input gas i destroyed
or removed when fed into abatement systems by process tools in fab
f, as calculated in Equation I-24A of this subpart (expressed as
decimal fraction). If the stack system does not have abatement
systems on the tools vented to the stack system, the value of this
parameter is zero.
f = Fab.
i = Fluorinated GHG input gas.
s = Stack system.
[GRAPHIC] [TIFF OMITTED] TP21JN22.019
EFif = Emission factor for input gas i, from fab f,
representing a 20-percent utilization rate and a 100-percent
abatement system uptime (kg emitted/kg input gas consumed).
aif = Fraction of input gas i emitted from tools with
abatement systems in fab f (expressed as a decimal fraction), as
calculated in Equation I-24C.
dif = Fraction of fluorinated GHG input gas i destroyed
or removed when fed into abatement systems by process tools in fab
f, as calculated in Equation I-24A of this subpart (expressed as
decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
(iv) You must calculate a fab-specific emission factor for each
fluorinated GHG formed as a by-product (in kg of fluorinated GHG per kg
of total fluorinated GHG consumed) in the tools vented to stack
systems, as applicable, using Equation I-20 of this subpart. When
calculating the by-product emission factor for an input gas for which
[sum]sEi,s equals or exceeds Eimax,f,
exclude the consumption of that input gas from the term
``[sum](Activityif).''
[GRAPHIC] [TIFF OMITTED] TP21JN22.020
Where:
EFkf = Emission factor for fluorinated GHG by-product gas
k, from fab f, representing 100 percent abatement system uptime (kg
emitted/kg of all input gases consumed in tools vented to stack
systems).
Eks = Mass emission of fluorinated GHG by-product gas k,
emitted from stack system s, during the sampling period (kg
emitted).
Activityif = Consumption of fluorinated GHG input gas i
for fab f in tools vented to stack systems during the sampling
period as determined following the procedures specified in Sec.
98.94(j)(3) (kg consumed).
UTf = The total uptime of all abatement systems for fab
f, during the sampling period, as calculated in Equation I-23 of
this subpart (expressed as decimal fraction).
akif = Fraction of by-product k emitted from tools using
input gas i with abatement systems in fab f (expressed as a decimal
fraction), as calculated using Equation I-24D.
dkif = Fraction of fluorinated GHG by-product gas k
generated from input gas i destroyed or removed when fed into
abatement systems by process tools in fab f, as calculated in
Equation I-24B of this subpart (expressed as decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
k = Fluorinated GHG by-product gas.
s = Stack system.
(v) You must calculate annual fab-level emissions of each
fluorinated GHG consumed using Equation I-21 of this section.
[[Page 37051]]
[GRAPHIC] [TIFF OMITTED] TP21JN22.021
Where:
Eif = Annual emissions of fluorinated GHG input gas i
(kg/year) from the stack systems for fab f.
EFif = Emission factor for fluorinated GHG input gas i
emitted from fab f, as calculated in Equation I-19 of this subpart
(kg emitted/kg input gas consumed).
Cif = Total consumption of fluorinated GHG input gas i in
tools that are vented to stack systems, for fab f, for the reporting
year, as calculated using Equation I-13 of this subpart (kg/year).
UTf = The total uptime of all abatement systems for fab
f, during the reporting year, as calculated using Equation I-23 of
this subpart (expressed as a decimal fraction).
aif = Fraction of fluorinated GHG input gas i emitted
from tools with abatement systems in fab f (expressed as a decimal
fraction), as calculated using Equation I-24C or I-24D.
dif = Fraction of fluorinated GHG input gas i destroyed
or removed when fed into abatement systems by process tools in fab f
that are included in the stack testing option, as calculated in
Equation I-24A of this subpart (expressed as decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
(vi) You must calculate annual fab-level emissions of each
fluorinated GHG by-product formed using Equation I-22 of this section.
[GRAPHIC] [TIFF OMITTED] TP21JN22.022
Where:
Ekf = Annual emissions of fluorinated GHG by-product gas
k (kg/year) from the stack for fab f.
EFkf = Emission factor for fluorinated GHG by-product gas
k, emitted from fab f, as calculated in Equation I-20 of this
subpart (kg emitted/kg of all fluorinated input gases consumed).
Cif = Total consumption of fluorinated GHG input gas i in
tools that are vented to stack systems, for fab f, for the reporting
year, as calculated using Equation I-13 of this subpart.
UTf = The total uptime of all abatement systems for fab
f, during the reporting year as calculated using Equation I-23 of
this subpart (expressed as a decimal fraction).
akif = Estimate of fraction of fluorinated GHG by-product
gas k emitted in fab f from tools using input gas i with abatement
systems (expressed as a decimal fraction), as calculated using
Equation I-24D.
dkif = Fraction of fluorinated GHG by-product k generated
from input gas i destroyed or removed when fed into abatement
systems by process tools in fab f that are included in the stack
testing option, as calculated in Equation I-24B of this subpart
(expressed as decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
k = Fluorinated GHG by-product
* * * * *
(viii) When using the stack testing option described in paragraph
(i) of this section and when using more than one DRE for the same input
gas i or by-product gas k, you must calculate the weighted-average
fraction of each fluorinated input gas i and each fluorinated by-
product gas k that has more than one DRE and that is destroyed or
removed in abatement systems for each fab f, as applicable, by using
Equation I-24A (for input gases) and Equation I-24B (for by-product
gases) of this subpart and Table I-18 of this subpart. If default
values are not available in Table I-18 for a particular input gas, you
must use a value of 10.
[GRAPHIC] [TIFF OMITTED] TP21JN22.023
[GRAPHIC] [TIFF OMITTED] TP21JN22.024
Where:
dif = The average weighted fraction of fluorinated GHG
input gas i destroyed or removed when fed into abatement systems by
process tools in fab f (expressed as a decimal fraction).
dkif = The average weighted fraction of fluorinated GHG
by-product gas k generated from input gas i that is destroyed or
removed when fed into abatement systems by process tools in fab f
(expressed as a decimal fraction).
ni,p,DREy = Number of tools that use gas i, that run
chamber cleaning process p, and that are equipped with abatement
systems for gas i that have the DRE DREy.
mi,q,DREz = Number of tools that use gas i, that run etch
and/or wafer cleaning processes, and that are equipped with
abatement systems for gas i that have the DRE DREz.
ni,p,a = Total number of tools that use gas i, run
chamber cleaning process type p, and that are equipped with
abatement systems for gas i.
mi,q,a = Total number of tools that use gas i, run etch
and/or wafer cleaning processes, and that are equipped with
abatement systems for gas i.
nk,i,p,DREy = Number of tools that use gas i, generate
by-product k, that run chamber cleaning process p, and that are
equipped with abatement systems for gas i that have the DRE DREy.
mk,i,q,DREz = Number of tools that use gas i, generate
by-product k, that run etch and/or wafer cleaning processes, and
that are equipped with abatement systems for gas i that have the DRE
DREz.
nk,i,p,a = Total number of tools that use gas i, generate
by-product k, run chamber cleaning process type p, and that are
equipped with abatement systems for gas i.
mk,i,q,a = Total number of tools that use gas i, generate
by-product k, run etch and/or wafer cleaning processes, and that are
equipped with abatement systems for gas i.
[gamma]i,p = Default factor reflecting the ratio of
uncontrolled emissions per tool of input gas i from tools running
process sub-type p processes to uncontrolled emissions per tool of
input gas i from process tools running process type q processes.
[gamma]k,i,p = Default factor reflecting the ratio of
uncontrolled emissions per tool of input gas i from tools running
process sub-type p processes to uncontrolled emissions
[[Page 37052]]
per tool of input gas i from process tools running process type q
processes.
DREy = Default or alternative certified DRE for gas i for
abatement systems connected to CVD tool.
DREz = Default or alternative certified DRE for gas i for
abatement systems connected to etching and/or wafer cleaning tool.
p = Chamber cleaning process sub-type.
q = Reference process type. There is one process type q that
consists of the combination of etching and/or wafer cleaning
processes.
f = Fab.
i = Fluorinated GHG input gas.
(ix) When using the stack testing method described in this
paragraph (i), you must calculate the fraction each fluorinated input
gas i exhausted in fab f from tools with abatement systems and the
fraction of each by-product gas k exhausted from tools with abatement
systems, as applicable, by following either the procedure set forth in
paragraph (i)(3)(ix)(A) of this section or the procedure set forth in
paragraph (i)(3)(ix)(B) of this section.
(A) Use Equation I-24C (for input gases) and Equation I-24D (for
by-product gases) and Table I-18 of this subpart. If default values are
not available in Table I-18 for a particular input gas, you must use a
value of 10.
[GRAPHIC] [TIFF OMITTED] TP21JN22.025
Where:
aif = Fraction of fluorinated input gas i exhausted from
tools with abatement systems in fab f (expressed as a decimal
fraction).
ni,p,a = Number of tools that use gas i, that run chamber
cleaning process sub-type p, and that are equipped with abatement
systems for gas i.
mi,q,a = Number of tools that use gas i, that run etch
and/or wafer cleaning processes, and that are equipped with
abatement systems for gas i.
ni,p = Total number of tools using gas i and running
chamber cleaning process sub-type p.
mi,q = Total number of tools using gas i and running etch
and/or wafer cleaning processes.
[gamma]i,p = Default factor reflecting the ratio of
uncontrolled emissions per tool of input gas i from tools running
process type p processes to uncontrolled emissions per tool of input
gas i from process tools running process type q processes.
p = Chamber cleaning process sub-type.
q = Reference process type. There is one process type q that
consists of the combination of etching and/or wafer cleaning
processes.
[GRAPHIC] [TIFF OMITTED] TP21JN22.026
Where:
ak,i,f = Fraction of by-product gas k exhausted from
tools using input gas i with abatement systems in fab f (expressed
as a decimal fraction).
nk,i,p,a = Number of tools that exhaust by-product gas k
from input gas i, that run chamber cleaning process p, and that are
equipped with abatement systems for gas k.
mk,i,q,a = Number of tools that exhaust by-product gas k
from input gas i, that run etch and/or wafer cleaning processes, and
that are equipped with abatement systems for gas k.
nk,i,p = Total number of tools emitting by-product k from
input gas i and running chamber cleaning process p.
mk,i,q = Total number of tools emitting by-product k from
input gas i and running etch and/or wafer cleaning processes.
[gamma]k,i,p = Default factor reflecting the ratio of
uncontrolled emissions per tool of by-product gas k from input gas i
from tools running chamber cleaning process p to uncontrolled
emissions per tool of by-product gas k from input gas i from process
tools running etch and/or wafer cleaning processes.
p = Chamber cleaning process sub-type.
q = Reference process type. There is one process type q that
consists of the combination of etching and/or wafer cleaning
processes.
(B) Use paragraph (e) of this section to apportion consumption of
gas i either to tools with abatement systems and tools without
abatement systems or to each process type or sub-type, as applicable.
If you apportion consumption of gas i to each process type or sub-type,
calculate the fractions of input gas i and by-product gas k formed from
gas i that are exhausted from tools with abatement systems based on the
numbers of tools with and without abatement systems within each process
type or sub-type.
(4) Method to calculate emissions from fluorinated GHGs that are
not tested. Calculate emissions from consumption of each intermittent
low-use fluorinated GHG as defined in Sec. 98.98 of this subpart using
the default utilization and by-product formation rates provided in
Table I-11, I-12, I-13, I-14, or I-15 of this subpart, as applicable,
and by using Equations I-8A, I-8B, I-9, and I-13 of this subpart. If a
fluorinated GHG was not being used during the stack testing and does
not meet the definition of intermittent low-use fluorinated GHG in
Sec. 98.98, then you must test the stack systems associated with the
use of that fluorinated GHG at a time when that gas is in use at a
magnitude that would allow you to determine an emission factor for that
gas according to the procedures specified in paragraph (i)(3) of this
section.
0
27. Amend Sec. 98.94 by revising paragraphs (c) introductory text,
(e), (f)(3), (f)(4) introductory text, (f)(4)(iii), (j)(1) introductory
text, (j)(1)(i), (j)(3) introductory text, (j)(5)(i), and (j)(5)(ii)
introductory text and by removing and reserving paragraphs (j)(6) and
(j)(8)(v).
The revisions read as follows:
Sec. 98.94 Monitoring and QA/QC requirements.
* * * * *
(c) You must develop apportioning factors for fluorinated GHG and
N2O consumption (including the fraction of gas consumed by
process tools connected to abatement systems as in Equations I-8A, I-
8B, I-9, and I-10 of this subpart), to use in the equations of this
subpart for each input gas i, process sub-type, process type, stack
system, and fab as appropriate, using a fab-specific engineering model
that is documented in your site GHG Monitoring Plan as required under
Sec. 98.3(g)(5). This model must be based on a quantifiable metric,
such as wafer passes or wafer starts, or direct measurement of input
gas consumption as specified in paragraph (c)(3) of this section. To
verify your model, you must demonstrate its precision and accuracy by
adhering to the requirements in paragraphs (c)(1) and (2) of this
section.
* * * * *
(e) If you use hydrocarbon-fuel-based emissions control systems to
control
[[Page 37053]]
emissions from tools that use either NF3 as an input gas in
remote plasma cleaning processes or F2 as an input gas in
any process, and if you use a value less than 1 for either
aF2,j or aNF3,RPC in Equation I-9, you must
certify and document that the model for each of the systems for which
you are claiming that it does not form CF4 from
F2 has been tested and verified to produce less than 0.1%
CF4 from F2 and that each of the systems is
installed, operated, and maintained in accordance with the directions
of the emissions control system manufacturer. Hydrocarbon-fuel-based
emissions control systems include but are not limited to abatement
systems as defined in Sec. 98.98 that are hydrocarbon-fuel-based. The
rate of conversion from F2 to CF4 must be
measured using a scientifically sound, industry-accepted method that
accounts for dilution through the abatement device, such as EPA 430-R-
10-003, adjusted to calculate the rate of conversion from F2
to CF4 rather than the DRE. Either the hydrocarbon-fuel-
based emissions control system manufacturer or the electronics
manufacturer may perform the measurement. The flow rate of
F2 into the tested emissions control system(s) may be
metered using a calibrated mass flow controller.
(f) * * *
(3) If you use default destruction and removal efficiency values in
your emissions calculations under Sec. 98.93(a), (b), and/or (i), you
must certify and document that the abatement systems at your facility
for which you use default destruction or removal efficiency values are
specifically designed for fluorinated GHG or N2O abatement,
as applicable, and that the abatement system has been tested by the
abatement system manufacturer based on the methods specified in
paragraph (f)(3)(i) of this section and verified to meet (or exceed)
the default destruction or removal efficiency in Table I-16 for the
fluorinated GHG or N2O under worst-case flow conditions as
defined in paragraph (f)(3)(ii) of this section. If you use a verified
destruction and removal efficiency value that is lower than the default
in Table I-16 in your emissions calculations under Sec. 98.93(a), (b),
and/or (i), you must certify and document that the abatement systems at
your facility for which you use the verified destruction or removal
efficiency values are specifically designed for fluorinated GHG or
N2O abatement, as applicable, and that the abatement system
has been tested by the abatement system manufacturer based on the
methods specified in paragraph (f)(3)(i) of this section and verified
to meet or exceed the destruction or removal efficiency value used for
that fluorinated GHG or N2O under worst-case flow conditions
as defined in paragraph (f)(3)(ii) of this section. If you elect to
calculate fluorinated GHG emissions using the stack test method under
Sec. 98.93(i), you must also certify that you have included and
accounted for all abatement systems designed for fluorinated GHG
abatement and any respective downtime in your emissions calculations
under Sec. 98.93(i)(3).
(i) For purposes of paragraph (f)(3) of this section, destruction
and removal efficiencies must be measured using a scientifically sound,
industry-accepted measurement methodology that accounts for dilution
through the abatement system, such as EPA 430-R-10-003 (incorporated by
reference, see Sec. 98.7).
(ii) Worst-case flow conditions are defined as the highest total
fluorinated GHG or N2O flows through each model of emissions
control systems (gas by gas and process type by process type across the
facility) and the highest total flow scenarios (with N2
dilution accounted for) across the facility during which the abatement
system is claimed to be operational.
(4) If you calculate and report controlled emissions using neither
the default destruction or removal efficiency values in Table I-16 of
this subpart nor a manufacturer verified lower destruction or removal
efficiency values per paragraph (f)(3) of this section, you must use an
average of properly measured destruction or removal efficiencies for
each gas and process sub-type or process type combination, as
applicable, determined in accordance with procedures in paragraphs
(f)(4)(i) through (vi) of this section. This includes situations in
which your fab employs abatement systems not specifically designed for
fluorinated GHG or N2O abatement and you elect to reflect
emission reductions due to these systems. You must not use a default
value from Table I-16 of this subpart for any abatement system not
specifically designed for fluorinated GHG and N2O abatement,
for any abatement system not certified to meet the default value from
Table I-16, or for any gas and process type combination for which you
have measured the destruction or removal efficiency according to the
requirements of paragraphs (f)(4)(i) through (vi) of this section.
* * * * *
(iii) If you elect to take credit for abatement system destruction
or removal efficiency before completing testing on 20 percent of the
abatement systems for that gas and process sub-type or process type
combination, as applicable, you must use default destruction or removal
efficiencies or a verified destruction or removal efficiency, if
verified at a lower value, for a gas and process type combination. You
must not use a default value from Table I-16 of this subpart for any
abatement system not specifically designed for fluorinated GHG and
N2O abatement, and must not take credit for abatement system
destruction or removal efficiency before completing testing on 20
percent of the abatement systems for that gas and process sub-type or
process type combination, as applicable. Following testing on 20
percent of abatement systems for that gas and process sub-type or
process type combination, you must calculate the average destruction or
removal efficiency as the arithmetic mean of all test results for that
gas and process sub-type or process type combination, until you have
tested at least 30 percent of all abatement systems for each gas and
process sub-type or process type combination. After testing at least 30
percent of all systems for a gas and process sub-type or process type
combination, you must use the arithmetic mean of the most recent 30
percent of systems tested as the average destruction or removal
efficiency. You may include results of testing conducted on or after
January 1, 2011 for use in determining the site-specific destruction or
removal efficiency for a given gas and process sub-type or process type
combination if the testing was conducted in accordance with the
requirements of paragraph (f)(4)(i) of this section.
* * * * *
(j) * * *
(1) Stack system testing. Conduct an emissions test for each stack
system according to the procedures in paragraphs (j)(1)(i) through (iv)
of this section.
(i) You must conduct an emission test during which the fab is
operating at a representative operating level, as defined in Sec.
98.98, and with the abatement systems connected to the stack system
being tested operating with at least 90 percent uptime, averaged over
all abatement systems, during the 8-hour (or longer) period for each
stack system, or at no less than 90 percent of the abatement system
uptime rate measured over the previous reporting year, averaged over
all abatement systems. Hydrocarbon-fuel-based emissions control systems
that are not certified not to form CF4 must operate
[[Page 37054]]
with at least 90 percent uptime during the test.
* * * * *
(3) Fab-specific fluorinated GHG consumption measurements. You must
determine the amount of each fluorinated GHG consumed by each fab
during the sampling period for all process tools connected to the stack
systems under Sec. 98.93(i)(3), according to the procedures in
paragraphs (j)(3)(i) and (ii) of this section.
* * * * *
(5) * * *
(i) Annual testing. You must conduct an annual emissions test for
each stack system unless you meet the criteria in paragraph (j)(5)(ii)
of this section to skip annual testing. Each set of emissions testing
for a stack system must be separated by a period of at least 2 months.
(ii) Criteria to test less frequently. After the first 3 years of
annual testing, you may calculate the relative standard deviation of
the emission factors for each fluorinated GHG included in the test and
use that analysis to determine the frequency of any future testing. As
an alternative, you may conduct all three tests in less than 3 calendar
years for purposes of this paragraph (j)(5)(ii), but this does not
relieve you of the obligation to conduct subsequent annual testing if
you do not meet the criteria to test less frequently. If the criteria
specified in paragraphs (j)(5)(ii)(A) and (B) of this section are met,
you may use the arithmetic average of the three emission factors for
each fluorinated GHG and fluorinated GHG byproduct for the current year
and the next 4 years with no further testing unless your fab operations
are changed in a way that triggers the re-test criteria in paragraph
(j)(8) of this section. In the fifth year following the last stack test
included in the previous average, you must test each of the stack
systems and repeat the relative standard deviation analysis using the
results of the most recent three tests (i.e., the new test and the two
previous tests conducted prior to the 4-year period). If the criteria
specified in paragraphs (j)(5)(ii)(A) and (B) of this section are not
met, you must use the emission factors developed from the most recent
testing and continue annual testing. You may conduct more than one test
in the same year, but each set of emissions testing for a stack system
must be separated by a period of at least 2 months. You may repeat the
relative standard deviation analysis using the most recent three tests,
including those tests conducted prior to the 4-year period, to
determine if you are exempt from testing for the next 4 years.
* * * * *
0
28. Amend Sec. 98.96 by:
0
a. Revising paragraphs (c)(1) and (2), (o), (p)(2), and (q)(2) and (3);
0
b. Revising Equation I-28 in paragraph (r)(2);
0
c. Revising parameters ``Cif,'' ``EFkf,''
``af,'' and ``dkf'' of Equation I-28 in paragraph
(r)(2); and
0
d. Revising paragraphs (w)(2), (y) introductory text, (y)(1), (y)(2)(i)
and (iv), and (y)(4).
The revisions read as follows:
Sec. 98.96 Data reporting requirements.
* * * * *
(c) * * *
(1) When you use the procedures specified in Sec. 98.93(a) of this
subpart, each fluorinated GHG emitted from each process type for which
your fab is required to calculate emissions as calculated in Equations
I-6, I-7, and I-9 of this subpart.
(2) When you use the procedures specified in Sec. 98.93(a), each
fluorinated GHG emitted from each process type or process sub-type as
calculated in Equations I-8A and I-8B of this subpart, as applicable.
* * * * *
(o) For all hydrocarbon-fuel-based emissions control systems that
are used to control emissions from tools that use either NF3
as an input gas in remote plasma clean processes or F2 as an
input gas in any process type or sub-type, certification that the rate
of conversion from F2 to CF4 is <0.1% and that
the systems are installed, operated, and maintained in accordance with
the directions of the emissions control system manufacturer, unless the
emissions control system is included in the count of systems not
certified to not form CF4 in Equation I-9. Hydrocarbon-fuel-
based emissions control systems include but are not limited to
abatement systems as defined in Sec. 98.98 that are hydrocarbon-fuel-
based. If you make the certification based on your own testing, you
must certify that you tested the model of the system according to the
requirements specified in Sec. 98.94(e). If you make the certification
based on testing by the emissions control system manufacturer, you must
provide documentation from the emissions control system manufacturer
that the rate of conversion from F2 to CF4 is
<0.1% when tested according to the requirements specified in Sec.
98.94(e).
(p) * * *
(2) The basis of the destruction or removal efficiency being used
(default, manufacturer verified, or site-specific measurement according
to Sec. 98.94(f)(4)(i)) for each process sub-type or process type and
for each gas.
(q) * * *
(2) If you use default destruction or removal efficiency values in
your emissions calculations under Sec. 98.93(a), (b), or (i),
certification that the site maintenance plan for abatement systems for
which emissions are being reported contains manufacturer's
recommendations and specifications for installation, operation, and
maintenance for each abatement system. To use the default or lower
manufacturer-verified destruction or removal efficiency values,
operation of the abatement system must be within manufacturer's
specifications, including but not limited to specifications on vacuum
pumps' purges, fuel and oxidizer settings, supply and exhaust flows and
pressures, and utilities to the emissions control equipment including
fuel gas flow and pressure, calorific value, and water quality, flow
and pressure.
(3) If you use default destruction or removal efficiency values in
your emissions calculations under Sec. 98.93(a), (b), and/or (i),
certification that the abatement systems for which emissions are being
reported were specifically designed for fluorinated GHG or
N2O abatement, as applicable. You must support this
certification by providing abatement system supplier documentation
stating that the system was designed for fluorinated GHG or
N2O abatement, as applicable, and supply the destruction or
removal efficiency value at which each abatement system is certified
for the fluorinated GHG or N2O abated, as applicable. You
may only use the default destruction or removal efficiency value if the
abatement system is verified to meet or exceed the destruction or
removal efficiency default value in Table I-16. If the system is
verified at a destruction or removal efficiency value lower than the
default value, you may use the verified value.
* * * * *
(r) * * *
(2) * * *
[[Page 37055]]
[GRAPHIC] [TIFF OMITTED] TP21JN22.027
* * * * *
Cif = Total consumption of fluorinated GHG input gas i,
of tools vented to stack systems, for fab f, for the reporting year,
expressed in metric ton CO2e, which you used to calculate
total emissions according to the procedures in Sec. 98.93(i)(3)
(expressed as a decimal fraction).
EFkf = Emission factor for fluorinated GHG by-product gas
k, emitted from fab f, as calculated in Equation I-20 of this
subpart (kg emitted/kg of all input gases consumed in tools vented
to stack systems).
akif = Fraction of fluorinated GHG by-product gas k
emitted in fab f from tools using input gas i with abatement systems
(expressed as a decimal fraction), as calculated using Equation I-
24D.
dik = Fraction of fluorinated GHG byproduct k destroyed
or removed in abatement systems connected to process tools in fab f,
as calculated from Equation I-24B of this subpart, which you used to
calculate total emissions according to the procedures in Sec.
98.93(i)(3) (expressed as a decimal fraction).
* * * * *
(w) * * *
(2) An inventory of all stack systems from which process
fluorinated GHG are emitted.
* * * * *
(y) If your semiconductor manufacturing facility manufactures
wafers greater than 150 mm and emits more than 40,000 metric ton
CO2e of GHG emissions, based on your most recently submitted
annual report as required in paragraph (c) of this section, from the
electronics manufacturing processes subject to reporting under this
subpart, you must prepare and submit a technology assessment report
every five years to the Administrator (or an authorized representative)
that meets the requirements specified in paragraphs (y)(1) through (6)
of this section. Any other semiconductor manufacturing facility may
voluntarily submit this report to the Administrator. If your
semiconductor manufacturing facility manufactures only 150 mm or
smaller wafers, you are not required to prepare and submit a technology
assessment report, but you are required to prepare and submit a report
if your facility begins manufacturing wafers 200 mm or larger during or
before the calendar year preceding the year the technology assessment
report is due. If your semiconductor manufacturing facility is no
longer required to report to the GHGRP under subpart I due to the
cessation of semiconductor manufacturing as described in Sec.
98.2(i)(3), you are not required to submit a technology assessment
report.
(1) The first technology assessment report due after January 1,
2023 is due on March 31, 2025, and subsequent reports must be delivered
every 5 years no later than March 31 of the year in which it is due.
(2) * * *
(i) It must describe how the gases and technologies used in
semiconductor manufacturing using 200 mm and 300 mm wafers in the
United States have changed in the past 5 years and whether any of the
identified changes are likely to have affected the emissions
characteristics of semiconductor manufacturing processes in such a way
that the default utilization and by-product formation rates or default
destruction or removal efficiency factors of this subpart may need to
be updated.
* * * * *
(iv) It must provide any utilization and byproduct formation rates
and/or destruction or removal efficiency data that have been collected
in the previous 5 years that support the changes in semiconductor
manufacturing processes described in the report. Any utilization or
byproduct formation rate data submitted must be reported using all of
the methods specified in paragraphs (y)(2)(iv)(A) through (C) of this
section if multiple fluorinated input gases are used. If only one
fluorinated input gas is fed into the process, you must use Equations
I-29a and I-29b. The report must include the input gases used and
measured, the utilization rates measured, the byproduct formation rates
measured, the process type, the process subtype for chamber clean
processes, the wafer size, and the methods used for the measurements.
The report must also specify the method used to calculate each reported
utilization and by-product formation rate, and provide a unique record
number for each data set. For any destruction or removal efficiency
data submitted, the report must include the input gases used and
measured, the destruction and removal efficiency measured, the process
type, the methods used for the measurements, and whether the abatement
system is specifically designed to abate the gas measured under the
operating condition used for the measurement.
(A) Dominant gas method. Use Equation I-29a to calculate the input
gas emission factor (1-Uij) for each input gas in a single
test. If the result of Equation I-29a exceeds 0.8 for an F-GHG, you
must instead use Equation I-29c to calculate the input gas emission
factor for that F-GHG and Equation I-29d to calculate the by-product
formation rate for that F-GHG from the other input F-GHGs. To calculate
by-product emission factors for all other measured F-GHGs, use Equation
I-29b and assign all measured by-products to the dominant gas. The
dominant gas is the carbon-containing input F-GHG fed into the process
in the largest quantity (mass). If there are no carbon containing input
F-GHGs, the dominant gas is the input F-GHG with the largest input
mass.
[GRAPHIC] [TIFF OMITTED] TP21JN22.028
Where:
Uij = Process utilization rate for fluorinated GHG i,
process type j.
Ei = The mass emissions of input gas i.
Massi = The mass of input gas i fed into the Process.
i = Fluorinated GHG input gas i.
[GRAPHIC] [TIFF OMITTED] TP21JN22.029
[[Page 37056]]
Where:
BEFki = By-product formation rate for gas k from input
gas i, where gas k is not an input gas.
Ek = The mass emissions of by-product gas k.
Massi = The mass of input gas i where i is the dominant
gas, as defined in (A).
i = Fluorinated GHG input gas i.
k = By-product gas k.
[GRAPHIC] [TIFF OMITTED] TP21JN22.030
Where:
Uij = Process utilization rate for fluorinated GHG i, process type
j.
[GRAPHIC] [TIFF OMITTED] TP21JN22.031
Where:
BEFijg = By-product formation rate for gas i from input
gas g for process type j.
Ei = The mass emissions of input gas i.
Massi = The mass of input gas i where i is the dominant
gas, as defined in (A).
Massg = The mass of input gas g fed into the process,
where g does not equal input gas i.
i = Fluorinated GHG.
g = Fluorinated GHG input gas, where gas g is not equal to gas i.
j = Process type.
(B) All-input gas method. Use Equation I-30a to calculate the input
gas emission factor (1-Uij) for each input gas in a single
test. If the result of Equation I-30a exceeds 0.8 for an F-GHG, you
must use Equation I-30c to calculate the input gas emission factor for
that F-GHG and Equation I-30d to calculate the by-product formation
rate for that F-GHG from the other input gases. Use Equation I-30b to
calculate the by-product formation rates from each input gas for F-GHGs
that are not input gases. If a test uses a cleaning or etching gas that
does not contain carbon in combination with a cleaning or etching gas
that does contain carbon and the process chamber is not used to etch or
deposit carbon-containing films, you may elect to assign carbon
containing by-products only to the carbon-containing input gases. If
you choose to assign carbon containing by-products only to carbon-
containing input gases, remove the input mass of the non-carbon
containing gases from the sum of Massi and the sum of
Massg in Equations I-30b and I-30d, respectively.
[GRAPHIC] [TIFF OMITTED] TP21JN22.032
Where:
Uij = Process utilization rate for fluorinated GHG i,
process type j.
Ei = The mass emissions of input gas i.
Massi = The mass of input gas i fed into the Process.
i = Fluorinated GHG.
j = Process type.
[GRAPHIC] [TIFF OMITTED] TP21JN22.033
Where:
BEFkji = By-product formation rate for gas k from input
gas i, for process type j, where gas k is not an input gas.
Ek = The mass emissions of by-product gas k.
Massi = The mass of input gas i fed into the Process.
i = Fluorinated GHG.
j = Process type.
k = Fluorinated GHG by-product.
[GRAPHIC] [TIFF OMITTED] TP21JN22.034
Where:
Uij = Process utilization rate for fluorinated GHG i, process type
j.
[GRAPHIC] [TIFF OMITTED] TP21JN22.035
Where:
BEFijg = By-product formation rate for gas i from input
gas g for process type j.
Ei = The mass emissions of input gas i.
Massi = The mass of input gas i fed into the process.
Massg = The mass of input gas g fed into the process,
where g does not equal input gas i.
i = Fluorinated GHG.
g = Fluorinated GHG input gas, where gas g is not equal to gas i.
j = Process type.
[[Page 37057]]
(C) Reference emission factor method. Calculate the input gas
emission factors and by-product formation rates from a test using
Equations I-31a and I-31b, and Table I-19 or I-20 of this subpart. In
this case, use Equation I-31a to calculate the input gas emission
factors and use Equation I-31b and I-30b to calculate the by-product
formation rates.
[GRAPHIC] [TIFF OMITTED] TP21JN22.036
Where:
Uij = Process utilization rate for fluorinated GHG i,
process type j.
Uijr = Reference process utilization rate for fluorinated
GHG i, process type j, for input gas i, using Table I-19 or I-20 of
this subpart as appropriate.
Ei = The mass emissions of input gas i.
Massi = The mass of gas i fed into the process.
Massg = The mass of input gas g fed into the process,
where g does not equal input gas i.
BEFijgr = Reference by-product formation rate for gas i
from input gas g for process type j, using Table I-19.
i = Fluorinated GHG.
g = Fluorinated GHG input gas, where gas g is not equal to gas i.
r = Reference data.
[GRAPHIC] [TIFF OMITTED] TP21JN22.037
Where:
BEFijg = By-product formation rate for gas i from input
gas g for process type j, where gas i is also an input gas.
BEFijgr = By-product formation rate for gas i from input
gas g for process type j from Table I-19 or I-20 of this subpart, as
appropriate.
Uijr = Process utilization rate for fluorinated GHG i,
process type j, for input gas i, using Table I-19 or I-20 of this
subpart, as appropriate.
Ei = The mass emissions of input gas i.
Massi = The mass of gas i fed into the process.
Massg = The mass of input gas g fed into the process,
where g does not equal input gas i.
i = Fluorinated GHG.
j = Process type.
g = Fluorinated GHG input gas, where gas g is not equal to gas i.
r = Reference data.
* * * * *
(4) Multiple semiconductor manufacturing facilities may submit a
single consolidated technology assessment report as long as the
facility identifying information in Sec. 98.3(c)(1) and the
certification statement in Sec. 98.3(c)(9) is provided for each
facility for which the consolidated report is submitted.
* * * * *
0
29. Amend Sec. 98.97 by:
0
a. Revising paragraphs (b), (d)(1)(iii), (d)(3), (d)(5)(i), (d)(6) and
(7), and (d)(9)(i) and (ii);
0
b. Removing and reserving paragraph (i)(1); and
0
c. Revising paragraphs (i)(5) and (9) and (k).
The revisions read as follows:
Sec. 98.97 Records that must be retained.
* * * * *
(b) If you use hydrocarbon-fuel-based emissions control systems to
control emissions from tools that use either NF3 as an input
gas in remote plasma cleaning processes or F2 as an input
gas in any process, and if you use a value less than 1 for either
aF2,j or aNF3,RPC in Equation I-9, certification
and documentation that the model for each of the systems that you claim
does not form CF4 from F2 has been tested and
verified to produce less than 0.1% CF4 from F2,
and certification that the site maintenance plan includes the emission
control system manufacturer's recommendations and specifications for
installation, operation, and maintenance of those systems. If you are
relying on your own testing to make the certification that the model
produces less than 0.1% CF4 from F2, the
documentation must include the model tested, the method used to perform
the testing (e.g., EPA 430-R-10-003, modified to calculate the
formation rate of CF4 from F2 rather than the
DRE), complete documentation of the results of any initial and
subsequent tests, and a final report similar to that specified in EPA
430-R-10-003, with appropriate adjustments to reflect the measurement
of the formation rate of CF4 from F2 rather than
the DRE. If you are relying on testing by the emissions control system
manufacturer to make the to make the certification that the system
produces less than 0.1% CF4 from F2, the
documentation must include the model tested, the method used to perform
the testing, and the results of the test.
* * * * *
(d) * * *
(1) * * *
(iii) If you use either default destruction or removal efficiency
values or certified destruction or removal efficiency values that are
lower than the default values in your emissions calculations under
Sec. 98.93(a), (b), and/or (i), certification that the abatement
systems for which emissions are being reported were specifically
designed for fluorinated GHG and N2O abatement, as required
under Sec. 98.94(f)(3), certification that the site maintenance plan
includes the abatement system manufacturer's recommendations and
specifications for installation, operation, and maintenance, and the
certified destruction and removal efficiency values for all applicable
abatement systems. For abatement systems purchased after January 1,
2023, also include records of the method used to measure the
destruction and removal efficiency values.
* * * * *
(3) Where either the default destruction or removal efficiency
value or a certified destruction or removal efficiency value that is
lower than the default is used, documentation from the abatement system
supplier describing the equipment's designed purpose and
[[Page 37058]]
emission control capabilities for fluorinated GHG and N2O.
* * * * *
(5) * * *
(i) The number of abatement systems of each manufacturer, and model
numbers, and the manufacturer's certified fluorinated GHG and
N2O destruction or removal efficiency, if any.
* * * * *
(6) Records of all inputs and results of calculations made
accounting for the uptime of abatement systems used during the
reporting year, in accordance with Equations I-15 or I-23 of this
subpart, as applicable. The inputs should include an indication of
whether each value for destruction or removal efficiency is a default
value, lower manufacturer verified value, or a measured site-specific
value.
(7) Records of all inputs and results of calculations made to
determine the average weighted fraction of each gas destroyed or
removed in the abatement systems for each stack system using Equations
I-24A and I-24B of this subpart, if applicable. The inputs should
include an indication of whether each value for destruction or removal
efficiency is a default value, lower manufacturer-verified value, or a
measured site-specific value.
* * * * *
(9) * * *
(i) The site maintenance plan for abatement systems must be based
on the abatement system manufacturer's recommendations and
specifications for installation, operation, and maintenance if you use
default or lower-manufacturer verified destruction and removal
efficiency values in your emissions calculations under Sec. 98.93(a),
(b), and/or (i). If the manufacturer's recommendations and
specifications for installation, operation, and maintenance are not
available, you cannot use default destruction and removal efficiency
values or lower manufacturer verified value in your emissions
calculations under Sec. 98.93(a), (b), and/or (i). If you use an
average of properly measured destruction or removal efficiencies
determined in accordance with the procedures in Sec. 98.94(f)(4)(i)
through (vi), the site maintenance plan for abatement systems must be
based on the abatement system manufacturer's recommendations and
specifications for installation, operation, and maintenance, where
available. If you deviate from the manufacturer's recommendations and
specifications, you must include documentation that demonstrates how
the deviations do not negatively affect the performance or destruction
or removal efficiency of the abatement systems.
(ii) The site maintenance plan for abatement systems must include a
defined preventative maintenance process and checklist. Preventative
maintenance must include, but is not limited to, calibration of pump
purge flow indicators. Pump purge flow indicators must be calibrated
each time a vacuum pump is serviced or exchanged.
* * * * *
(i) * * *
(5) The fab-specific emission factor and the calculations and data
used to determine the fab-specific emission factor for each fluorinated
GHG and by-product, as calculated using Equations I-19A, I-19B, I-19C
and I-20 of Sec. 98.93(i)(3).
* * * * *
(9) The number of tools vented to each stack system in the fab and
all inputs and results for the calculations accounting for the fraction
of gas exhausted through abatement systems using Equations I-24C and I-
24D.
* * * * *
(k) Annual gas consumption for each fluorinated GHG and
N2O as calculated in Equation I-11 of this subpart,
including where your fab used less than 50 kg of a particular
fluorinated GHG or N2O used at your facility for which you
have not calculated emissions using Equations I-6, I-7, I-8A, I-8B, I-
9, I-10, I-21, or I-22 of this subpart, the chemical name of the GHG
used, the annual consumption of the gas, and a brief description of its
use.
* * * * *
0
30. Amend Sec. 98.98 by adding in alphabetical order a definition for
``Hydrocarbon-fuel based emission control systems'' and revising the
definition of ``Operational mode'' to read as follows:
Sec. 98.98 Definitions.
* * * * *
Hydrocarbon-fuel based emission control systems means a hydrocarbon
fuel based combustion device or equipment that is designed to destroy
or remove gas emissions in exhaust streams via combustion from one or
more electronics manufacturing production processes, and includes both
emission control systems that are and are not designed to destroy or
remove fluorinated GHGs or N2O.
* * * * *
Operational mode means the time in which an abatement system is
properly installed, maintained, and operated according to the site
maintenance plan for abatement systems as required in Sec. 98.94(f)(1)
and defined in Sec. 98.97(d)(9). This includes being properly operated
within the range of parameters as specified in the site maintenance
plan for abatement systems and within the range of parameters as
specified in the DRE certification documentation. An abatement system
is considered to not be in operational mode when it is not operated and
maintained according to the site maintenance plan for abatement systems
and within the range of parameters as specified in the DRE
certification documentation.
* * * * *
0
31. Revise table I-1 to subpart I of part 98 to read as follows:
Table I-1 to Subpart I of Part 98--Default Emission Factors for Manufacturing Capacity-Based Threshold Applicability Determination
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission factors EFi
------------------------------------------------------------------------------------------------
Product type c-C4F8
CF4 C2F6 CHF3 C3F8 NF3 SF6 N2O
--------------------------------------------------------------------------------------------------------------------------------------------------------
Semiconductors (kg/m\2\)............................... 0.9 1.0 0.04 NA 0.05 0.04 0.20 NA
LCD (g/m\2\)........................................... 0.65 NA 0.0024 0.00 NA 1.29 4.14 17.06
MEMS (kg/m\2\)......................................... 0.015 NA NA 0.076 NA NA 1.86 NA
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA denotes not applicable based on currently available information.
[[Page 37059]]
0
32. Redesignate table I-2 to subpart I of part 98 as table I-21 to
subpart I of part 98.
0
33. Add new table I-2 to subpart I of part 98 in numerical order to
read as follows:
Table I-2 to Subpart I of Part 98--Default Emission Factors for Gas
Consumption-Based Threshold Applicability Determination
------------------------------------------------------------------------
Process gas i
-------------------------------------
Fluorinated GHGs N2O
------------------------------------------------------------------------
1-Ui.............................. 0.8 1
BCF4.............................. 0.15 0
BC2F6............................. 0.05 0
------------------------------------------------------------------------
0
34. Revise table I-3 to subpart I of part 98 to read as follows:
Table I-3 to Subpart I of Part 98--Default Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for 150 mm and 200 mm
Wafer Sizes
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Process gas i
Process type/ sub-type -----------------------------------------------------------------------------------------------------------------------------------------------------------------
CF4 C2F6 CHF3 CH2F2 C2HF5 CH3F C3F8 C4F8 NF3 SF6 C4F6 C5F8 C4F8O
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
ETCHING/WAFER CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.......................... 0.73 0.72 0.51 0.13 0.064 0.70 NA 0.14 0.19 0.55 0.083 0.072 NA
BCF4.......................... NA 0.10 0.085 0.079 0.077 NA NA 0.11 0.0040 0.13 0.095 NA NA
BC2F6......................... 0.041 NA 0.035 0.025 0.024 0.0034 NA 0.037 0.025 0.11 0.073 0.014 NA
BC4F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BCHF3......................... 0.091 0.047 NA 0.049 NA NA NA 0.040 NA 0.0012 0.066 0.0039 NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CHAMBER CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
IN SITU PLASMA CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.......................... 0.92 0.55 NA NA NA NA 0.40 0.10 0.18 NA NA NA 0.14
BCF4.......................... NA 0.19 NA NA NA NA 0.20 0.11 0.14 NA NA NA 0.13
BC2F6......................... NA NA NA NA NA NA NA NA NA NA NA NA 0.045
BC3F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
REMOTE PLASMA CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.......................... NA NA NA NA NA NA NA NA 0.028 NA NA NA NA
BCF4.......................... NA NA NA NA NA NA NA NA 0.015 NA NA NA NA
BC2F6......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BF2........................... NA NA NA NA NA NA NA NA 0.5 NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
IN SITU THERMAL CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BCF4.......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC2F6......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA = Not applicable; i.e., there are no applicable default emission factor measurements for this gas. This does not necessarily imply that a particular gas is not used in or emitted
from a particular process sub-type or process type.
0
35. Revise table I-4 to subpart I of part 98 to read as follows:
Table I-4 to Subpart I of Part 98--Default Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for 300 mm and 450 mm
Wafer Size
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Process gas i
Process type/sub-type ----------------------------------------------------------------------------------------------------------------------------------------------------------
CF4 C2F6 CHF3 CH2F2 CH3F C3F8 C4F8 NF3 SF6 C4F6 C5F8 C4F8O
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
ETCHING/WAFER CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui................................. 0.65 0.80 0.37 0.20 0.30 0.30 0.18 0.16 0.30 0.15 0.10 NA
BCF4................................. NA 0.21 0.076 0.060 0.0291 0.21 0.045 0.044 0.033 0.059 0.11 NA
BC2F6................................ 0.058 NA 0.058 0.043 0.009 0.18 0.027 0.045 0.041 0.062 0.083 NA
BC4F8................................ 0.0046 NA 0.0027 0.054 0.0070 NA NA NA NA 0.0051 NA NA
BC3F8................................ NA NA NA NA NA NA NA NA NA NA 0.00012 NA
BCHF3................................ 0.012 NA NA 0.057 0.016 0.012 0.028 0.023 0.0039 0.017 0.0069 NA
[[Page 37060]]
BCH2F2............................... 0.005 NA 0.0024 NA 0.0033 NA 0.0021 0.00074 0.000020 0.000030 NA NA
BCH3F................................ 0.0061 NA 0.027 0.0036 NA 0.00073 0.0063 0.0080 0.0082 0.00065 NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CHAMBER CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
IN SITU PLASMA CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui................................. NA NA NA NA NA NA NA 0.20 NA NA NA NA
BCF4................................. NA NA NA NA NA NA NA 0.037 NA NA NA NA
BC2F6................................ NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8................................ NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
REMOTE PLASMA CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui................................. NA NA NA NA NA 0.063 NA 0.018 NA NA NA NA
BCF4................................. NA NA NA NA NA NA NA 0.037 NA NA NA NA
BC2F6................................ NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8................................ NA NA NA NA NA NA NA NA NA NA NA NA
BCHF3................................ NA NA NA NA NA NA NA 0.000059 NA NA NA NA
BCH2F2............................... NA NA NA NA NA NA NA 0.00088 NA NA NA NA
BCH3F................................ NA NA NA NA NA NA NA 0.0028 NA NA NA NA
BF2.................................. NA NA NA NA NA NA NA 0.5 NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
IN SITU THERMAL CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui................................. NA NA NA NA NA NA NA 0.28 NA NA NA NA
BCF4................................. NA NA NA NA NA NA NA 0.010 NA NA NA NA
BC2F6................................ NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8................................ NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA = Not applicable; i.e., there are no applicable default emission factor measurements for this gas. This does not necessarily imply that a particular gas is not used in or emitted
from a particular process sub-type or process type.
0
36. Revise table I-8 to subpart I of part 98 to read as follows:
Table I-8 to Subpart I of Part 98--Default Emission Factors (1-UN2O,j)
for N2O Utilization (UN2O,j)
------------------------------------------------------------------------
Manufacturing type/process type/wafer size N2O
------------------------------------------------------------------------
Semiconductor Manufacturing:
200 mm or Less:
CVD 1-Ui............................................ 1.0
Other Manufacturing Process 1-Ui................ 1.0
300 mm or greater:....................................
CVD 1-Ui............................................ 0.5
Other Manufacturing Process 1-Ui.................... 1.0
LCD Manufacturing:
CVD Thin Film Manufacturing 1-Ui...................... 0.63
All other N2O Processes................................. 1.0
------------------------------------------------------------------------
0
37. Revise table I-11 to subpart I of part 98 to read as follows:
Table I-11 to Subpart I of Part 98--Default Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for Use With the Stack Test Method
[150 mm and 200 mm Wafers]
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Process gas i
---------------------------------------------------------------------------------------------------------------------------------------------------------------------------
All processes NF3
CF4 C2F6 CHF3 CH2F2 C2HF5 CH3F C3F8 C4F8 NF3 Remote SF6 C4F6 C5F8 C4F8O
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui........................................................ 0.79 0.55 0.51 0.13 0.064 0.70 0.40 0.12 0.18 0.028 0.58 0.083 0.072 0.14
BCF4........................................................ NA 0.19 0.085 0.079 0.077 NA 0.20 0.11 0.11 0.015 0.13 0.095 NA 0.13
BC2F6....................................................... 0.027 NA 0.035 0.025 0.024 0.0034 NA 0.019 0.0059 NA 0.10 0.073 0.014 0.045
BC4F8....................................................... NA NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8....................................................... NA NA NA NA NA NA NA NA NA NA NA NA NA NA
BC5F8....................................................... 0.00077 NA 0.0012 NA NA NA NA 0.0043 NA NA NA NA NA NA
[[Page 37061]]
BCHF3....................................................... 0.060 0.0020 NA 0.049 NA NA NA 0.020 NA NA 0.0011 0.066 0.0039 NA
BF2......................................................... NA NA NA NA NA NA NA NA NA 0.50 NA NA NA NA
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA = Not applicable; i.e., there are no applicable emission factor measurements for this gas. This does not necessarily imply that a particular gas is not used in or emitted from a particular process sub-type or process type.
0
38. Revise table I-12 to subpart I of part 98 to read as follows:
Table I-12 to Subpart I of Part 98--Default Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for Use With the Stack Test Method
[300 mm and 450 mm Wafers]
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Process gas i
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
All processes C3F8 Remote NF3
CF4 C2F6 CHF3 CH2F2 CH3F C3F8 C4F8 NF3 Remote SF6 C4F6 C5F8 C4F8O
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..................................................... 0.65 0.80 0.37 0.20 0.30 0.30 0.063 0.183 0.19 0.018 0.30 0.15 0.100 NA
BCF4..................................................... NA 0.21 0.076 0.060 0.029 0.21 NA 0.045 0.040 0.037 0.033 0.059 0.109 NA
BC2F6.................................................... 0.058 NA 0.058 0.043 0.0093 0.18 NA 0.027 0.0204 NA 0.041 0.062 0.083 NA
BC4F6.................................................... 0.0083 NA 0.01219 NA 0.001 NA NA 0.008 NA NA NA NA NA NA
BC4F8.................................................... 0.0046 NA 0.00272 0.054 0.007 NA NA NA NA NA NA 0.0051 NA NA
BC3F8.................................................... NA NA NA NA NA NA NA NA NA NA NA NA 0.00012 NA
BCH2F2................................................... 0.005 NA 0.0024 NA 0.0033 NA NA 0.0021 0.00034 0.00088 0.000020 0.000030 NA NA
BCH3F.................................................... 0.0061 NA 0.027 0.0036 NA 0.0007 NA 0.0063 0.0036 0.0028 0.0082 0.00065 NA NA
BCHF3.................................................... 0.012 NA NA 0.057 0.016 0.012 NA 0.028 0.0106 0.000059 0.0039 0.017 0.0069 NA
BF2...................................................... NA NA NA NA NA NA NA NA NA 0.50 NA NA NA NA
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
0
39. Revise table I-16 to subpart I of part 98 to read as follows:
Table I-16 to Subpart I of Part 98--Default Emission Destruction or
Removal Efficiency (DRE) Factors for Electronics Manufacturing
------------------------------------------------------------------------
Default DRE
Manufacturing type/process type/gas (percent)
------------------------------------------------------------------------
MEMS, LCDs, and PV Manufacturing........................ 60
Semiconductor Manufacturing
CF4..................................................... 87
CH3F.................................................... 98
CHF3.................................................... 97
CH2F2................................................... 98
C4F8.................................................... 93
C4F8O................................................... 93
C5F8.................................................... 97
C4F6.................................................... 95
C3F8.................................................... 98
C2HF5................................................... 97
C2F6.................................................... 98
SF6..................................................... 95
NF3..................................................... 88
All other carbon-based fluorinated GHGs used in 60
Semiconductor Manufacturing............................
N2O Processes
CVD and all other N2O-using processes................... 60
------------------------------------------------------------------------
0
40. Add table I-18 to subpart I of part 98 to read as follows:
[[Page 37062]]
Table I-18 to Subpart I of Part 98 Default Factors for Gamma ([gamma]i,p and [gamma]k,i,p) for Semiconductor Manufacturing and for MEMS and PV
Manufacturing Under Certain Conditions* for Use With the Stack Testing Method
--------------------------------------------------------------------------------------------------------------------------------------------------------
Process type In-situ thermal or in-situ plasma cleaning Remote plasma cleaning
--------------------------------------------------------------------------------------------------------------------------------------------------------
c-C4F8
Gas CF4 C2F6 NF3 SF6 C3F8 CF4 NF3
--------------------------------------------------------------------------------------------------------------------------------------------------------
If manufacturing wafer sizes <=200 mm AND manufacturing
300 mm (or greater) wafer sizes
[gamma]i............................................... 13 9.3 4.7 14 11 NA NA 5.7
[gamma]CF4,i........................................... NA 23 6.7 63 8.7 NA NA 58
[gamma]C2F6,i.......................................... NA NA NA NA 3.4 NA NA NA
[gamma]CHF3,i.......................................... NA NA NA NA NA NA NA 0.12
[gamma]CH2F2,i......................................... NA NA NA NA NA NA NA 55
[gamma]CH3F,i.......................................... NA NA NA NA NA NA NA 16
If manufacturing <=200 mm OR manufacturing 300 mm (or
greater) wafer sizes
[gamma]i (<= 200 mm wafer size)........................ 13 9.3 4.7 2.9 11 NA NA 1.4
[gamma]CF4,i (<= 200 mm wafer size).................... NA 23 6.7 110 8.7 NA NA 36
[gamma]C2F6,i(<= 200 mm wafer size).................... NA NA NA NA 3.4 NA NA NA
[gamma]i (300 mm wafer size)........................... NA NA NA 26 NA NA NA 10
[gamma]CF4,i(300 mm wafer size)........................ NA NA NA 17 NA NA NA 80
[gamma]C2F6,i (300 mm wafer size)...................... NA NA NA NA NA NA NA NA
[gamma]CHF3,i (300 mm wafer size)...................... NA NA NA NA NA NA NA 0.24
[gamma]CH2F2,i (300 mm wafer size)..................... NA NA NA NA NA NA NA 111
[gamma]CH3F,i (300 mm wafer size)...................... NA NA NA NA NA NA NA 33
--------------------------------------------------------------------------------------------------------------------------------------------------------
* If you manufacture MEMS or PVs and use semiconductor tools and processes, you may you use the corresponding [gamma] in this table. For all other tools
and processes, a default [gamma] of 10 must be used.
0
41. Add table I-19 to subpart I of part 98 to read as follows:
Table I-19 to Subpart I of Part 98 Reference Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for 150 mm and 200 mm Wafer Sizes
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Process gas i
Process type/sub-type --------------------------------------------------------------------------------------------------------------------------------------------------------------------
CF4 C2F6 CHF3 CH2F2 C2HF5 CH3F C3F8 C4F8 NF3 SF6 C4F6 C5F8 C4F8O
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
ETCHING/WAFER CLEANING
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui............................................................... 0.73 0.46 0.31 0.37 0.064 0.66 NA 0.21 0.20 0.55 0.086 0.072 NA
BCF4............................................................... NA 0.20 0.10 0.031 0.077 NA NA 0.17 0.0040 0.023 0.089 NA NA
BC2F6.............................................................. 0.029 NA NA NA NA NA NA 0.065 NA NA 0.045 0.014 NA
BC4F6.............................................................. NA NA NA NA NA NA NA NA NA NA NA NA NA
BC4F8.............................................................. NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8.............................................................. NA NA NA NA NA NA NA NA NA NA NA NA NA
BC5F8.............................................................. NA NA NA NA NA NA NA 0.016 NA NA NA NA NA
BCHF3.............................................................. 0.13 NA NA NA NA NA NA NA NA NA NA 0.0039 NA
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CHAMBER CLEANING
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
IN SITU PLASMA CLEANING
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui............................................................... 0.92 0.55 NA NA NA NA 0.40 0.10 0.18 NA NA NA 0.14
BCF4............................................................... NA 0.19 NA NA NA NA 0.20 0.11 0.14 NA NA NA 0.13
BC2F6.............................................................. NA NA NA NA NA NA NA NA NA NA NA NA 0.045
BC3F8.............................................................. NA NA NA NA NA NA NA NA NA NA NA NA NA
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
REMOTE PLASMA CLEANING
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui............................................................... NA NA NA NA NA NA NA NA 0.028 NA NA NA NA
BCF4............................................................... NA NA NA NA NA NA NA NA 0.015 NA NA NA NA
BC2F6.............................................................. NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8.............................................................. NA NA NA NA NA NA NA NA NA NA NA NA NA
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
IN SITU THERMAL CLEANING
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui............................................................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BCF4............................................................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC2F6.............................................................. NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8.............................................................. NA NA NA NA NA NA NA NA NA NA NA NA NA
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 37063]]
0
42. Add table I-20 to subpart I of part 98 to read as follows:
Table I-20 to Subpart I of Part 98 Reference Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for 300 mm Wafer
Sizes
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Process gas i
Process type/sub-type ----------------------------------------------------------------------------------------------------------------------------------------------------------
CF4 C2F6 CHF3 CH2F2 CH3F C3F8 C4F8 NF3 SF6 C4F6 C5F8 C4F8O
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
ETCHING/WAFER CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui................................. 0.68 0.80 0.35 0.15 0.34 0.30 0.16 0.17 0.28 0.17 0.10 NA
BCF4................................. NA 0.21 0.073 0.020 0.038 0.21 0.045 0.035 0.0072 0.034 0.11 NA
BC2F6................................ 0.041 NA 0.040 0.0065 0.0064 0.18 0.030 0.038 0.0017 0.025 0.083 NA
BC4F6................................ 0.0015 NA 0.00010 NA 0.0010 NA 0.0083 NA NA NA NA NA
BC4F8................................ 0.0051 NA 0.00061 NA 0.0070 NA NA NA NA NA NA NA
BC3F8................................ NA NA NA NA NA NA NA NA NA NA 0.00012 NA
BC5F8................................ NA NA NA NA NA NA NA NA NA NA NA NA
BCHF3................................ 0.0056 NA NA 0.033 0.0049 0.012 0.029 0.0065 0.0012 0.019 0.0069 NA
BCH2F2............................... 0.014 NA 0.0026 NA 0.0023 NA 0.0014 0.00086 0.000020 0.000030 NA NA
BCH3F................................ 0.00057 NA 0.12 NA NA 0.00073 NA NA 0.0082 NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
CHAMBER CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
IN SITU PLASMA CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui................................. NA NA NA NA NA NA NA 0.20 NA NA NA NA
BCF4................................. NA NA NA NA NA NA NA 0.037 NA NA NA NA
BC2F6................................ NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8................................ NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
REMOTE PLASMA CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui................................. NA NA NA NA NA 0.063 NA 0.018 NA NA NA NA
BCF4................................. NA NA NA NA NA NA NA 0.038 NA NA NA NA
BC2F6................................ NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8................................ NA NA NA NA NA NA NA NA NA NA NA NA
BCHF3................................ NA NA NA NA NA NA NA 0.000059 NA NA NA NA
BCH2F2............................... NA NA NA NA NA NA NA 0.0016 NA NA NA NA
BCH3F................................ NA NA NA NA NA NA NA 0.0028 NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
IN SITU THERMAL CLEANING
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui................................. NA NA NA NA NA NA NA 0.28 NA NA NA NA
BCF4................................. NA NA NA NA NA NA NA 0.010 NA NA NA NA
BC2F6................................ NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8................................ NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Subpart N--Glass Production
0
43. Amend Sec. 98.146 by revising paragraphs (a)(2) and (b)(3) to read
as follows:
Sec. 98.146 Data reporting requirements.
* * * * *
(a) * * *
(2) Annual quantity of glass produced (tons), by glass type, from
each continuous glass melting furnace and from all furnaces combined.
(b) * * *
(3) Annual quantity of glass produced (tons), by glass type, from
each continuous glass melting furnace and from all furnaces combined.
* * * * *
0
44. Amend Sec. 98.147 by revising paragraphs (a)(1) and (b)(1) to read
as follows:
Sec. 98.147 Records that must be retained.
* * * * *
(a) * * *
(1) Monthly glass production rate for each continuous glass melting
furnace, by glass type (tons).
* * * * *
(b) * * *
(1) Monthly glass production rate for each continuous glass melting
furnace, by glass type (metric tons).
* * * * *
Subpart P--Hydrogen Production
0
45. Amend Sec. 98.163 by revising the introductory text and paragraph
(b) introductory text and adding paragraph (d) to read as follows:
Sec. 98.163 Calculating GHG emissions.
You must calculate and report the annual CO2 emissions from each
hydrogen production process unit using the procedures specified in
paragraphs (a) through (d) of this section, as applicable.
* * * * *
(b) Fuel and feedstock material balance approach. Calculate and
report CO2 emissions as the sum of the annual emissions associated with
each fuel and feedstock used for hydrogen production by following
paragraphs (b)(1) through (3) of this section. Adjust the emissions
estimated using paragraphs (b)(1) through (b)(3) by correcting for non-
CO2 carbon produced, if applicable, according to paragraph
(d) of this section. The carbon content and molecular weight shall be
obtained from the analyses conducted in accordance with Sec.
98.164(b)(2), (b)(3), or (b)(4), as applicable, or from the missing
data procedures in Sec. 98.165. If the analyses are performed
annually, then the annual value shall be used as the monthly average.
If the analyses are performed more frequently than monthly, use the
arithmetic average of values obtained during the month as the monthly
average.
* * * * *
(d) If carbon other than CO2 is collected and
transferred off site or if methanol is intentionally produced as a
desired product, you must correct the
[[Page 37064]]
CO2 emissions determined in paragraph (b) of this section to
determine the net CO2 emissions according to Equation P-4 of
this section.
[GRAPHIC] [TIFF OMITTED] TP21JN22.038
CO2,net = Annual net CO2 process emissions from hydrogen
production unit (metric tons/yr).
CO2,p = Annual CO2 process emissions arising from fuel
and feedstock consumption based on fuel type ``p'' (metric tons/yr).
p = index for fuel or feedstock type; 1 indicates gaseous fuel or
feedstocks; 2 indicates liquid fuel or feedstocks; and 3 indicates
solid fuel or feedstocks
Coffsite,n = Mass of carbon other than CO2 or methanol
collected from the hydrogen production unit and transferred off
site, from company records for month n (metric tons carbon).
MeOHn = Mass of methanol intentionally produced as a desired product
from the hydrogen production unit, from company records for month n
(metric tons). If the methanol product has a 99.5 weight percent or
higher purity, use the mass of methanol product produced; otherwise,
you must correct that mass of product produced by the methanol
purity (determined from company records) to determine the mass of
methanol intentionally produced.
k = Months in the year.
44/12 = Ratio of molecular weights, CO2 to carbon.
44/32 = Ratio of molecular weights, CO2 to methanol.
0
46. Amend Sec. 98.164 by revising paragraphs (b)(2) through (4) and
(b)(5) introductory text and adding paragraph (b)(5)(xix) to read as
follows:
Sec. 98.164 Monitoring and QA/QC requirements.
* * * * *
(b) * * *
(2) Determine the carbon content and the molecular weight annually
of standard gaseous hydrocarbon fuels and feedstocks having consistent
composition (e.g., natural gas) using the applicable methods in
paragraph (b)(5) of this section. For non-hydrocarbon gaseous fuels and
feedstocks that have a maximum product specification for carbon content
less than or equal to 0.00002 kg carbon per kg of gaseous fuel or
feedstock, you may determine the carbon content and the molecular
weight annually using the product specification's maximum carbon
content and molecular weight rather than using the methods specified in
paragraph (b)(5) of this section. For other gaseous fuels and
feedstocks (e.g., biogas, refinery gas, or process gas), sample and
analyze no less frequently than weekly to determine the carbon content
and molecular weight of the fuel and feedstock using the applicable
methods in paragraph (b)(5) of this section.
(3) Determine the carbon content of fuel oil, naphtha, and other
liquid fuels and feedstocks at least monthly, except annually for
standard liquid hydrocarbon fuels and feedstocks having consistent
composition, or upon delivery for liquid fuels and feedstocks delivered
by bulk transport (e.g., by truck or rail) using the applicable methods
in paragraph (b)(5) of this section. For non-hydrocarbon liquid fuels
and feedstocks that have a maximum product specification for carbon
content less than or equal to 0.00006 kg carbon per gallon of liquid
fuel or feedstock, you may determine the carbon content annually using
the product specification's maximum carbon content rather than using
the methods specified in paragraph (b)(5) of this section.
(4) Determine the carbon content of coal, coke, and other solid
fuels and feedstocks at least monthly, except annually for standard
solid hydrocarbon fuels and feedstocks having consistent composition,
or upon delivery for solid fuels and feedstocks delivered by bulk
transport (e.g., by truck or rail) using the applicable methods in
paragraph (b)(5) of this section.
(5) Except as provided in paragraphs (b)(2) and (3) of this section
for certain non-hydrocarbon feedstocks, you must use the following
applicable methods to determine the carbon content for all fuels and
feedstocks, and molecular weight of gaseous fuels and feedstocks.
Alternatively, you may use the results of chromatographic analysis of
the fuel and feedstock, provided that the chromatograph is operated,
maintained, and calibrated according to the manufacturer's
instructions; and the methods used for operation, maintenance, and
calibration of the chromatograph are documented in the written
monitoring plan for the unit under Sec. 98.3(g)(5).
* * * * *
(xix) For non-hydrocarbon fuels and feedstocks, if the methods
listed in paragraphs (b)(5)(i) through (xviii) of this section are not
appropriate because the relevant compounds cannot be detected, the
quality control requirements are not technically feasible, or use of
the method would be unsafe, you may use modifications of the methods
listed in paragraphs (b)(5)(i) through (xviii) or use other methods
that are applicable to your fuel or feedstock.
0
47. Amend Sec. 98.166 by revising the introductory text and paragraphs
(b)(1) and (d) to read as follows:
Sec. 98.166 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraph (a)
or (b) of this section, as appropriate, and paragraphs (c) through (e)
of this section:
* * * * *
(b) * * *
(1) Unit identification number and annual CO2 emissions
(determined in accordance with Sec. 98.163(b) or (d), as applicable).
* * * * *
(d) Annual quantity of carbon other than CO2 collected
and transferred off site in either gas, liquid, or solid forms (metric
tons carbon), excluding methanol, for each process unit.
* * * * *
0
48. Amend Sec. 98.167 by revising paragraph (b) and paragraph (e)
introductory text and adding paragraphs (e)(13) and (14) to read as
follows:
Sec. 98.167 Records that must be retained.
* * * * *
(b) If a CEMS is not used to measure CO2 emissions, then
you must retain records of all analyses and calculations conducted to
determine the values reported in Sec. 98.166(b) through (e).
* * * * *
(e) You must keep a record of the file generated by the
verification software specified in Sec. 98.5(b) for the applicable
data specified in paragraphs (e)(1) through (14) of this section.
Retention of this file satisfies the recordkeeping requirement for
the data in paragraphs (e)(1) through (14) of this section for each
hydrogen production unit.
* * * * *
(13) Monthly mass of carbon other than CO2 or methanol
collected and transferred off site (metric tons carbon) (Equation P-4).
(14) Monthly mass of methanol intentionally produced as a desired
product (metric tons) (Equation P-4).
[[Page 37065]]
Subpart Q--Iron and Steel Production
0
49. Amend Sec. 98.173 by revising Equation Q-5 in paragraph (b)(1)(v)
to read as follows:
Sec. 98.173 Calculating GHG emissions.
* * * * *
(b) * * *
(1) * * *
(v) * * *
[GRAPHIC] [TIFF OMITTED] TP21JN22.039
* * * * *
0
50. Amend Sec. 98.174 by:
0
a. Revising paragraph (b)(2) introductory text;
0
b. Redesignating paragraph (b)(2)(vi) as paragraph (b)(2)(vii); and
0
c. Adding new paragraph (b)(2)(vi).
The revision and addition read as follows:
Sec. 98.174 Monitoring and QA/QC requirements.
* * * * *
(b) * * *
(2) Except as provided in paragraph (b)(4) of this section,
determine the carbon content of each process input and output annually
for use in the applicable equations in Sec. 98.173(b)(1) based on
analyses provided by the supplier, analyses provided by material
recyclers who manage process outputs for sale or use by other
industries, or by the average carbon content determined by collecting
and analyzing at least three samples each year using the standard
methods specified in paragraphs (b)(2)(i) through (b)(2)(vii) of this
section as applicable.
* * * * *
(vi) ASTM E415-17, Standard Test Method for Analysis of Carbon and
Low-Alloy Steel by Spark Atomic Emission Spectrometry (incorporated by
reference, see Sec. 98.7) as applicable for steel.
* * * * *
0
51. Amend Sec. 98.176 by revising paragraphs (e)(2) and (g) to read as
follows:
Sec. 98.176 Data reporting requirements.
* * * * *
(e) * * *
(2) Whether the carbon content was determined from information from
the supplier, material recycler, or by laboratory analysis, and if by
laboratory analysis, the method used in Sec. 98.174(b)(2).
* * * * *
(g) For each unit, the type of unit, the annual production
capacity, and annual operating hours.
* * * * *
Subpart S--Lime Manufacturing
0
52. Amend Sec. 98.193 by revising paragraph (b)(2)(iv) to read as
follows:
Sec. 98.193 Calculating GHG emissions.
* * * * *
(b) * * *
(2) * * *
(iv) You must calculate annual net CO2 process emissions
for all lime kilns using Equation S-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.040
Where:
ECO2, net = Annual net CO2 process emissions from lime
production from all lime kilns (metric tons/year).
EFLIME,i,n = Emission factor for lime type i produced, in calendar
month n (metric tons CO2/ton lime) from Equation S-1 of
this section.
MLIME,i,n = Weight or mass of lime type i produced in calendar month
n (tons).
EFLKD,i,n = Emission factor of calcined byproducts or wastes sold
for lime type i in calendar month n, (metric tons CO2/ton
byproduct or waste) from Equation S-2 of this section.
MLKD,i,n = Monthly weight or mass of calcined byproducts or waste
sold (such as lime kiln dust, LKD) for lime type i in calendar month
n (tons).
Ewaste,i = Annual CO2 emissions for calcined lime
byproduct or waste type i that is not sold (metric tons
CO2) from Equation S-3 of this section.
Eproduct,n = Monthly amount of CO2 from lime production
that is captured for use in all on-site processes in calendar month
n, as described in Sec. 98.196(b)(17) (metric tons).
t = Number of lime types produced
b = Number of calcined byproducts or wastes that are sold.
z = Number of calcined byproducts or wastes that are not sold.
* * * * *
0
53. Amend Sec. 98.196 by:
0
a. Revising paragraph (a) introductory text;
0
b. Adding paragraphs (a)(9) through (14);
0
c. Revising paragraphs (b) introductory text, (b)(1), (b)(17)
introductory text, and (b)(17)(i); and
0
d. Adding paragraphs (b)(22) and (23).
The revisions and additions read as follows:
Sec. 98.196 Data reporting requirements.
* * * * *
(a) If a CEMS is used to measure CO2 emissions, then you
must report under this subpart the relevant information required by
Sec. 98.36 and the information listed in paragraphs (a)(1) through
(14) of this section.
* * * * *
(9) Annual arithmetic average of calcium oxide content for each
type of
[[Page 37066]]
lime product produced (metric tons CaO/metric ton lime).
(10) Annual arithmetic average of magnesium oxide content for each
type of lime product produced (metric tons MgO/metric ton lime).
(11) Annual arithmetic average of calcium oxide content for each
type of calcined lime byproduct/waste sold (metric tons CaO/metric ton
lime).
(12) Annual arithmetic average of magnesium oxide content for each
type of calcined lime byproduct/waste sold (metric tons MgO/metric ton
lime).
(13) Annual arithmetic average of calcium oxide content for each
type of calcined lime byproduct/waste not sold (metric tons CaO/metric
ton lime).
(14) Annual arithmetic average of magnesium oxide content for each
type of calcined lime byproduct/waste not sold (metric tons MgO/metric
ton lime).
(b) If a CEMS is not used to measure CO2 emissions, then
you must report the information listed in paragraphs (b)(1) through
(23) of this section.
(1) Annual net CO2 process emissions from all lime kilns
combined (metric tons).
* * * * *
(17) Indicate whether CO2 was captured and used on-site
(e.g., for use in a purification process, the manufacture of another
product). If CO2 was captured and used on-site, provide the
information in paragraphs (b)(17)(i) and (ii) of this section.
(i) The annual amount of CO2 captured for use in all on-
site processes.
* * * * *
(22) Annual average results of chemical composition analysis of all
lime byproducts or wastes not sold.
(23) Annual quantity (tons) of all lime byproducts or wastes not
sold.
0
54. Amend Sec. 98.197 by revising paragraph (c) introductory text and
adding paragraph (c)(10) to read as follows:
Sec. 98.197 Records that must be retained.
* * * * *
(c) You must keep a record of the file generated by the
verification software specified in Sec. 98.5(b) for the applicable
data specified in paragraphs (c)(1) through (10) of this section.
Retention of this file satisfies the recordkeeping requirement for the
data in paragraphs (c)(1) through (10) of this section.
* * * * *
(10) Monthly amount of CO2 from lime production that is
captured for use in all on-site processes, as described in Sec.
98.196(b)(17) (metric tons) (Equation S-4).
Subpart W--Petroleum and Natural Gas Systems
0
55. Amend Sec. 98.230 by revising paragraph (a)(3) to read as follows:
Sec. 98.230 Definition of the source category.
(a) * * *
(3) Onshore natural gas processing. Natural gas processing means
the forced extraction of natural gas 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.
* * * * *
0
56. Amend Sec. 98.232 by:
0
a. Revising paragraphs (b) and (c)(21);
0
b. Adding paragraph (c)(23);
0
c. Revising paragraph (d)(7);
0
d. Adding paragraphs (d)(8) and (9);
0
e. Revising paragraph (e)(8);
0
f. Adding paragraph (e)(9);
0
g. Revising paragraphs (f)(6) and (8);
0
h. Adding paragraph (f)(9);
0
i. Revising paragraphs (g)(6) and (7);
0
j. Adding paragraph (g)(8);
0
k. Revising paragraphs (h)(7) and (8);
0
l. Adding paragraphs (h)(9) and (10) and (i)(8);
0
m. Revising paragraph (j)(10);
0
n. Adding paragraph (j)(13); and
0
o. Revising paragraph (m).
The revisions and additions read as follows:
Sec. 98.232 GHGs to report.
* * * * *
(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 in the data collection and emissions estimation study
conducted by 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) * * *
(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, acid gas removal units,
dehydrators, heater treaters, and storage vessels.
* * * * *
(23) Other large release events.
(d) * * *
(7) Equipment leaks from valves, connectors, open ended lines,
pressure relief valves, and meters, and equipment leaks from all other
components in gas service that either are subject to equipment leak
standards for processing plants in part 60, subpart OOOOb 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.
(e) * * *
(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 and compressor stations in part 60, subpart OOOOb 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.
(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 and compressor stations
in part 60, subpart OOOOb 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 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
[[Page 37067]]
this chapter, the fugitive emissions standards for well sites and
compressor stations in part 60, subpart OOOOb 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) Other large release events.
(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 and compressor stations in part 60, subpart OOOOb 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 and compressor stations in part 60, subpart OOOOb 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.
(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 and compressor stations in part 60, subpart OOOOb 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 and compressor stations in 40 CFR part 60, subpart OOOOb 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 vents.
(10) Other large release events.
(i) * * *
(8) Other large release events.
(j) * * *
(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, acid gas removal units,
dehydrators, heater treaters, and storage vessels.
* * * * *
(13) Other large release events.
* * * * *
(m) For onshore natural gas transmission pipeline, report pipeline
blowdown CO2 and CH4 emissions from blowdown vent
stacks and CO2 and CH4 emissions from other large
release events.
0
57. Amend Sec. 98.233 by:
0
a. Revising paragraphs (a), (c), (d) introductory text, and (d)(4)(vi);
0
b. Adding paragraph (d)(12);
0
c. Revising paragraphs (e) introductory text, (e)(1) introductory text;
(e)(1)(x), and (e)(2) introductory text;
0
d. Revising parameter ``Count'' of Equation W-5 in paragraph (e)(2);
0
e. Removing and reserving paragraph (e)(3);
0
f. Removing paragraph (e)(4);
0
g. Redesignating paragraphs (e)(5) and (6) as (e)(4) and (5),
respectively;
0
h. Revising newly redesignated paragraphs (e)(4) and (5) and paragraphs
(g)(4), (h)(2), (i) introductory text, and (i)(2) introductory text;
0
i. Revising parameters ``Ta'' and ``Pa'' of
Equation W-14A in paragraph (i)(2)(i);
0
j. Revising parameters ``Ta,p'', ``Pa,b,p'', and
``Pa,e,p'' of Equation W-14B in paragraph (i)(2)(i);
0
k. Adding paragraph (i)(2)(iv);
0
l. Revising paragraphs (j) introductory text, (j)(1) introductory text,
(j)(1)(iii), (iv), and (vii), and (j)(2);
0
m. Revising parameter ``Count'' of Equation W-15 in paragraph (j)(3);
0
n. Revising paragraphs (j)(4) through (6), (k)(5), (l)(6), and (m)(3)
introductory text;
0
o. Revising parameters ``Vp,q'' and ``SGp,q'' of
Equation W-18 in paragraph (m)(3);
0
p. Revising paragraphs (m)(5), (n) introductory text, (n)(1), (n)(2)
introductory text, and (n)(5);
0
q. Removing and reserving paragraph (n)(9);
0
r. Revising paragraphs (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
s. Adding paragraph (o)(2)(iii);
0
t. Removing and reserving paragraph (o)(4)(ii)(D);
0
u. Revising paragraphs (o)(4)(ii)(E) and (o)(6)(i) introductory text;
0
v. Revising parameter ``m'' of Equation W-21 in paragraph (o)(6)(i);
0
w. Revising paragraph (o)(6)(ii) introductory text;
0
x. Revising parameter ``m'' of Equation W-22 in paragraph (o)(6)(ii);
0
y. Revising paragraph (o)(6)(iii) introductory text;
0
z. Revising parameter ``m'' of Equation W-23 in paragraph (o)(6)(iii);
0
aa. Revising parameter ``Tg'' of Equation W-24B in paragraph
(o)(8);
0
bb. Revising paragraph (o)(10) introductory text;
0
cc. Revising parameter ``Count'' of Equation W-25 in paragraph (o)(10);
0
dd. 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
ee. Removing and reserving paragraph (p)(4)(ii)(D);
0
ff. Revising paragraphs (p)(4)(ii)(E), (p)(6)(ii) introductory text,
(p)(6)(iii) introductory text, and (p)(10) introductory text;
0
gg. Revising parameter ``Count'' of Equation W-29D in paragraph
(p)(10);
0
hh. Revising paragraphs (q) introductory text, (q)(1), and (q)(2)
introductory text;
0
ii. Revising parameter ``EFs,p'' of Equation W-30 in
paragraph (q)(2) introductory text;
0
jj. Revising paragraphs (q)(2)(i), (iii), (v), (x), and (xi);
0
kk. Adding paragraph (q)(3);
0
ll. Revising paragraph (r) introductory text;
0
mm. Revising parameters ``Es,e,I,'' ``Es,MR,I,''
``Counte,'' ``CountMR,'' and ``EFs,e''
of Equations W-32A and W-32B in paragraph (r) introductory text;
0
nn. Revising paragraphs (r)(2), (r)(6)(i) and (ii), and (s);
[[Page 37068]]
0
oo. Revising parameter ``Za'' of Equation W-34 in paragraph
(t)(2);
0
pp. Removing the unnumbered text ``You may use either a default
compressibility factor of 1, or a site-specific compressibility factor
based on actual temperature and pressure conditions.'' after parameter
``Za'' of Equation W-34 in paragraph (t)(2); and
0
qq. Revising paragraphs (u)(2)(ii), (y), and (z).
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 natural gas processing facilities, onshore
natural gas transmission compression facilities, and underground
natural gas storage facilities, use methods specified in paragraphs
(a)(1) through (5) of this section to calculate CH4 and
CO2 emissions. For all continuous high bleed and continuous
low bleed natural gas pneumatic devices at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility, use methods specified in paragraphs
(a)(1) through (5) of this section to calculate CH4 and
CO2 emissions. For intermittent bleed natural gas pneumatic
devices at an onshore petroleum and natural gas production facility or
an onshore petroleum and natural gas gathering and boosting facility
that are subject to monitoring requirements in part 60, subpart OOOOb
of this chapter or an applicable approved state plan or applicable
Federal plan in part 62 of this chapter, use the methods specified in
paragraph (a)(6) of this section to calculate CH4 and
CO2 emissions from those pneumatic devices. For intermittent
bleed natural gas pneumatic devices 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 monitoring
requirements in part 60, subpart OOOOb of this chapter or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter, you may either elect to monitor your intermittent bleed
natural gas pneumatic devices at least annually following the methods
specified in part 60, subpart OOOOb of this chapter or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter, as applicable, and use the methods specified in paragraph
(a)(6) of this section to calculate CH4 and CO2
emissions from your natural gas intermittent bleed pneumatic devices or
use the methods specified in paragraphs (a)(1) through (5) of this
section to calculate CH4 and CO2 emissions from
your natural gas intermittent bleed pneumatic devices.
(1) Calculate CH4 and CO2 volumetric
emissions from continuous high bleed, continuous low bleed, and
intermittent bleed natural gas pneumatic devices using Equation W-1A of
this section.
[GRAPHIC] [TIFF OMITTED] TP21JN22.041
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 paragraph (a)(1) or (a)(2) 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'' listed in Tables W-1A, W-2B, W-3B, and W-4B to this subpart
for onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting, onshore natural
gas processing, onshore natural gas transmission compression, and
underground natural gas storage facilities, respectively.
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, and underground natural gas storage
facilities, concentration of GHGi, CH4 or
CO2, in produced natural gas or processed natural gas for
each facility as specified in paragraphs (u)(2)(i) through (iv) 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.
(2) For all industry segments, determine ``Countt'' for
Equation W-1A of this subpart for each type of natural gas pneumatic
device (continuous high bleed, continuous low bleed, and intermittent
bleed) by counting the devices, except as specified in paragraph (a)(3)
of this section. The reported number of devices must represent the
total number of devices for the reporting year.
(3) For the onshore petroleum and natural gas production industry
segment, you have the option in the first two consecutive calendar
years to determine ``Countt'' for Equation W-1A of this
section for each type of natural gas pneumatic device (continuous high
bleed, continuous low bleed, and intermittent bleed) using engineering
estimates based on best available data. For the onshore petroleum and
natural gas gathering and boosting industry segment, you have the
option in the first two consecutive calendar years to determine
``Countt'' for Equation W-1A for each type of natural gas
pneumatic device (continuous high bleed, continuous low bleed, and
intermittent bleed) using engineering estimates based on best available
data.
(4) For all industry segments, determine the type of pneumatic
device using engineering estimates based on best available information.
(5) Calculate both CH4 and CO2 mass emissions
from volumetric emissions using calculations in paragraph (v) of this
section.
(6) Calculate CH4 and CO2 volumetric
emissions using Equation W-1B of this section from natural gas
intermittent bleed pneumatic devices that are monitored according to
the requirements in this paragraph (a)(6).
[GRAPHIC] [TIFF OMITTED] TP21JN22.042
[[Page 37069]]
Where:
Ei = Annual total volumetric emissions of GHGi from
natural gas intermittent bleed 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.
x = Total number of intermittent bleed 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.
24.1 = Whole gas emission factor for malfunctioning intermittent
bleed natural gas pneumatic devices, in standard cubic feet per hour
per device.
Tz = The total time the surveyed pneumatic device ``z'' was in
service (i.e., supplied with natural gas) and assumed to be leaking,
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.
0.3 = Whole gas emission factor for properly operating intermittent
bleed natural gas pneumatic devices, in standard cubic feet per
hour.
Count = Total number of intermittent bleed devices that were never
observed to be malfunctioning during any monitoring survey during
the year.
Tavg = The average time the 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.
(i) You must conduct pneumatic device monitoring surveys using the
methods in either paragraph (a)(6)(i) or (ii) of this paragraph.
(A) For intermittent bleed natural gas pneumatic devices that are
subject to monitoring requirements in part 60, subpart OOOOb of this
chapter or an approved state plan or Federal plan in part 62 of this
chapter, as applicable, you must use the methods specified in the
applicable standard.
(B) For intermittent bleed natural gas pneumatic devices that are
not subject to monitoring requirements in part 60, subpart OOOOb of
this chapter or an applicable approved state plan or applicable Federal
plan in part 62 of this chapter and that you elect to monitor, you must
use the methods specified in part 60, subpart OOOOb of this chapter.
(ii) 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-1B.
(iii) Calculate both CO2 and CH4 mass
emissions using calculations in paragraph (v) of this section.
* * * * *
(c) Natural gas driven pneumatic pump venting. Calculate emissions
from natural gas driven pneumatic pumps venting directly to the
atmosphere as specified in paragraphs (c)(1) and (2) of this section.
Calculate emissions from natural gas driven pneumatic pumps routed to
flares, combustion, or vapor recovery systems as specified in paragraph
(c)(3) of this section. 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) Calculate CH4 and CO2 volumetric
emissions from natural gas driven pneumatic pump venting using Equation
W-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP21JN22.043
Where:
Es,i = Annual total volumetric GHG emissions at standard conditions
in standard cubic feet per year from all natural gas driven
pneumatic pump venting, for GHGi.
Count = Total number of natural gas driven pneumatic pumps that
vented directly to the atmosphere.
EF = Population emission factors for natural gas driven pneumatic
pumps (in standard cubic feet per hour per pump) listed in Table W-
1A of this subpart for onshore petroleum and natural gas production
and onshore petroleum and natural gas gathering and boosting
facilities.
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 in service (i.e.,
supplied with natural gas) using engineering estimates based on best
available data. Default is 8,760 hours for pumps that only vented
directly to the atmosphere.
(2) Calculate both CH4 and CO2 mass emissions
from volumetric emissions using calculations in paragraph (v) of this
section.
(3) Calculate emissions from natural gas driven pneumatic pumps
routed to flares, combustion, or vapor recovery systems as specified in
paragraph (c)(3)(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, combustion, or vapor recovery system during another part of
the year, then calculate emissions from the time the pump vents
directly to the atmosphere as specified in paragraphs (c)(1) and (2) of
this section and calculate emissions from the time the pump was routed
to a flare or combustion as specified in paragraphs (c)(3)(i) and (ii)
of this section, as applicable. For emissions that are collected in a
vapor recovery system that is not routed to combustion, paragraphs
(c)(1) and (2) and (c)(3)(i) and (ii) 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), without subtracting emissions attributable to natural
gas driven pneumatic pumps from the flare.
(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 (AGR) vents. For AGR vents (including
processes such as amine, membrane, molecular sieve or other absorbents
and adsorbents), calculate emissions for CO2 only (not
CH4) vented directly to the atmosphere or emitted through an
engine (e.g., permeate from a membrane or de-adsorbed gas from a
pressure swing adsorber used as fuel supplement), or sulfur recovery
plant, using any of the calculation methods described in
[[Page 37070]]
paragraphs (d)(1) through (4) of this section, and also comply with
paragraphs (d)(5) through (11), as applicable. For AGR emissions that
are routed to a flare, calculate the flared emissions as specified in
paragraph (d)(12) of this section.
* * * * *
(4) * * *
(vi) Solvent type, pressure, temperature, circulation rate, and
composition.
* * * * *
(12) For AGR vents routed to a flare, calculate CO2
emissions from the AGR as specified in paragraph (d)(12)(i) or (ii) of
this section, as applicable.
(i) For emissions from an AGR unit that are routed to a dedicated
flare, or if the emissions from the AGR unit are comingled with
emissions from any other source types for routing to a flare and you do
not continuously measure either flow or composition of the comingled
gas stream, then calculate CO2 emissions from the AGR using
a method specified in paragraph (d)(1) through (4) of this section, as
applicable. You must also incorporate your AGR data into the parameters
Vs and XCO2 in Equation W-20 to account for the
AGR portion of the total flared CO2 emissions for all
miscellaneous flared sources as described in paragraphs (n)(1) and (2)
of this section.
(ii) For emissions from an AGR unit that are comingled with
emissions from any other source types for routing to a flare and you
continuously measure flow and/or composition of the comingled gas
stream, then calculate total emissions from all miscellaneous flared
sources (which includes AGRs) for the flare(s) to which the AGR
emissions are routed using the procedures specified in paragraphs
(n)(1) through (8) of this section. Use site-specific engineering
estimates based on best available data to calculate the portion of the
total flared CO2 emissions from the miscellaneous flared
sources that entered the flare from the AGR. Report the calculated
portion of the total flared CO2 emissions that entered the
flare from the AGR as CO2 emissions from the AGR as
specified in Sec. 98.236(d)(1)(v). Subtract this amount of
CO2 from the total flared CO2 and report the
remainder as CO2 from miscellaneous flared sources as
specified in Sec. 98.236(n)(1)(xi).
(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. 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 flare or regenerator firebox/fire tubes, you must
calculate CH4, CO2, and N2O annual
emissions as specified in paragraph (e)(5) of this section.
(1) Calculation Method 1. Calculate annual mass emissions from
glycol dehydrators that have an annual average of daily natural gas
throughput that is greater than or equal to 0.4 million standard cubic
feet per day by using a software program, such as AspenTech
HYSYS[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.
Emissions must be modeled from both the still vent and, if applicable,
the flash tank vent. The following parameters must be determined by
engineering estimate based on best available data and must be used at a
minimum to characterize emissions from dehydrators:
* * * * *
(x) Wet natural gas temperature and pressure at the absorber inlet.
* * * * *
(2) Calculation Method 2. Calculate annual volumetric emissions
from glycol dehydrators that have an annual average of daily natural
gas throughput that is less than 0.4 million standard cubic feet per
day 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.
* * * * *
(4) If the dehydrator unit has vapor recovery, calculate annual
emissions as specified in paragraphs (e)(4)(i) and (ii) of this
section.
(i) Adjust the emissions estimated in paragraphs (e)(1) and (2) of
this section, as applicable, downward by the magnitude of emissions
recovered using a vapor recovery system and by the amount of emissions
routed to flares or regenerator firebox/fire tubes as determined by
engineering estimate based on best available data. Report unrecovered
emissions that are not routed to flares or regenerator fireboxes/fire
tubes as emissions vented directly to the atmosphere.
(ii) If unrecovered emissions from the dehydrator are routed to
flares or regenerator fireboxes/fire tubes, use the calculation method
of flare stacks in paragraph (n) of this section to determine
dehydrator vent emissions from the flare or regenerator combustion gas
vent. Use the volume routed to the flares or regenerator fireboxes/fire
tubes and the dehydrator vent gas composition as determined using
either engineering estimates based on best available data or the
procedures specified in paragraph (u)(2) of this section, as
applicable. Report unrecovered emissions that are routed to flares or
regenerator fireboxes/fire tubes as flared emissions from dehydrators.
(5) If any dehydrator vent streams are routed to a flare or
regenerator firebox/fire tubes, calculate emissions from these devices
attributable to dehydrators as specified in paragraphs (e)(5)(i)
through (v) of this section. If you operate a CEMS to monitor the
emissions from the flare in accordance with paragraph (n)(8) of this
section, calculate emissions as specified in paragraph (e)(5)(v) of
this section instead of the provisions of paragraphs (e)(5)(i) through
(iv) of this section.
(i) Determine the volume of gas from the dehydrator(s) to each
flare using any of the methods specified in paragraph (e)(5)(i)(A) or
(B) of this section. You are not required to use the same method for
all dehydrator streams.
(A) Use the vented volume as determined in paragraphs (e)(1)
through (4) of this section.
(B) Measure the flow from the dehydrator(s) to the flare or
regenerator firebox/fire tubes using a continuous flow measurement
device. If the measured volume is in a manifold that combines flow from
multiple dehydrators or from dehydrators and other sources, use
engineering calculations based on process knowledge and best available
data to estimate the portion(s) of the total flow (in scf) from each
large dehydrator or from all small dehydrators combined.
(ii) Except as specified in paragraph (e)(5)(iii) of this section,
determine composition of the gas from the dehydrator(s) to each flare
or regenerator firebox/fire tubes using any of the methods specified in
paragraphs (e)(5)(ii)(A) through (C) of this section. You are not
required to use the same method for all dehydrator streams.
(A) Use the gas composition as determined in paragraphs (e)(1)
through (4) of this section.
[[Page 37071]]
(B) Measure the composition of the gas from the dehydrator(s) to
the flare or regenerator firebox/fire tubes using a continuous
composition analyzer. If the measured composition is in a manifold that
combines streams only from multiple dehydrators, assume the measured
composition applies to all dehydrators that route gas through the
manifold.
(C) Measure the composition of the total gas to the flare or
regenerator firebox/fire tubes using a continuous composition analyzer.
If the measured composition is in a manifold that combines flow from
dehydrators and other sources, use engineering calculations based on
available sampling data for other sources, process knowledge, and best
available data to estimate the composition of the flow from each large
dehydrator or from all small dehydrators combined.
(iii) If you continuously measure flow in accordance with paragraph
(e)(5)(i)(B) of this section and/or continuously measure gas
composition in accordance with paragraph (e)(5)(ii)(B) or (C) of this
section, then those measured data must be used, either directly or
after disaggregating to individual sources, to calculate dehydrator
emissions from flares or regenerator firebox/fire tubes.
(iv) Use the calculation method of flare stacks in paragraphs
(n)(3) through (7) of this section to calculate annual dehydrator
emissions from flares or regenerator firebox/fire tubes.
(v) If you monitor the flare with CEMS, use the calculation
procedures in paragraph (n)(8) of this section. If the flare receives
gas from multiple dehydrators or from both dehydrators and other
sources, then use engineering calculations based on process knowledge
and best available data to estimate the portions of the total
CO2 emissions measured by the CEMS that are from each large
dehydrator and from all small dehydrators combined.
* * * * *
(g) * * *
(4) If any streams from well completions and workovers with
hydraulic fracturing are flared, calculate annual emissions as
specified in paragraphs (g)(4)(i) through (v) of this section. If you
operate a CEMS to monitor the emissions from the flare in accordance
with paragraph (n)(8) of this section, calculate emissions as specified
in paragraph (g)(4)(v) of this section instead of the provisions of
paragraphs (g)(4)(i) through (iv) of this section.
(i) Determine the volume of gas from well completions and workovers
with hydraulic fracturing routed to each flare using any of the methods
specified in paragraph (g)(4)(i)(A) or (B) of this section. You are not
required to use the same method for all streams.
(A) Use the volume from gas venting to the atmosphere during well
completions and workovers with hydraulic fracturing as determined in
paragraph (g) of this section. Subtract the estimated amount vented to
the atmosphere, if any, from this total volume.
(B) Measure the flow from well completions and workovers with
hydraulic fracturing to the flare using a continuous flow measurement
device. If the measured volume is in a manifold that combines flow from
well completions and workovers with hydraulic fracturing and other
sources, use engineering calculations based on process knowledge and
best available data to estimate the portion(s) of the total flow (in
scf) from well completions and workovers with hydraulic fracturing.
(ii) Except as specified in paragraph (g)(4)(iii) of this section,
determine composition of the gas from well completions and workovers
with hydraulic fracturing to each flare using any of the methods
specified in paragraphs (g)(4)(ii)(A) through (C) of this section. You
are not required to use the same method for all streams.
(A) Use the gas composition as determined in paragraph (g)(3) of
this section.
(B) Measure the composition of the gas from well completions and
workovers with hydraulic fracturing to the flare using a continuous
composition analyzer. If the measured composition is in a manifold that
combines streams only from well completions and workovers with
hydraulic fracturing, assume the measured composition applies to all
completions and workovers with hydraulic fracturing that route gas
through the manifold.
(C) Measure the composition of the total gas to the flare using a
continuous composition analyzer. If the measured composition is in a
manifold that combines flow from well completions and workovers with
hydraulic fracturing and other sources, use engineering calculations
based on available sampling data for other sources, process knowledge,
and best available data to estimate the composition of the flow from
each well completions and workovers with hydraulic fracturing.
(iii) If you continuously measure flow in accordance with paragraph
(g)(4)(i)(B) of this section and/or continuously measure gas
composition in accordance with paragraph (g)(4)(ii)(B) or (C) of this
section, then those measured data must be used, either directly or
after disaggregating to individual sources, to calculate well
completion and workover from hydraulic fracturing emissions from
flares.
(iv) Use the calculation method of flare stacks in paragraphs
(n)(3) through (7) of this section to calculate annual emissions for
the portion of gas flared during well completions and workovers using
hydraulic fracturing.
(v) If you monitor the flare with CEMS, use the calculation
procedures in paragraph (n)(8) of this section. If the flare receives
gas from multiple well completions and workovers with hydraulic
fracturing or from both well completions and workovers with hydraulic
fracturing and other sources, then use engineering calculations based
on process knowledge and best available data to estimate the portions
of the total CO2 emissions measured by the CEMS that are
from well completions and workovers with hydraulic fracturing.
(h) * * *
(2) If any streams from gas well completions and workovers without
hydraulic fracturing are flared, calculate annual emissions of
CH4, CO2, and N2O as specified in
paragraphs (h)(2)(i) through (v) of this section. If you operate a CEMS
to monitor the emissions from the flare in accordance with paragraph
(n)(8) of this section, calculate emissions as specified in paragraph
(h)(2)(v) of this section instead of the provisions of paragraphs
(h)(2)(i) through (iv) of this section.
(i) Determine the volume of gas from well completions and workovers
without hydraulic fracturing routed to each flare using any of the
methods specified in paragraph (h)(2)(i)(A) or (B) of this section. You
are not required to use the same method for all streams.
(A) Use the gas well venting volume during well completions and
workovers without hydraulic fracturing that are flared as determined
using the methods specified in paragraphs (h) and (h)(1) of this
section.
(B) Measure the flow from well completions and workovers without
hydraulic fracturing to the flare using a continuous flow measurement
device. If the measured volume is in a manifold that combines flow from
well completions and workovers without hydraulic fracturing and other
sources, use engineering calculations based on process knowledge and
best available data to estimate the portion(s) of the total flow (in
scf) from well completions and workovers without hydraulic fracturing.
(ii) Determine composition of the gas from well completions and
workovers without hydraulic fracturing to each
[[Page 37072]]
flare using any of the methods specified in paragraphs (h)(2)(ii)(A)
through (C) of this section. You are not required to use the same
method for all streams.
(A) Use the gas composition as determined in paragraphs (h)
introductory text and (h)(1) of this section.
(B) Measure the composition of the gas from well completions and
workovers without hydraulic fracturing to the flare using a continuous
composition analyzer. If the measured composition is in a manifold that
combines streams only from well completions and workovers without
hydraulic fracturing, assume the measured composition applies to all
completions and workovers without hydraulic fracturing that route gas
through the manifold.
(C) Measure the composition of the total gas to the flare using a
continuous composition analyzer. If the measured composition is in a
manifold that combines flow from well completions and workovers without
hydraulic fracturing and other sources, use engineering calculations
based on available sampling data for other sources, process knowledge,
and best available data to estimate the composition of the flow from
each well completions and workovers without hydraulic fracturing.
(iii) If you continuously measure flow in accordance with paragraph
(h)(2)(i)(B) of this section and/or continuously measure gas
composition in accordance with paragraph (h)(2)(ii)(B) or (C) of this
section, then those measured data must be used, either directly or
after disaggregating to individual sources, to calculate well
completion and workover from hydraulic fracturing emissions from
flares.
(iv) Use the calculation method of flare stacks in paragraphs
(n)(3) through (7) of this section to calculate annual emissions from
the flare for gas well venting to a flare during completions and
workovers without hydraulic fracturing.
(v) If you monitor the flare with CEMS, use the calculation
procedures in paragraph (n)(8) of this section. If the flare receives
gas from multiple well completions and workovers without hydraulic
fracturing or from both well completions and workovers without
hydraulic fracturing and other sources, then use engineering
calculations based on process knowledge and best available data to
estimate the portions of the total CO2 emissions measured by
the CEMS that are from well completions and workovers without hydraulic
fracturing.
(i) Blowdown vent stacks. Calculate CO2 and
CH4 blowdown vent stack emissions from the depressurization
of equipment to reduce system pressure for planned or emergency
shutdowns resulting from human intervention or to take equipment out of
service for maintenance as specified in either paragraph (i)(2) or (3)
of this section. You may use the method in paragraph (i)(2) of this
section for some blowdown vent stacks at your facility and the method
in paragraph (i)(3) of this section for other blowdown vent stacks at
your facility. Equipment with a unique physical volume of less than 50
cubic feet as determined in paragraph (i)(1) of this section are not
subject to the requirements in paragraphs (i)(2) through (4) of this
section. The requirements in this paragraph (i) do not apply to
blowdown vent stack emissions from depressurizing to a flare, over-
pressure relief, operating pressure control venting, and blowdown of
non-GHG gases.
* * * * *
(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 gathering and boosting facilities and
onshore natural gas transmission pipeline 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 gathering and boosting facilities and onshore
natural gas transmission pipeline 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 gathering and
boosting facilities and onshore natural gas transmission pipeline
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
gathering and boosting facilities and onshore natural gas
transmission pipeline 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 gathering and
boosting facilities and onshore natural gas transmission pipeline
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 natural gas processing, transmission
compression, 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 segment,
pipeline
[[Page 37073]]
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) Onshore production and onshore petroleum and natural gas
gathering and boosting storage tanks. Calculate CH4,
CO2, and N2O (when flared) emissions from
atmospheric pressure fixed roof storage tanks receiving hydrocarbon
produced liquids from onshore petroleum and natural gas production
facilities and onshore petroleum and natural gas gathering and boosting
facilities (including stationary liquid storage not owned or operated
by the reporter), as specified in this paragraph (j). For 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 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 flowing directly
to atmospheric storage tanks without passing through a separator with
throughput greater than or equal to 10 barrels per day, calculate
annual CH4 and CO2 emissions using Calculation
Method 2 as specified in paragraph (j)(2) of this section. 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, use Calculation Method 3 as specified in
paragraph (j)(3) of this section. If you use Calculation Method 1 or
Calculation Method 2 for separators, you must also calculate emissions
that may have occurred due to dump valves not closing properly using
the method specified in paragraph (j)(6) of this section. If emissions
from atmospheric pressure fixed roof storage tanks are routed to a
vapor recovery system, you must adjust the emissions downward according
to paragraph (j)(4) of this section. If emissions from atmospheric
pressure fixed roof storage tanks are routed to a flare, you must
calculate CH4, CO2, and N2O annual
emissions as specified in paragraph (j)(5) of this section.
(1) Calculation Method 1. Calculate annual CH4 and
CO2 emissions from onshore production storage tanks and
onshore petroleum and natural gas gathering and boosting storage tanks
using operating conditions in the last gas-liquid separator or non-
separator equipment before liquid transfer to storage tanks. Calculate
flashing emissions with a software program, such as AspenTech
HYSYS[supreg] or 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 from the separator or non-separator equipment enter
an atmospheric pressure storage tank. The following parameters must be
determined for typical operating conditions over the year by
engineering estimate and process knowledge based on best available
data, and must be used at a minimum to characterize emissions from
liquid transferred to tanks:
* * * * *
(iii) Sales oil or stabilized hydrocarbon liquids API gravity.
(iv) Sales oil or stabilized hydrocarbon liquids production rate.
* * * * *
(vii) Separator or non-separator equipment hydrocarbon liquids
composition and Reid vapor pressure. If this data is not available,
determine these parameters by using one of the methods described in
paragraphs (j)(1)(vii)(A) through (C) of this section.
(A) If separator or non-separator equipment hydrocarbon liquid
composition and Reid vapor pressure default data are provided with the
software program, select the default values that most closely match
your separator or non-separator equipment pressure first, and API
gravity secondarily.
(B) If separator or non-separator equipment hydrocarbon liquids
composition and Reid vapor pressure data are available through your
previous analysis, select the latest available analysis that is
representative of produced crude oil or condensate from the sub-basin
category for onshore petroleum and natural gas production or from the
county for onshore petroleum and natural gas gathering and boosting.
(C) Analyze a representative sample of separator or non-separator
equipment hydrocarbon liquids in each sub-basin category for onshore
petroleum and natural gas production or each county for onshore
petroleum and natural gas gathering and boosting for hydrocarbon
liquids composition and Reid vapor pressure using an appropriate
standard method published by a consensus-based standards organization.
(2) Calculation Method 2. Calculate annual CH4 and
COCO2 emissions using the methods in paragraph (j)(2)(i) of
this section for gas-liquid separators with annual average daily
throughput of hydrocarbon liquids greater than or equal to 10 barrels
per day. Calculate annual CH4 and COCO2 emissions
using the methods in paragraph (j)(2)(ii) of this section for wells
with annual average daily hydrocarbon liquids production greater than
or equal to 10 barrels per day that flow directly to atmospheric
storage tanks in onshore petroleum and natural gas production and
onshore petroleum and natural gas gathering and boosting (if
applicable). Calculate annual CH4 and COCO2
emissions using the methods in paragraph (j)(2)(iii) of this section
for non-separator equipment with annual average daily hydrocarbon
liquids throughput greater than or equal to 10 barrels per day that
flow directly to atmospheric storage tanks in onshore petroleum and
natural gas gathering and boosting.
(i) Flow to storage tank after passing through a separator. Assume
that all of the CH4 and COCO2 in solution at
separator temperature and pressure is emitted from hydrocarbon liquids
sent to 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 separator hydrocarbon liquids
composition at separator pressure and temperature.
(ii) Flow to storage tank direct from wells. Calculate
CH4 and COCO2 emissions using either of the
methods in paragraph (j)(2)(ii)(A) or (B) of this section.
(A) If well production hydrocarbon liquids and gas compositions are
available through a previous analysis, select the latest available
analysis that is representative of produced hydrocarbon liquids and gas
from the sub-basin category and assume all of the CH4 and CO2 in both
hydrocarbon liquids and gas are emitted from the tank.
[[Page 37074]]
(B) If well production hydrocarbon liquids and gas compositions are
not available, use default hydrocarbon liquids and gas compositions in
software programs, such as API 4697 E&P Tank, that most closely match
the well production gas/oil ratio and API gravity and assume all of the
CH4 and CO2 in both hydrocarbon liquids and gas are emitted from the
tank.
(iii) Flow to storage tank direct from non-separator equipment.
Calculate CH4 and CO2 emissions using either of the methods in
paragraph (j)(2)(iii)(A) or (B) of this section.
(A) If other non-separator equipment hydrocarbon liquids and gas
compositions are available through a previous analysis, select the
latest available analysis that is representative of hydrocarbon liquids
and gas from non-separator equipment in the same county and assume all
of the CH4 and CO2 in both hydrocarbon liquids and gas are emitted from
the tank.
(B) If non-separator equipment hydrocarbon liquids and gas
compositions are not available, use default hydrocarbon liquids and gas
compositions in software programs, such as API 4697 E&P Tank, that most
closely match the non-separator equipment gas/liquid ratio and API
gravity and assume all of the CH4 and CO2 in both hydrocarbon liquids
and gas are emitted from the tank.
(3) * * *
Count = Total number of separators, wells, or non-separator
equipment with annual average daily throughput less than 10 barrels
per day. Count only separators, wells, or non-separator equipment
that feed hydrocarbon liquids directly to the storage tank.
* * * * *
(4) If the storage tank receiving your hydrocarbon liquids has a
vapor recovery system, calculate annual emissions from storage tanks as
specified in paragraphs (j)(4)(i) and (ii) of this section.
(i) 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 emissions
recovered.
(ii) Determine total emissions not recovered by a vapor recovery
system as specified in paragraphs (j)(4)(ii)(A) and (B) of this
section.
(A) Adjust the emissions estimated in paragraphs (j)(1) through (3)
of this section downward by the magnitude of emissions recovered using
a vapor recovery system and by the amount of emissions routed to
flares. Unrecovered emissions may include, but are not limited to,
emissions during periods when the vapor recovery system is not
operating, losses from the tank when the vapor recovery system is not
operating and the tank is connected to a flare, and losses from the
tank during periods when the vapor recovery system is operating. These
losses may include, but are not limited to, emissions due to open or
unseated thief hatches. Report unrecovered emissions that are not
routed to flares as emissions vented directly to the atmosphere.
(B) If unrecovered emissions from atmospheric tanks are routed to
flares, determine the volume of gas routed to flares, calculate annual
emissions from flares as specified in paragraphs (j)(5)(i) through
(iii) of this section, and report as flared emissions from atmospheric
tanks.
(5) If the storage tank receiving your hydrocarbon liquids has a
flare(s), calculate annual flared emissions from storage tanks as
specified in paragraphs (j)(5)(i) through (v) of this section and
calculate emissions vented directly to the atmosphere as specified in
paragraph (j)(5)(vi) of this section. For atmospheric tanks with
emissions calculated using Calculation Method 3 in paragraph (j)(3) of
this section, this paragraph (j)(5) only applies when at least half of
the hydrocarbon liquids flowing to gas-liquid separators or non-
separator equipment or directly to atmospheric storage tanks are
directed to atmospheric tanks that used flares to control emissions. If
you operate a CEMS to monitor the emissions from the flare in
accordance with paragraph (n)(8) of this section, calculate emissions
as specified in paragraph (j)(5)(v) of this section instead of the
provisions of paragraphs (j)(5)(i) through (iv) of this section.
(i) Estimate the volume routed to the flare using any of the
methods specified in paragraph (j)(5)(i)(A) or (B) of this section. You
are not required to use the same method for all storage tanks.
(A) If unrecovered emissions from the storage tank are calculated
in accordance with paragraph (j)(4) of this section, then determine the
volume of the unrecovered emissions routed to flares based on best
available data. If no emissions from the storage tank are routed to
vapor recovery, then use the storage tank emissions volume as
determined in paragraphs (j)(1) through (3) of this section, except
that you must also adjust this total volume of emissions downward by
the estimated portion of the total volume that is not routed to the
flare (e.g., when the flare is bypassed or when a thief hatch is open
or not properly seated). Estimate the volume of the emissions not
routed to flares based on best available data.
(B) Measure the flow from the storage tank(s) to the flare using a
continuous flow measurement device. If the measured volume is in a
manifold that combines flow from storage tanks and other sources, use
engineering calculations based on process knowledge and best available
data to estimate the portion(s) of the total flow (in scf) from each
storage tank.
(ii) Except as specified in paragraph (j)(5)(iii) of this section,
determine the composition of the gas from the storage tanks routed to
the flare using any of the methods specified in paragraphs
(j)(5)(ii)(A) through (C) of this section. You are not required to use
the same method for all storage tanks.
(A) If you use Calculation Method 1 or Calculation Method 2, use
your gas composition as determined in paragraphs (j)(1) and (2) of this
section. If you use Calculation Method 3 in paragraph (j)(3) of this
section, determine the gas composition using either engineering
estimates based on best available data or the procedures specified in
paragraph (u)(2)(i) of this section.
(B) Measure the composition of the gas from the storage tanks to
the flare using a continuous gas composition analyzer. If the measured
composition is in a manifold that combines streams only from multiple
storage tanks, assume the measured composition applies to all storage
tanks that route gas through the manifold.
(C) Measure the composition of the total gas to the flare using a
continuous composition analyzer. If the measured composition is in a
manifold that combines flow from storage tanks and other sources, use
engineering calculations based on available sampling data for other
sources, process knowledge, and best available data to estimate the
composition of the flow from storage tanks.
(iii) If you continuously measure flow in accordance with paragraph
(j)(5)(i)(B) of this section and/or continuously measure gas
composition in accordance with paragraph (j)(5)(ii)(B) or (C) of this
section, then those measured data must be used, either directly or
after disaggregating to individual sources, to calculate storage tank
emissions from flares.
(iv) Use the calculation method of flare stacks in paragraphs
(n)(3) through (7) of this section with the volume and composition
determined according to paragraphs (j)(5)(i) and (ii) of this
[[Page 37075]]
section to determine storage tank emissions from the flare.
(v) If you monitor the flare with CEMS, use the calculation
procedures in paragraph (n)(8) of this section. If the flare receives
gas from both storage tanks and other sources, then use engineering
calculations based on process knowledge and best available data to
estimate the portions of the total CO2 emissions measured by
the CEMS that are from storage tanks.
(vi) For storage tanks with no vapor recovery system, if the volume
routed to the flare as determined in paragraph (j)(5)(i)(A) or (B) of
this section is less than the total volume of emissions from the tank
as estimated in paragraphs (j)(1) through (3) of this section, then use
the volume not sent to the flare to calculate emissions of flash gas
vented directly to the atmosphere from the storage tank.
(6) 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 not closing
during the calendar year by using Equation W-16 of this section.
[GRAPHIC] [TIFF OMITTED] TP21JN22.044
Where:
Es,i,dv = Annual volumetric GHG emissions (either
CO2 or CH4) at standard conditions in cubic
feet from storage tanks that resulted from the dump valve on the
gas-liquid separator not closing properly.
Es,i = Annual volumetric GHG emissions (either
CO2 or CH4) as determined in paragraphs (j)(1)
and (2) and, if applicable, (j)(4) and (5) of this section, in
standard cubic feet per year, from storage tanks with dump valves on
an associated gas-liquid separator that did not close properly.
Tdv = Total time a dump valve is not closing properly in
the calendar year in hours. Estimate Tdv 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.
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.
8,760 = Conversion to hourly emissions.
* * * * *
(k) * * *
(5) If any transmission storage tanks are routed to flares,
calculate 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), without subtracting emissions attributable to
transmission tanks from the flare. If the volume to the flare is not
continuously measured for the duration of time that flaring occurred,
then conduct an annual leak measurement as specified in paragraph
(k)(1)(ii) or (iv) of this section. If a leak is detected, quantify the
leak in accordance with paragraph (k)(2)(i) or (ii) of this section and
determine the time leaking as specified in paragraph (k)(3) of this
section. Use these data when estimating total flow to the flare in
accordance with paragraph (n)(1) of this section.
(l) * * *
(6) If any emissions from well testing are routed to a flare,
calculate flared emissions from well testing as specified in paragraphs
(l)(6)(i) through (v) of this section. If you operate a CEMS to monitor
the emissions from the flare in accordance with paragraph (n)(8) of
this section, calculate emissions as specified in paragraph (l)(6)(v)
of this section instead of the provisions of paragraphs (l)(6)(i)
through (iv) of this section.
(i) Determine the volume of gas from well testing to each flare
using any of the methods specified in paragraph (l)(6)(i)(A) or (B) of
this section. You are not required to use the same method for all well
testing.
(A) Use the well testing emissions volume as determined in
paragraphs (l)(1) through (4) of this section.
(B) Measure the flow from well testing to the flare using a
continuous flow measurement device. If the measured volume is in a
manifold that combines flow from well testing and other sources, use
engineering calculations based on process knowledge and best available
data to estimate the portion(s) of the total flow (in scf) from well
testing.
(ii) Except as specified in paragraph (l)(6)(iii) of this section,
determine composition of the gas from well testing to each flare using
any of the methods specified in paragraphs (l)(6)(ii)(A) through (C) of
this section. You are not required to use the same method for all well
testing.
(A) Use the gas composition as determined in paragraphs (l)(1)
through (4) of this section.
(B) Measure the composition of gas from well testing to the flare
using a continuous composition analyzer. If the measured composition is
in a manifold that combines streams only from testing of multiple
wells, assume the measured composition applies to all well testing gas
routed through the manifold.
(C) Measure the composition of the total gas to the flare using a
continuous composition analyzer. If the measured composition is in a
manifold that combines flow from well testing and other sources, use
engineering calculations based on available sampling data for other
sources, process knowledge, and best available data to estimate the
composition of the flow from well testing.
(iii) If you continuously measure flow in accordance with paragraph
(l)(6)(i)(B) of this section and/or continuously measure gas
composition in accordance with paragraph (l)(6)(ii)(B) or (C) of this
section, then those measured data must be used, either directly or
after disaggregating to individual sources, to calculate well testing
emissions from flares.
(iv) Use the calculation method of flare stacks in paragraphs
(n)(3) through (7) of this section to determine annual well testing
emissions from the flare.
(v) If you monitor the flare with CEMS, use the calculation
procedures in paragraph (n)(8) of this section. If the flare receives
gas from both well testing and other sources, then use engineering
calculations based on process knowledge and best available data to
estimate the portions of the total CO2 emissions measured by
the CEMS that are from well testing.
(m) * * *
(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.
* * * * *
Vp,q = Volume of oil produced, for well p in sub-basin q,
in barrels in the calendar year only during time periods in which
associated gas was vented or flared.
SGp,q = Volume of associated gas sent to sales, for well
p in sub-basin q, in standard cubic feet of gas in the calendar year
only during time periods in which associated gas was vented or
flared.
* * * * *
(5) Calculate flared associated natural gas emissions as specified
in paragraphs (m)(5)(i) through (v) of this section. If you operate a
CEMS to monitor the emissions from the flare in accordance
[[Page 37076]]
with paragraph (n)(8) of this section, calculate emissions as specified
in paragraph (m)(5)(v) of this section instead of the provisions of
paragraphs (m)(5)(i) through (iv) of this section.
(i) Determine the volume of associated gas to each flare using any
of the methods specified in paragraph (m)(5)(i)(A) or (B) of this
section. You are not required to use the same method for all associated
gas streams.
(A) Use the associated natural gas volume as determined in
paragraphs (m)(1) through (4) of this section.
(B) Measure the flow of associated gas to the flare using a
continuous flow measurement device. If the measured volume is in a
manifold that combines flow from multiple associated gas streams or
from associated gas streams and other sources, use engineering
calculations based on process knowledge and best available data to
estimate the portions of the total flow (in scf) that is associated
gas.
(ii) Except as specified in paragraph (m)(5)(iii) of this section,
determine composition of the associated gas to each flare using any of
the methods specified in paragraphs (m)(5)(ii)(A) through (C) of this
section. You are not required to use the same method for all associated
gas streams.
(A) Use the associated gas composition as determined in paragraphs
(m)(1) through (4) of this section.
(B) Measure the composition of the associated gas to the flare
using a continuous composition analyzer. If the measured composition is
in a manifold that combines only associated gas streams, assume the
measured composition applies to all associated gas that is routed
through the manifold.
(C) Measure the composition of the total gas to the flare using a
continuous composition analyzer. If the measured composition is in a
manifold that combines both associated gas and gas from other sources,
use engineering calculations based on available sampling data for other
sources, process knowledge, and best available data to estimate the
composition of the associated gas in the combined stream.
(iii) If you continuously measure flow in accordance with paragraph
(m)(5)(i)(B) of this section and/or continuously measure gas
composition in accordance with paragraph (m)(5)(ii)(B) or (C) of this
section, then those measured data must be used, either directly or
after disaggregating to individual sources, to calculate associated gas
emissions from flares.
(iv) Use the calculation method of flare stacks in paragraphs
(n)(3) through (7) of this section to calculate annual associated gas
emissions from flares.
(v) If you monitor the flare with CEMS, use the calculation
procedures in paragraph (n)(8) of this section. If the flare receives
both associated gas and gas from other sources, then use engineering
calculations based on process knowledge and best available data to
estimate the portions of the total CO2 emissions measured by
the CEMS that are from associated gas.
(n) Flare stack emissions. As applicable for the industry segment,
use the procedures in paragraphs (n)(3) through (9) of this section to
calculate CO2, CH4, and N2O emissions
per flare stack separately from dehydrators as specified in paragraph
(e)(5) of this section, completions and workovers with hydraulic
fracturing as specified in paragraph (g)(4) of this section,
completions and workovers without hydraulic fracturing as specified in
paragraph (h)(2) of this section, atmospheric tanks as specified in
paragraph (j)(5) of this section, well testing as specified in
paragraph (l)(6) of this section, and associated gas as specified in
paragraph (m)(5) of this section. Also use the procedures specified in
paragraphs (n)(1) through (9) of this section to calculate the
collective emissions per flare stack from all miscellaneous flared
sources (i.e., sources that are not subject to source-specific flared
emissions reporting for your industry segment).
(1) If you have a continuous flow measurement device on gas to the
flare, you must use the measured flow volumes to calculate the flare
gas emissions from miscellaneous flared sources. If all of the flare
gas is not measured by the existing flow measurement device, then the
flow not measured can be estimated using engineering calculations based
on best available data. If you do not have a continuous flow
measurement device on gas to the flare, or if a continuous flow
measurement device measures a stream that combines flow from sources
that are subject to source-specific flared emissions reporting as well
as flow from miscellaneous flared sources, you can use engineering
calculations based on process knowledge and best available data to
estimate the flow from the miscellaneous flared sources. Best available
data also includes the procedures specified in paragraphs (e)(5),
(g)(4), (h)(2), (j)(5), (k)(5), (l)(6), and (m)(5) of this section. If
a continuous flow measurement device is not installed on an AGR that is
routed to a flare, the volumetric CO2 emissions calculated
using AGR Calculation Method 3 or 4 and paragraph (d)(9) of this
section must be incorporated into the parameter Vs in
Equation W-20 to account for the AGR portion of the total flared
CO2 emissions.
(2) If you have a continuous gas composition analyzer on gas to the
flare, you must use these compositions in calculating emissions from
miscellaneous flared sources, except when the measured stream to the
flare includes emissions from an AGR unit that are comingled with
emissions from other sources. If you do not have a continuous gas
composition analyzer on gas to the flare, or if the stream to the flare
consists of AGR emissions that are comingled with emissions from other
sources, you must use the appropriate gas compositions for each stream
of hydrocarbons going to the flare from an emission source other than
an AGR vent as specified in paragraphs (n)(2)(i) through (iii) of this
section. For emissions from AGR vents that do not have a continuous gas
composition analyzer, you may use either site-specific engineering
estimates based on best available data or a default CO2 mole
fraction of 1.
* * * * *
(5) Calculate GHG volumetric emissions from flaring at standard
conditions using Equations W-19 and W-20 of this section. Emissions may
be calculated per stream routed to the flare and then summed over all
streams per emissions source type. Alternatively, you may sum the total
volume of all streams from a particular emission source type, determine
the flow-weighted average CO2 and hydrocarbon concentrations
over all streams per source type, and then perform a single calculation
using Equation W-19 and a single calculation using Equation W-20 to
calculate the total CH4 and CO2 emissions per
source type.
[GRAPHIC] [TIFF OMITTED] TP21JN22.045
[[Page 37077]]
[GRAPHIC] [TIFF OMITTED] TP21JN22.046
Where:
Es,CH4 = Annual CH4 emissions per emission
source type from flare stack in cubic feet, at standard conditions.
Es,CO2 = Annual CO2 emissions per emission
source type from flare stack in cubic feet, at standard conditions.
Vs = Volume of gas sent to flare per emission source type
in standard cubic feet, during the year as determined in paragraph
(e)(5)(i), (g)(4)(i), (h)(2)(i), (j)(5)(i), (l)(6)(i), (m)(5)(i), or
(n)(1) of this section.
[eta] = Flare combustion efficiency, expressed as fraction of gas
combusted by a burning flare (default is 0.98).
XCH4 = Mole fraction of CH4 in the feed gas to
the flare per emission source type as determined in paragraph
(e)(5)(ii), (g)(4)(ii), (h)(2)(ii), (j)(5)(ii), (l)(6)(ii),
(m)(5)(ii), or (n)(2) of this section. Use a flow-weighted mole
fraction if multiple streams from the same source type are combined
for the emissions calculation.
XCO2 = Mole fraction of CO2 in the feed gas to
the flare per emission source type as determined in paragraph
(e)(5)(ii), (g)(4)(ii), (h)(2)(ii), (j)(5)(ii), (l)(6)(ii),
(m)(5)(ii), or (n)(2) of this section. Use a flow-weighted mole
fraction if multiple streams from the same source type are combined
for the emissions calculation.
ZU = Fraction of the feed gas sent to an un-lit flare per
emission source type determined by engineering estimate and process
knowledge based on best available data and operating records.
ZL = Fraction of the feed gas sent to a burning flare per
emission source type (equal to 1 - ZU).
Yj = Mole fraction of hydrocarbon constituents j (such as
methane, ethane, propane, butane, and pentanes-plus) in the feed gas
to the flare per emissions source type as determined in paragraph
(e)(5)(ii), (g)(4)(ii), (h)(2)(ii), (j)(5)(ii), (l)(6)(ii),
(m)(5)(ii), or (n)(2) of this section.
Rj = Number of carbon atoms in the hydrocarbon
constituent j in the feed gas to the flare per emission source type:
1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for
pentanes-plus).
* * * * *
(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); and calculate CH4 and CO2 mass
emissions as specified in paragraph (o)(11). If emissions from a
compressor source are routed to a flare, paragraphs (o)(1) through (11)
do not apply and instead you must calculate CH4,
CO2, and N2O emissions as specified in paragraph
(o)(12) of this section. If emissions from a compressor source are
routed to combustion, paragraphs (o)(1) through (12) 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 vapor recovery,
paragraphs (o)(1) through (12) 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).
[[Page 37078]]
(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)(ii)(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 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 emissions from 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 are not required
to be determined under this paragraph (o).
* * * * *
Count = Total number of centrifugal compressors that have wet seal
oil degassing vents that are vented to the atmosphere.
* * * * *
(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)(5), you must
calculate volumetric emissions as specified in paragraph (p)(10); and
calculate CH4 and CO2 mass emissions as specified in paragraph (p)(11).
If emissions from a compressor source are routed to a flare, paragraphs
(p)(1) through (11) do not apply and instead you must calculate CH4,
CO2, and N2O emissions as specified in paragraph (p)(12) of this
section. If emissions from a compressor source are routed to
combustion, paragraphs (p)(1) through (12) 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 vapor recovery, paragraphs (p)(1)
through (12) 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
[[Page 37079]]
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 paragraph (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 paragraph (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.
* * * * *
(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.
* * * * *
(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 emissions from
reciprocating compressor atmospheric venting of rod packing emissions
at an onshore petroleum and natural gas production facility or an
onshore petroleum and natural gas gathering and boosting facility using
Equation W-29D of this section. Reciprocating compressor rod packing
emissions that are routed to a flare, combustion, or vapor recovery are
not required to be determined under this paragraph (p).
* * * * *
Count = Total number of reciprocating compressors with rod packing
emissions vented to the atmosphere.
* * * * *
(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.
(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
[[Page 37080]]
emissions standards for well sites and compressor stations in part 60,
subpart OOOOb 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 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 and compressor stations
in part 60, subpart OOOOb 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 and
compressor stations in part 60, subpart OOOOb 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 this subparagraph (q)(1)(iv), 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 and compressor
stations in 40 CFR part 60, subpart OOOOb 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 in the equipment leak standards
for processing plants in part 60, subpart OOOOb 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 in the equipment leak standards
for processing plants in part 60, subpart OOOOb 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)(v)(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 will
be considered a complete leak detection survey for purposes of this
section.
(B) For components subject to the well site and compressor station
fugitive emissions standards in the fugitive emissions standards for
well sites and compressor stations in part 60, subpart OOOOb of this
chapter, each survey conducted in accordance with the fugitive
emissions standards for well sites and compressor stations in part 60,
subpart OOOOb of this chapter will be considered a complete leak
detection survey for purposes of this section.
(C) For components subject to the well site 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 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 compressor station or centralized oil
production 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
the equipment leak standards for onshore natural gas processing plants
in part 60, subpart OOOOb 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 part 60, subpart OOOOb 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
[[Page 37081]]
detection survey for the purposes of calculating emissions using the
procedures specified in either paragraph (q)(2) or (3) of this section.
However, this provision does not absolve you of the responsibility to
conduct a complete leak detection survey of all components listed in
Sec. 98.232(d)(7) and subject to this paragraph (q) at least once
during the calendar year.
(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 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 to use this method, you must use this method
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 (iv) 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.
* * * * *
EFs,p = Leaker emission factor for specific component
types by leak detection method listed in Tables W-1E, W-2A, W-3A, W-
4A, W-5A, W-6A, and W-7A to this subpart.
* * * * *
(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
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-1E to this subpart.
* * * * *
(v) Onshore natural gas processing facilities must 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-2A 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-7 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] TP21JN22.047
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-7 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
[[Page 37082]]
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. If you
elect to use this method, you must use this method 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, you must determine the
volumetric flow rate of each natural gas leak identified during the
leak survey and aggregate the emissions by 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; 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 for which a leak was
detected.
(vii) 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) 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.
(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) and (j)(11). 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 paragraph (r) of this section and do not need
to 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.
* * * * *
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, or gathering
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
[[Page 37083]]
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-
1A 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-4B 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-8 to this
subpart.
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-1A, W-4B, W-5B, W-6B,
and W-8 to this subpart.
* * * * *
(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-1A of this subpart. Major equipment associated with
gas wells are considered gas service equipment in Table W-1A of this
subpart. Onshore petroleum and natural gas gathering and boosting
facilities shall use the gas service equipment emission factors in
Table W-1A of this subpart. Major equipment associated with crude oil
wells are considered crude service equipment in Table W-1A of this
subpart. Where facilities conduct EOR operations the emission factor
listed in Table W-1A 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.
* * * * *
(6) * * *
(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-8 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).
(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 in the
data collection and emissions estimation study conducted by BOEM in
compliance with 30 CFR 550.302 through 304.
(1) Offshore production facilities under BOEM jurisdiction shall
report the same annual emissions as calculated and reported by BOEM in
data collection and emissions estimation study published by BOEM
referenced in 30 CFR 550.302 through 304.
(i) For any calendar year that does not overlap with the most
recent BOEM emissions study publication year, report the most recent
BOEM reported emissions data published by BOEM referenced in 30 CFR
550.302 through 304. Adjust emissions based on the operating time for
the facility relative to the operating time in the most recent BOEM
published study.
(ii) [Reserved]
(2) Offshore production facilities that are not under BOEM
jurisdiction must use the most recent monitoring methods and
calculation methods published by BOEM referenced in 30 CFR 550.302
through 304 to calculate and report annual emissions.
(i) For any calendar year that does not overlap with the most
recent BOEM emissions study publication, you may report the most
recently reported 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) [Reserved]
(3) If BOEM discontinues or delays their data collection effort by
more than 4 years, then offshore reporters shall once in every 4 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 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 release events for each release
that emits GHG in excess of 250 metric tons of CO2e as
specified in paragraphs (y)(1) through (4) of this section.
(1) Estimate the total volume of gas released during the event in
standard
[[Page 37084]]
cubic feet using any combination of measurement data, engineering
estimates, and best available data. Typically, total volume of gas
released would be estimated as the product of the estimated flow or
release rate and the estimated event duration.
(2) Determine the composition of the gas released to the atmosphere
using measurement data, if available, or process knowledge, engineering
estimates and best available data. 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 that was converted to CO2 during the
release event.
(3) Calculate the GHG volumetric emissions using Equation W-35 in
paragraph (u)(1) of this section.
(4) 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)(5) and (6)
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
according to any Tier listed in subpart C of this part, except that
natural gas-fired compressor-drivers must use the appropriate emission
factor in Table W-9 for quantifying CH4 emissions instead of
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)(4) 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 and other gaseous fuels listed
in Table C-1. The natural gas also 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
according to Tier 2, Tier 3, or Tier 4 listed in subpart C of this
part, except that natural gas-fired compressor-drivers must use the
appropriate emissions factor in Table W-9 for quantifying
CH4 emissions instead of 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)(4) 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 is not listed in Table C-1 of subpart C of this part,
the fuel is a blend containing one or more fuels not listed in Table C-
1, or the fuel is natural gas or contains natural gas that does not
meet the criteria of either paragraph (z)(1)(i) or (z)(2)(i) of this
section. This includes 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. This also includes field
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 hydrocarbon 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 hydrocarbon constituent in the flow of gas to the
unit or group of units. Otherwise, you must use the appropriate gas
compositions for each stream of hydrocarbons going to the combustion
unit(s) as specified in the applicable paragraph in (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] TP21JN22.048
[[Page 37085]]
[GRAPHIC] [TIFF OMITTED] TP21JN22.049
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.
Ea,CH4 = Contribution of annual CH4 emissions
from portable or stationary fuel combustion sources in cubic feet,
under actual conditions.
[eta] = Fraction of gas combusted for portable and stationary
equipment determined using engineering estimation. For internal
combustion devices that are not compressor-drivers, a default of
0.995 can be used. For two-stroke lean-burn compressor-drivers, a
default of 0.953 must be used; for four- stroke lean-burn
compressor-drivers, a default of 0.962 must be used; and for four-
stroke rich-burn compressor-drivers, a default of 0.997 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.
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] TP21JN22.050
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 = Higher heating value of fuel, mmBtu/unit of fuel (in units
consistent with the fuel quantity combusted). For field gas or
process vent gas, you may use either a default higher heating value
of 1.235 x 10-3 mmBtu/scf or a site-specific higher
heating value. For natural gas that is not of pipeline quality or
that has a higher heating value less than 950 Btu per standard cubic
foot, use a site-specific higher heating value.
EF = Use 1.0 x 10-\4\ kg N2O/mmBtu.
1 x 10-\3\ = Conversion factor from kilograms to metric
tons.
(4) 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.
(5) 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.
(6) 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 emissions for threshold determination in
Sec. 98.231(a). You must report the type and number of each internal
fuel combustion unit.
0
58. Amend Sec. 98.234 by revising the introductory text, paragraph
(a), and paragraph (d)(3) and adding paragraphs (d)(5) and (i) to 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 to comply with
the fugitive emission component requirements in part 60, subpart OOOOa
of this chapter or with the fugitive emission component or equipment
leak requirements in part 60, OOOOb of this chapter or with the
fugitive emission component or equipment leak requirements in an
applicable approved state plan or applicable Federal plan in part 62 of
this chapter.
(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
[[Page 37086]]
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(b), (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(b) 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 to comply with the fugitive
emission component requirements in part 60, subpart OOOOa of this
chapter or with the fugitive emission component or equipment leak
requirements in part 60, subpart OOOOb of this chapter or with the
fugitive emission component or equipment leak requirements in an
applicable approved state plan or applicable Federal plan in part 62 of
this chapter. 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 component'' in Sec. 60.5397a 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) Special reporting provisions for best available monitoring
methods in reporting year 2023--(1) Use of best available monitoring
methods. From January 1, 2023, to December 31, 2023, you must use the
calculation methodologies and equations in Sec. 98.233 but you may use
the best available monitoring method as described in paragraph (i)(2)
of this section for any parameter specified in paragraphs (i)(3)
through (7) of this section for which it is not reasonably feasible to
acquire, install, and operate a required piece of monitoring equipment
by January 1, 2023. Starting no later than January 1, 2024, you must
discontinue using best available methods and begin following all
applicable monitoring and QA/QC requirements of this part.
(2) Best available monitoring methods. Best available monitoring
[[Page 37087]]
methods means any of the following methods:
(i) Monitoring methods currently used by the facility that do not
meet the specifications of this subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other facility records.
(3) Best available monitoring methods for measurement data for
natural gas pneumatic devices. You may use best available monitoring
methods for any measurement data, including activity data such as gas
compositions and hours of operation, that cannot reasonably be measured
according to the monitoring and QA/QC requirements of this subpart for
natural gas pneumatic devices as specified in Sec. 98.233(a) at
onshore natural gas processing plants and for natural gas intermittent
bleed pneumatic devices that are monitored as specified in Sec.
98.233(a)(6).
(4) Best available monitoring methods for measurement data for LNG
import/export facilities. You may use best available monitoring methods
for any measurement data, including activity data such as flow rates,
gas compositions, and hours of operation, that cannot reasonably be
measured according to the monitoring and QA/QC requirements of this
subpart for acid gas removal vents as specified in Sec. 98.233(d) at
LNG import/export facilities.
(5) Best available monitoring methods for measurement data for
other large release events. You may use best available monitoring
methods for any measurement data, including activity data such as flow
rates, gas compositions, and hours of operation, that cannot reasonably
be measured according to the monitoring and QA/QC requirements of this
subpart for other large release events as specified in Sec. 98.233(y).
(6) Best available monitoring methods for measurement data for
miscellaneous flared sources. You may use best available monitoring
methods for any measurement data, including activity data such as flow
rates and gas compositions, that cannot reasonably be obtained
according to the monitoring and QA/QC requirements of this subpart for
miscellaneous flared sources as specified in Sec. 98.233(n)(1) and
(2).
(7) Best available monitoring methods for measurement data for
specific emission sources routed to vapor recovery. You may use best
available monitoring methods for any measurement data, including
activity data such as flow rates, gas compositions, and hours of
operation, that cannot reasonably be obtained according to the
monitoring and QA/QC requirements of this subpart for dehydrator vents
and storage tank vents routed to vapor recovery as specified in Sec.
98.233(e)(4) and (j)(4), respectively.
(8) Best available monitoring methods for measurement data for
compressors. You may use best available monitoring methods for any
measurement data that cannot reasonably be obtained according to the
monitoring and QA/QC requirements of this subpart for dry seal vents on
centrifugal compressors and all compressor sources for centrifugal
compressors found in standby-pressurized-mode as specified in Sec.
98.233(o). You may use best available monitoring methods for any
measurement data that cannot reasonably be obtained according to the
monitoring and QA/QC requirements of this subpart for rod packing on
reciprocating compressors in standby-pressurized-mode as specified in
Sec. 98.233(p).
(9) Best available monitoring methods for measurement data for a
facility that was part of a facility with respect to onshore petroleum
and natural gas gathering and boosting prior to January 1, 2023, and
meets the definition of onshore natural gas processing in Sec.
98.230(a)(3) effective as of January 1, 2023. You may use best
available monitoring methods for measurement data, including activity
data, as listed in paragraphs (i)(9)(i) through (iv) of this section
that cannot reasonably be obtained according to the monitoring and QA/
QC requirements of this subpart.
(i) Temperature and pressure for emergency blowdowns in Sec.
98.233(i).
(ii) Equipment leak surveys in Sec. 98.233(q).
(iii) Centrifugal compressors in Sec. 98.233(o).
(iv) Reciprocating compressors in Sec. 98.233(p).
(10) Best available monitoring methods for measurement data for a
facility that was an onshore natural gas processing facility prior to
January 1, 2023, and became part of a facility with respect to onshore
petroleum and natural gas gathering and boosting as defined in Sec.
98.238 as of January 1, 2023, due to the change in definition of
onshore natural gas processing in Sec. 98.230(a)(3) effective as of
January 1, 2023. You may use best available monitoring methods for
measurement data, including activity data, as listed in paragraphs
(i)(10)(i) through (iii) of this section that cannot reasonably be
obtained according to the monitoring and QA/QC requirements of this
subpart.
(i) Natural gas driven pneumatic pumps in Sec. 98.233(c).
(ii) Storage tanks in Sec. 98.233(j).
(iii) Equipment leak surveys in Sec. 98.233(q) and/or equipment
leaks by population count in Sec. 98.233(r), as applicable, for
equipment components not required for the onshore natural gas
processing industry segment (i.e., pumps, flanges, other components,
and gathering pipelines).
0
59. Amend Sec. 98.236 by:
0
a. Revising the introductory text and paragraphs (a)(1) introductory
text and (a)(1)(xviii);
0
b. Adding paragraph (a)(1)(xix);
0
c. Revising paragraphs (a)(2) and (a)(3) introductory text;
0
d. Redesignating paragraphs (a)(3)(i) through (vii) as paragraphs
(a)(3)(ii) through (viii), respectively;
0
e. Adding new paragraph (a)(3)(i) and paragraph (a)(3)(ix);
0
f. Revising paragraph (a)(4) introductory text;
0
g. Adding paragraph (a)(4)(viii);
0
h. Revising paragraph (a)(5) introductory text;
0
i. Adding paragraph (a)(5)(vii);
0
j. Revising paragraph (a)(6) introductory text;
0
k. Adding paragraph (a)(6)(vi);
0
l. Revising paragraph (a)(7) introductory text;
0
m. Redesignating paragraphs (a)(7)(i) through (vi) as paragraphs
(a)(7)(ii) through (vii), respectively;
0
n. Adding new paragraph (a)(7)(i) and paragraph (a)(7)(viii);
0
o. Revising paragraph (a)(8) introductory text;
0
p. Adding paragraph (a)(8)(iv);
0
q. Revising paragraphs (a)(9) introductory text and (a)(9)(xii);
0
r. Adding paragraph (a)(9)(xiii);
0
s. Revising paragraphs (a)(10), (b), (c), (d)(1)(iii), and
(d)(2)(iii)(L);
0
t. Adding paragraph (d)(2)(iv);
0
u. Revising paragraphs (e) introductory text, (e)(1) introductory text,
and (e)(1)(viii), (xi), (xii), and (xv) through (xviii);
0
v. Adding paragraph (e)(1)(xix);
0
w. Revising paragraph (e)(2);
0
x. Removing and reserving paragraph (e)(3);
0
y. Revising paragraphs (f)(1) introductory text and (f)(1)(iii);
0
z. Adding paragraphs (f)(1)(xi)(F) and (f)(1)(xii)(F);
0
aa. Revising paragraphs (f)(2) introductory text and (f)(2)(iii), (ix)
and (x);
0
bb. Adding paragraphs (f)(2)(xi) and (xii);
0
cc. Revising paragraphs (g)(10), (h)(2) introductory text, and
(h)(2)(v) through (vii);
0
dd. Adding paragraphs (h)(2)(viii) through (xvi);
0
ee. Revising paragraphs (h)(4) introductory text and (h)(4)(iii)
through (v);
[[Page 37088]]
0
ff. Adding paragraphs (h)(4)(vi) through (xiv);
0
gg. Revising paragraphs (i)(1) introductory text, (j) introductory
text, (j)(1) and (2), (j)(3)(ii), (k)(1)(ii) through (iv), (k)(2)
introductory text, (k)(3), (l)(1) introductory text, (l)(2)
introductory text, and (l)(2)(vi) through (viii);
0
hh. Adding paragraphs (l)(2)(ix) through (xvii);
0
ii. Revising paragraphs (l)(3) introductory text, (l)(4) introductory
text, and (l)(4)(v) through (vii);
0
jj. Adding paragraphs (l)(4)(viii) through (xvi);
0
kk. Revising paragraphs (m)(4) through (8), (n), (o)(1), (o)(2)(i)(B),
(o)(2)(ii)(A), (o)(5)(i) through (iii), (p)(1), (p)(2)(ii)(A),
(p)(3)(ii) introductory text, (p)(5)(i) through (iii), (q)(1)
introductory text, and (q)(1)(iii);
0
ll. Adding paragraphs (q)(1)(vi) and (vii);
0
mm. Revising paragraphs (q)(2), (r)(1) introductory text, and
(r)(1)(i);
0
nn. Removing and reserving paragraph (r)(3);
0
oo. Revising paragraphs (s) introductory text, (y), (z) introductory
text, (z)(2)(i) and (iv) through (vi), (aa)(3) introductory text, and
(aa)(3)(i);
0
pp. Adding paragraph (aa)(3)(viii);
0
qq. Removing and reserving paragraph (aa)(9);
0
rr. Revising paragraph (aa)(10) introductory text;
0
ss. Adding paragraphs (aa)(10)(v) and (vi); and
0
tt. Revising paragraphs (aa)(11)(ii) and (iii), (bb) introductory text,
and (cc).
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) * * *
(1) Onshore petroleum and natural gas production. For the
equipment/activities specified in paragraphs (a)(1)(i) through (xix) of
this section, report the information specified in the applicable
paragraphs of this section.
* * * * *
(xviii) Other large release events. Report the information
specified in paragraph (y) of this section.
(xix) Combustion equipment. Report the information specified in
paragraph (z) of this section.
(2) Offshore petroleum and natural gas production. Report the
information specified in paragraphs (s) and (y) of this section.
(3) Onshore natural gas processing. For the equipment/activities
specified in paragraphs (a)(3)(i) through (ix) 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.
* * * * *
(ix) Other large release events. Report the information specified
in paragraph (y) of this section.
(4) Onshore natural gas transmission compression. For the
equipment/activities specified in paragraphs (a)(4)(i) through (viii)
of this section, report the information specified in the applicable
paragraphs of this section.
* * * * *
(viii) Other large release events. Report the information specified
in paragraph (y) of this section.
(5) Underground natural gas storage. For the equipment/activities
specified in paragraphs (a)(5)(i) through (vii) of this section, report
the information specified in the applicable paragraphs of this section.
* * * * *
(vii) Other large release events. Report the information specified
in paragraph (y) of this section.
(6) LNG storage. For the equipment/activities specified in
paragraphs (a)(6)(i) through (vi) of this section, report the
information specified in the applicable paragraphs of this section.
* * * * *
(vi) Other large release events. Report the information specified
in paragraph (y) of this section.
(7) LNG import and export equipment. For the equipment/activities
specified in paragraphs (a)(7)(i) through (viii) of this section,
report the information specified in the applicable paragraphs of this
section.
(i) Acid gas removal units. Report the information specified in
paragraph (d) of this section.
* * * * *
(viii) Other large release events. Report the information specified
in paragraph (y) of this section.
(8) Natural gas distribution. For the equipment/activities
specified in paragraphs (a)(8)(i) through (iv) of this section, report
the information specified in the applicable paragraphs of this section.
* * * * *
(iv) Other large release events. Report the information specified
in paragraph (y) of this section.
(9) Onshore petroleum and natural gas gathering and boosting. For
the equipment/activities specified in paragraphs (a)(9)(i) through
(xiii) of this section, report the information specified in the
applicable paragraphs 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.
(10) Onshore natural gas transmission pipeline. For blowdown vent
stacks, report the information specified in paragraphs (i) and (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 gas pneumatic devices,
or intermittent bleed natural gas pneumatic devices, then you must
report the information specified in paragraphs (b)(1) through (4) of
this section.
(1) The number of natural gas pneumatic devices as specified in
paragraphs (b)(1)(i) through (iii) of this section.
(i) For onshore natural gas processing, onshore natural gas
transmission compression, and underground natural gas storage
facilities, the total number of devices of each type (continuous low
bleed, continuous high bleed, and intermittent bleed), determined
according to Sec. 98.233(a)(2).
(ii) For onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting facilities, the number
of devices by each type as specified in paragraphs (b)(1)(ii)(A)
through (E) of this section.
(A) Continuous low bleed devices.
(B) Continuous high bleed devices.
(C) Intermittent bleed devices subject to part 60, subpart OOOOb of
this chapter or an applicable approved state plan or applicable Federal
plan in part 62 of this chapter (i.e., the number required to use
Equation W-1B).
(D) Intermittent bleed devices not subject to part 60, subpart
OOOOb of
[[Page 37089]]
this chapter or an applicable approved state plan or applicable Federal
plan in part 62 of this chapter but routinely monitored (i.e., the
number electing to use Equation W-1B).
(E) Intermittent bleed devices not subject to part 60, subpart
OOOOb of this chapter or an applicable approved state plan or
applicable Federal plan in part 62 of this chapter and not routinely
monitored (i.e., the number using Equation W-1A).
(iii) If the reported values in paragraphs (b)(1)(ii)(A), (B), and
(E) of this section are estimated values determined according to Sec.
98.233(a)(3), then you must report the information specified in
paragraphs (b)(1)(iii)(A) through (C) of this section.
(A) The number of devices of each type reported in paragraphs
(b)(1)(ii)(A), (B), and (E) of this section that are counted.
(B) The number of devices of each type reported in paragraphs
(b)(1)(ii)(A), (B), and (E) 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.
(2) For each type of pneumatic device for which Equation W-1A of
this subpart is used, report the information in paragraphs (b)(2)(i)
through (iii) of this section.
(i) The estimated average number of hours in the calendar year that
the natural gas pneumatic devices reported in paragraph (b)(1)(i) or
paragraphs (b)(1)(ii)(A), (B), and (E) of this section, as applicable,
were in service (i.e., supplied with natural gas) in the calendar year
(``Tt'' in Equation W-1A of this subpart).
(ii) Annual CO2 emissions, in metric tons
CO2, for the natural gas pneumatic devices combined,
calculated using Equation W-1A of this subpart and Sec. 98.233(a)(5),
and reported in paragraph (b)(1)(i) or paragraphs (b)(1)(ii)(A), (B),
and (E) of this section, as applicable.
(iii) Annual CH4 emissions, in metric tons
CH4, for the natural gas pneumatic devices combined,
calculated using Equation W-1A of this subpart and Sec. 98.233(a)(5),
and reported in paragraph (b)(1)(i) or paragraphs (b)(1)(ii)(A), (B),
and (E) of this section, as applicable.
(3) For intermittent bleed pneumatic devices for which Equation W-
1B of this subpart is used, report the information in paragraphs
(b)(3)(i) through (iii) of this section.
(i) The total number of intermittent devices detected as
malfunctioning in any pneumatic device monitoring survey during the
calendar year (``x'' in Equation W-1B of this subpart).
(ii) Average time the intermittent devices were in service (i.e.,
supplied with natural gas) and assumed to be malfunctioning in the
calendar year (average value of ``Tz'' in Equation W-1B of
this subpart).
(iii) The total number of intermittent devices that were monitored
but were not detected as malfunctioning in any pneumatic device
monitoring survey during the calendar year (``Count'' in Equation W-1B
of this subpart).
(iv) Average time the intermittent 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-1B of this subpart).
(v) Annual CO2 emissions, in metric tons CO2,
for the natural gas intermittent bleed pneumatic devices combined for
which emissions were calculated using Equation W-1B of this subpart and
Sec. 98.233(a)(6).
(vi) Annual CH4 emissions, in metric tons
CH4, for the natural gas pneumatic devices combined for
which emissions were calculated using Equation W-1B of this subpart and
Sec. 98.233(a)(6).
(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 (6) 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)(1) through (3) of this section.
(1) Count of natural gas driven pneumatic pumps vented directly to
the atmosphere at any point during the year.
(2) Count of natural gas driven pneumatic pumps routed to a flare,
combustion, or vapor recovery system at any point during the year.
(3) Total count of natural gas driven pneumatic pumps at the
facility.
(4) Average estimated number of hours in the calendar year that
natural gas driven pneumatic pumps that vented directly to atmosphere
were in service (i.e., supplied with natural gas) (``T'' in Equation W-
2 of this subpart).
(5) 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)(1) and
(2).
(6) 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)(1) and
(2).
(d) * * *
(1) * * *
(iii) The calculation method used to calculate CO2
emissions from the acid gas removal unit, as specified in Sec.
98.233(d). If the AGR vent was routed to a flare and comingled with
emissions from other sources and you continuously monitor the flow rate
and/or composition, select ``Routed to a flare [Sec.
98.233(d)(12)(ii)]'' as the calculation method.
* * * * *
(2) * * *
(iii) * * *
(L) Solvent type, from one of the following options:
SelexolTM, Rectisol[supreg], PurisolTM, Fluor
SolventSM, BenfieldTM, 20 wt% MEA, 30 wt% MEA, 40
wt% MDEA, 50 wt% MDEA, and other.
(iv) If the AGR vent was routed to a flare, then you must report
the unique name or ID for the flare stack to which the AGR vent is
routed.
(e) Dehydrators. You must indicate whether your facility contains
any of the following equipment: Glycol dehydrators with an annual
average daily natural gas throughput greater than or equal to 0.4
million standard cubic feet per day and glycol dehydrators with an
annual average daily natural gas throughput less than 0.4 million
standard cubic feet per day. 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 that has an annual average daily
natural gas throughput greater than or equal to 0.4 million standard
cubic feet per day (as specified in Sec. 98.233(e)(1)), you must
report the information specified in paragraphs (e)(1)(i) through (xix)
of this section for the dehydrator.
* * * * *
(viii) Whether stripping gas is used in dehydrator.
(A) If stripping gas is used in the dehydrator, type of stripping
gas used (dry natural gas, flash gas, nitrogen/inert gas, other).
(B) If stripping gas is used in the dehydrator, average flow rate
of stripping gas in standard cubic feet per minute.
* * * * *
(xi) Temperature of the wet natural gas at the absorber inlet, in
degrees Fahrenheit.
[[Page 37090]]
(xii) Pressure of the wet natural gas at the absorber inlet, in
pounds per square inch gauge.
* * * * *
(xv) Sub-basin ID that best represents the wells supplying gas to
the dehydrator (for the onshore petroleum and natural gas production
industry segment only) or name of the county that best represents the
equipment supplying gas to the dehydrator (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 (I) of this section for the emissions from the flash tank vent.
(A) Flash tank vent gas flow rate in standard cubic feet per hour.
(B) Flow-weighted average mole fraction of CO2 in flash
tank vent gas (``XCO2'' in Equation W-20 of this subpart if
the flash tank vent gas is routed to a flare).
(C) Flow-weighted average mole fraction of CH4 in flash
tank vent gas (``XCH4'' in Equation W-19 of this subpart if
the flash tank vent gas is routed to a flare).
(D) 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.
(E) 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)(iv), and, if
applicable, (e)(1)(vi)(A).
(F) 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)(iv) and, if
applicable, (e)(1)(vi)(A).
(G) Annual CO2 emissions, in metric tons CO2,
that resulted from routing flash gas to a flare or regenerator firebox/
fire tubes, calculated according to Sec. 98.233(e)(1)(v) and, if
applicable, (e)(1)(vi)(B).
(H) Annual CH4 emissions, in metric tons CH4,
that resulted from routing flash gas to a flare or regenerator firebox/
fire tubes, calculated according to Sec. 98.233(e)(1)(v) and, if
applicable, (e)(1)(vi)(B).
(I) Annual N2O emissions, in metric tons N2O,
that resulted from routing flash gas to a flare or regenerator firebox/
fire tubes, calculated according to Sec. 98.233(e)(1)(v) and, if
applicable, (e)(1)(vi)(B).
(xvii) If flash tank emissions were routed to a flare, then you
must report the information specified in paragraphs (e)(1)(xvii)(A)
through (G) of this section for the flared emissions from the flash
tank vent.
(A) Indicate whether the flare was monitored with a CEMS in
accordance with Sec. 98.233(n)(8). If a CEMS was used, then paragraphs
(e)(1)(xvi)(H) and (I) and (e)(1)(xvii)(B) through (G) of this section
do not apply.
(B) Indicate whether all gas from the flash tank was measured using
a continuous flow monitor.
(C) Indicate whether all gas from the flash tank was measured with
a continuous gas composition analyzer.
(D) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
(E) Total volume of gas from the flash tank to a flare, in standard
cubic feet (``Vs'' in Equations W-19 and W-20 of this
subpart).
(F) Fraction of total flared gas from the flash tank routed to an
un-lit flare (``Zu'' in Equation W-19 of this subpart).
(G) Average flare combustion efficiency, expressed as a fraction of
gas from the flash tank combusted by a burning flare.
(xviii) Report the information specified in paragraphs
(e)(1)(xviii)(A) through (I) of this section for the emissions from the
dehydrator still vent.
(A) Still vent gas flow rate in standard cubic feet per hour.
(B) Flow-weighted average mole fraction of CO2 in still
vent gas (``XCO2'' in Equation W-20 of this subpart if the
flash tank vent gas is routed to a flare).
(C) Flow-weighted average mole fraction of CH4 in still
vent gas (``XCH4'' in Equation W-19 of this subpart if the
flash tank vent gas is routed to a flare).
(D) Whether any still vent emissions are vented directly to the
atmosphere, routed to a flare, routed to the regenerator firebox/fire
tubes, or routed to a vapor recovery system.
(E) 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)(iv), and, if
applicable, (e)(1)(vi)(A).
(F) 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)(iv) and, if
applicable, (e)(1)(vi)(A).
(G) Annual CO2 emissions, in metric tons CO2,
that resulted from routing still vent gas to a flare or regenerator
firebox/fire tubes, calculated according to Sec. 98.233(e)(1)(v) and,
if applicable, (e)(1)(vi)(B).
(H) Annual CH4 emissions, in metric tons CH4,
that resulted from routing still vent gas to a flare or regenerator
firebox/fire tubes, calculated according to Sec. 98.233(e)(1)(v) and,
if applicable, (e)(1)(vi)(B).
(I) Annual N2O emissions, in metric tons N2O,
that resulted from routing still vent gas to a flare or regenerator
firebox/fire tubes, calculated according to Sec. 98.233(e)(1)(v) and,
if applicable, (e)(1)(vi)(B).
(xix) If emissions from the still vent were routed to a flare, then
you must report the information specified in paragraphs (e)(1)(xix)(A)
through (G) of this section for the flared emissions from the still
vent.
(A) Indicate whether the flare was monitored with a CEMS in
accordance with Sec. 98.233(n)(8). If a CEMS was used, then paragraphs
(e)(1)(xviii)(H) and (I) and (e)(1)(xix)(B) through (G) of this section
do not apply.
(B) Indicate whether all gas from the still vent was measured using
a continuous flow monitor.
(C) Indicate whether all gas from the still vent was measured with
a continuous gas composition analyzer.
(D) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
(E) Total volume of gas from the still vent to a flare, in standard
cubic feet (``Vs'' in Equations W-19 and W-20 of this
subpart).
(F) Fraction of total flared gas from the still vent routed to an
un-lit flare (``Zu'' in Equation W-19 of this subpart).
(G) Average flare combustion efficiency, expressed as a fraction of
gas from the still vent combusted by a burning flare.
(2) You must report the information specified in paragraphs
(e)(2)(i) through (v) 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 (as specified in Sec. 98.233(e)(2)) at the facility.
(i) The total number of dehydrators at the facility.
(ii) 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.
[[Page 37091]]
(iii) Whether any dehydrator emissions were routed to a control
device other than a vapor recovery system or a flare or regenerator
firebox/fire tubes. If any dehydrator emissions were routed to a
control device(s) 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.
(iv) 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)(iv)(A) through (L) of this
section.
(A) The total number of dehydrators routed to a flare or
regenerator firebox/fire tubes.
(B) Indicate whether all gas from the dehydrators routed to flares
was measured using a continuous flow monitor.
(C) Indicate whether all gas from the dehydrators routed to flares
was measured with a continuous gas composition analyzer.
(D) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
(E) Total volume of gas from dehydrators to a flare, in standard
cubic feet (``Vs'' in Equations W-19 and W-20 of this
subpart).
(F) Fraction of total flared gas from the dehydrators routed to un-
lit flares (``Zu'' in Equation W-19 of this subpart).
(G) Average flare combustion efficiency, expressed as a fraction of
gas from the dehydrators combusted by a burning flare.
(H) Flow-weighted average mole fraction of CH4 in gas
from the dehydrators routed to a flare (``XCH4'' in Equation
W-19 of this subpart).
(I) Flow-weighted average mole fraction of CO2 in gas
from the dehydrators routed to a flare (``XCO2'' in Equation
W-20 of this subpart).
(J) Annual CO2 emissions, in metric tons CO2,
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this
section, calculated according to Sec. 98.233(e)(5) and, if applicable,
(e)(4)(ii).
(K) Annual CH4 emissions, in metric tons CH4,
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this
section, calculated according to Sec. 98.233(e)(5) and, if applicable,
(e)(4)(ii).
(L) Annual N2O emissions, in metric tons N2O,
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this
section, calculated according to Sec. 98.233(e)(5) and, if applicable,
(e)(4)(ii).
(v) For dehydrator emissions that were not routed to a flare or
regenerator firebox/fire tubes, report the information specified in
paragraphs (e)(2)(v)(A) and (B) of this section.
(A) Annual CO2 emissions, in metric tons CO2,
for emissions from all dehydrators reported in paragraph (e)(2)(i) 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)(i), where emissions are added together for all such
dehydrators.
(B) Annual CH4 emissions, in metric tons CH4,
for emissions from all dehydrators reported in paragraph (e)(2)(i) 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)(i), where emissions are added together for all such
dehydrators.
* * * * *
(f) * * *
(1) For each sub-basin and well tubing diameter and pressure group
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.
* * * * *
(iii) Unloading type combination (with or without plunger lifts,
automated or manual unloading).
* * * * *
(xi) * * *
(F) Unloading type (automated or manual).
(xii) * * *
(F) Unloading type (automated or manual).
(2) For each sub-basin 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.
* * * * *
(iii) Unloading type combination (with or without plunger lifts,
automated or manual unloadings).
* * * * *
(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 wells without plunger lifts, the information in paragraphs
(f)(2)(xi)(A) through (C) of this section.
(A) Average internal casing diameter (average of ``CDp''
from Equation W-8 of this subpart), in inches.
(B) Average well depth (average of ``WDp'' from Equation
W-8 of this subpart), in feet.
(C) Average shut-in pressure, surface pressure, or casing pressure
(average of ``SPp'' from Equation W-8 of this subpart), in
pounds per square inch absolute.
(xii) For wells with plunger lifts, the information in paragraphs
(f)(2)(xii)(A) through (C) of this section.
(A) Average internal tubing diameter (average of ``TDp''
from Equation W-9 of this subpart), in inches.
(B) Average tubing depth (average of ``WDp'' from
Equation W-9 of this subpart), in feet.
(C) Average flow line pressure (average of ``SPp'' from
Equation W-9 of this subpart), in pounds per square inch absolute.
(g) * * *
(10) If the well emissions were routed to a flare, then you must
report the information specified in paragraphs (g)(10)(i) through (xi)
of this section.
(i) Indicate whether the total emissions reported under paragraphs
(g)(8) and (9) of this section include vented emissions during the
initial flowback period.
(ii) Indicate whether the flare was monitored with a CEMS in
accordance with Sec. 98.233(n)(8). If a CEMS was used, then paragraph
(g)(9) and paragraphs (g)(10)(iii) through (xi) of this section do not
apply.
(iii) Indicate whether all of the gas from completions and
workovers was measured using continuous flow monitors.
(iv) Indicate whether all of the gas streams from completions and
workovers were measured with continuous gas composition analyzers.
(v) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
(vi) Total volume of gas from completions and workovers to all
flares, in standard cubic feet (``Vs'' in Equations W-19 and
W-20 of this subpart).
(vii) Fraction of total flared gas from completions and workovers
routed to
[[Page 37092]]
un-lit flares (``Zu'' in Equation W-19 of this subpart).
(viii) Average flare combustion efficiency, expressed as a fraction
of gas from completions and workovers combusted by a burning flare.
(ix) Flow-weighted average mole fraction of CH4 in gas
from completions and workovers routed to flares (``XCH4'' in
Equation W-19 of this subpart).
(x) Flow-weighted average mole fraction of CO2 in gas
from completions and workovers routed to flares (``XCO2'' in
Equation W-20 of this subpart).
(xi) Total N2O emissions, in metric tons N2O.
(h) * * *
(2) For each sub-basin with gas well completions without hydraulic
fracturing and with flaring, report the information specified in
paragraphs (h)(2)(i) through (xvi) of this section.
* * * * *
(v) Indicate whether the flare was monitored with a CEMS in
accordance with Sec. 98.233(n)(8). If a CEMS was used, then paragraphs
(h)(2)(vi) through (xii), (xiv), and (xv) of this section do not apply.
(vi) Indicate whether all of the gas from completions was measured
using continuous flow monitors.
(vii) Indicate whether all of the gas streams from completions were
measured with continuous gas composition analyzers.
(viii) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
(ix) Total volume of gas from completions to all flares, in
standard cubic feet (``Vs'' in Equations W-19 and W-20 of
this subpart).
(x) Fraction of total flared gas from completions routed to un-lit
flares (``Zu'' in Equation W-19 of this subpart).
(xi) Average flare combustion efficiency, expressed as a fraction
of gas from completions combusted by a burning flare.
(xii) Flow-weighted average mole fraction of CH4 in gas
from completions routed to flares (``XCH4'' in Equation W-19
of this subpart).
(xiii) Flow-weighted average mole fraction of CO2 in gas
from completions routed to flares (``XCO2'' in Equation W-20
of this subpart).
(xiv) Annual CO2 emissions, in metric tons
CO2, that resulted from completions that flared gas
calculated according to Sec. 98.233(h)(2).
(xv) Annual CH4 emissions, in metric tons
CH4, that resulted from completions that flared gas
calculated according to Sec. 98.233(h)(2).
(xvi) Annual N2O emissions, in metric tons
N2O, that resulted from completions that flared gas
calculated according to Sec. 98.233(h)(2).
* * * * *
(4) For each sub-basin with gas well workovers without hydraulic
fracturing and with flaring, report the information specified in
paragraphs (h)(4)(i) through (xiv) of this section.
* * * * *
(iii) Indicate whether the flare was monitored with a CEMS in
accordance with Sec. 98.233(n)(8). If a CEMS was used, then paragraphs
(h)(4)(iv) through (x), (xii), and (xiii) of this section do not apply.
(iv) Indicate whether all of the gas from workovers was measured
using continuous flow monitors.
(v) Indicate whether all of the gas streams from workovers were
measured with continuous gas composition analyzers.
(vi) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
(vii) Total volume of gas from workovers to all flares, in standard
cubic feet (``Vs'' in Equations W-19 and W-20 of this
subpart).
(viii) Fraction of total flared gas from workovers routed to un-lit
flares (``Zu'' in Equation W-19 of this subpart).
(ix) Average flare combustion efficiency, expressed as a fraction
of gas from workovers combusted by a burning flare.
(x) Flow-weighted average mole fraction of CH4 in gas
from workovers routed to flares (``XCH4'' in Equation W-19
of this subpart).
(xi) Flow-weighted average mole fraction of CO2 in gas
from workovers routed to flares (``XCO2'' in Equation W-20
of this subpart).
(xii) Annual CO2 emissions, in metric tons
CO2 per year, that resulted from workovers that flared gas
calculated as specified in Sec. 98.233(h)(2).
(xiii) Annual CH4 emissions, in metric tons
CH4 per year, that resulted from workovers that flared gas,
calculated as specified in Sec. 98.233(h)(2).
(xiv) Annual N2O emissions, in metric tons
N2O per year, that resulted from workovers that flared gas
calculated as specified in Sec. 98.233(h)(2).
(i) * * *
(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) for onshore natural gas processing, onshore natural
gas transmission compression, 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 (iii) 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 (iii) 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) for the onshore natural gas transmission pipeline
segment, then you must report the pipeline segments or event types and
the information specified in paragraphs (i)(1)(i) through (iii) 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 (iii) of
this section for the ``equipment or event type'' (i.e., category) that
represented the largest portion of the emissions for the blowdown
event.
* * * * *
(j) Onshore production and onshore petroleum and natural gas
gathering and boosting storage tanks. You must indicate whether your
facility sends hydrocarbon produced liquids to atmospheric tanks. If
your facility sends hydrocarbon produced liquids to atmospheric 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 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.
(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 sub-basin (for onshore production) or county (for
onshore petroleum and natural gas gathering and
[[Page 37093]]
boosting) and by calculation method. Onshore petroleum and natural gas
gathering and boosting facilities do not report the information
specified in paragraph (j)(1)(ix) of this section.
(i) Sub-basin ID (for onshore production) or county name (for
onshore petroleum and natural gas gathering and boosting).
(ii) Calculation method used, and name of the software package used
if using Calculation Method 1.
(iii) The total annual hydrocarbon liquids volume from gas-liquid
separators and direct from wells or non-separator equipment that is
sent to applicable onshore production and onshore petroleum and natural
gas gathering and boosting 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 production greater
than or equal to 10 barrels per day and flowing to gas-liquid
separators or direct to 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
from all wells and the well ID number(s) for the well(s) included in
this volume.
(iv) The average gas-liquid separator or non-separator equipment
temperature, in degrees Fahrenheit.
(v) The average gas-liquid separator or non-separator equipment
pressure, in pounds per square inch gauge.
(vi) The average sales oil or stabilized hydrocarbon liquids API
gravity, in degrees.
(vii) The flow-weighted average concentration (mole fraction) of
CO2 in flash gas from onshore production and onshore natural
gas gathering and boosting storage tanks (calculated as the sum of all
products of the concentration of CO2 in the flash gas for
each storage tank times the throughput for that storage tank, divided
by the sum of all throughputs from storage tanks) (``XCO2''
in Equation W-20 of this subpart if the flash gas is routed to a
flare).
(viii) The flow-weighted average concentration (mole fraction) of
CH4 in flash gas from onshore production and onshore natural gas
gathering and boosting storage tanks (calculated as the sum of all
products of the concentration of CH4 in the flash gas for
each storage tank times the throughput for that storage tank, divided
by the sum of all throughputs from storage tanks) (``XCH4''
in Equation W-19 of this subpart and ``Y1'' in Equation W-20
of this subpart if the flash gas is routed to a flare).
(ix) The number of wells sending hydrocarbon liquids to gas-liquid
separators or directly to atmospheric tanks.
(x) Count of atmospheric tanks specified in paragraphs (j)(1)(x)(A)
through (D) of this section.
(A) The number of atmospheric tanks.
(B) The number of atmospheric tanks that vented gas directly to the
atmosphere and did not control emissions using a vapor recovery system
or one or more flares at any point during the reporting year.
(C) The number of atmospheric tanks that routed emissions to vapor
recovery and/or one or more flares at any point during the reporting
year.
(D) The number of atmospheric tanks in paragraph (j)(1)(x)(C) of
this section that had an open or unseated thief hatch at some point
during the year while the tank was also routing emissions to a vapor
recovery system and/or a flare.
(xi) For the atmospheric tanks at your facility identified in
paragraph (j)(1)(x)(B) of this section, you must report the information
specified in paragraphs (j)(1)(xi)(A) and (B) of this section.
(A) 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).
(B) 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).
(xii) For the atmospheric tanks at your facility identified in
paragraph (j)(1)(x)(C) of this section, you must report the information
specified in paragraphs (j)(1)(xii)(A) through (N) of this section.
(A) Annual CO2 emissions, in metric tons CO2,
that resulted from venting gas directly to the atmosphere, calculated
according to Sec. 98.233(j)(1), (2), and (4).
(B) Annual CH4 emissions, in metric tons CH4,
that resulted from venting gas directly to the atmosphere, calculated
according to Sec. 98.233(j)(1), (2), and (4).
(C) Indicate whether the flare was monitored with a CEMS in
accordance with Sec. 98.233(n)(8). If a CEMS was used, then paragraphs
(j)(1)(xii)(D) through (K), (M), and (N) of this section do not apply.
(D) Indicate whether all of the gas from the atmospheric tanks in
the applicable sub-basin or county and subject to this paragraph
(j)(1)(xii) was measured using a continuous flow monitor.
(E) Indicate whether all of the gas from the atmospheric tanks in
the applicable sub-basin or county and subject to this paragraph
(j)(1)(xii) was measured with a continuous gas composition analyzer.
(F) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
(G) Total volume of gas from the atmospheric tanks in the
applicable sub-basin or county and subject to this paragraph
(j)(1)(xii) that was routed to a flare, in standard cubic feet
(``Vs'' in Equations W-19 and W-20 of this subpart).
(H) Fraction of total flared gas from the atmospheric tanks in the
applicable sub-basin or county and subject to this paragraph
(j)(1)(xii) that was routed to un-lit flares (``Zu'' in
Equation W-19 of this subpart).
(I) Average flare combustion efficiency, expressed as a fraction of
gas from the atmospheric tanks in the applicable sub-basin or county
and subject to this paragraph (j)(1)(xii) combusted by a burning flare.
(J) Annual CO2 emissions, in metric tons CO2,
from flares used to control emissions, calculated according to Sec.
98.233(j)(5).
(K) Annual CH4 emissions, in metric tons CH4,
from flares used to control emissions, calculated according to Sec.
98.233(j)(5).
(L) Annual N2O emissions, in metric tons N2O,
from flares used to control emissions, calculated according to Sec.
98.233(j)(5).
(M) Total CO2 mass, in metric tons CO2, that
was recovered during the calendar year using a vapor recovery system.
(N) Total CH4 mass, in metric tons CH4, that
was recovered during the calendar year using a vapor recovery system.
(xiii) For the atmospheric tanks at your facility identified in
paragraph (j)(1)(x)(D) of this section, the total volume of gas vented
through open or unseated thief hatches, in scf, during periods while
the 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 (E) of this section, at the basin level, for atmospheric 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 tanks in the basin, in
[[Page 37094]]
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 less than 10 barrels per day and that send
hydrocarbon liquids to atmospheric tanks. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec. 98.236(cc) the total annual hydrocarbon liquids throughput
from all wells and the well ID number(s) for the well(s) included in
this volume.
(B) An estimate of the fraction of hydrocarbon liquids throughput
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric
tanks in the basin that controlled emissions with flares.
(C) An estimate of the fraction of hydrocarbon liquids throughput
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric
tanks in the basin that controlled emissions with vapor recovery
systems.
(D) The number of atmospheric tanks in the basin.
(E) The total number of separators, wells, or non-separator
equipment (``Count'' from Equation W-15 of this subpart) in the basin.
(ii) Report the information specified in paragraphs (j)(2)(ii)(A)
through (D) of this section for each sub-basin (for onshore production)
or county (for onshore petroleum and natural gas gathering and
boosting) with atmospheric tanks whose emissions were calculated using
Calculation Method 3 of Sec. 98.233(j) and that either did not control
emissions with flares or that used flares to control emissions from
less than half the annual hydrocarbon liquids received.
(A) Sub-basin ID (for onshore production) or county name (for
onshore petroleum and natural gas gathering and boosting).
(B) The number of atmospheric tanks in the sub-basin (for onshore
production) or county (for onshore petroleum and natural gas gathering
and boosting) that did not control emissions with flares and for which
emissions were calculated using Calculation Method 3.
(C) Annual CO2 emissions, in metric tons CO2,
from atmospheric tanks in the sub-basin (for onshore production) or
county (for onshore petroleum and natural gas gathering and boosting)
that did not control emissions with flares, calculated using Equation
W-15 of Sec. 98.233(j) and adjusted using the requirements described
in Sec. 98.233(j)(4), if applicable.
(D) Annual CH4 emissions, in metric tons CH4,
from atmospheric tanks in the sub-basin (for onshore production) or
county (for onshore petroleum and natural gas gathering and boosting)
that did not control emissions with flares, calculated using Equation
W-15 of Sec. 98.233(j) and adjusted using the requirements described
in Sec. 98.233(j)(4), if applicable.
(iii) Report the information specified in paragraphs (j)(2)(iii)(A)
through (N) of this section for each sub-basin (for onshore production)
or county (for onshore petroleum and natural gas gathering and
boosting) with atmospheric tanks whose emissions were calculated using
Calculation Method 3 of Sec. 98.233(j) and that used flares to control
emissions from at least half the annual hydrocarbon liquids received.
(A) Sub-basin ID (for onshore production) or county name (for
onshore petroleum and natural gas gathering and boosting).
(B) The number of atmospheric tanks in the sub-basin (for onshore
production) or county (for onshore petroleum and natural gas gathering
and boosting) that controlled emissions with flares and for which
emissions were calculated using Calculation Method 3.
(C) Indicate whether the flare was monitored with a CEMS in
accordance with Sec. 98.233(n)(8). If a CEMS was used, then paragraphs
(j)(2)(iii)(D) through (K), (M), and (N) of this section do not apply.
(D) Indicate whether all of the gas from the atmospheric tanks in
the applicable sub-basin or county and subject to this paragraph
(j)(2)(iii) was measured using a continuous flow monitor.
(E) Indicate whether all of the gas from the atmospheric tanks in
the applicable sub-basin or county and subject to this paragraph
(j)(2)(iii) was measured with a continuous gas composition analyzer.
(F) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
(G) Total volume of gas from the atmospheric tanks in the
applicable sub-basin or county and subject to this paragraph
(j)(2)(iii) that was routed to a flare, in standard cubic feet
(``Vs'' in Equations W-19 and W-20 of this subpart).
(H) Fraction of total flared gas from the atmospheric tanks in the
applicable sub-basin or county and subject to this paragraph
(j)(2)(iii) that was routed to un-lit flares (``Zu'' in
Equation W-19 of this subpart).
(I) Average flare combustion efficiency, expressed as a fraction of
gas from the atmospheric tanks in the applicable sub-basin or county
and subject to this paragraph (j)(2)(iii) combusted by a burning flare.
(J) Flow-weighted average mole fraction of CH4 in gas
from the atmospheric tanks in the applicable sub-basin or county and
subject to this paragraph (j)(2)(iii) and routed to a flare
(``XCH4'' in Equation W-19 of this subpart).
(K) Flow-weighted average mole fraction of CO2 in gas
from the atmospheric tanks in the applicable sub-basin or county and
subject to this paragraph (j)(2)(iii) and routed to a flare
(``XCO2'' in Equation W-20 of this subpart).
(L) Annual CO2 emissions, in metric tons CO2,
from atmospheric tanks that controlled emissions with flares,
calculated according to Sec. 98.233(j)(5) and adjusted using the
requirements described in Sec. 98.233(j)(4), if applicable.
(M) Annual CH4 emissions, in metric tons CH4,
from atmospheric tanks that controlled emissions with flares,
calculated according to Sec. 98.233(j)(5) and adjusted using the
requirements described in Sec. 98.233(j)(4), if applicable.
(N) Annual N2O emissions, in metric tons N2O,
from atmospheric tanks that controlled emissions with flares,
calculated according to Sec. 98.233(j)(5).
(3) * * *
(ii) 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).
* * * * *
(k) * * *
(1) * * *
(ii) Indicate if there is a flare attached to the transmission
storage tank vent stack.
(iii) Method used to determine if dump valve leakage occurred.
(iv) Indicate whether scrubber dump valve leakage occurred for the
transmission storage tank vent according to Sec. 98.233(k)(2) or Sec.
98.233(k)(5).
(2) If scrubber dump valve leakage occurred for a transmission
storage tank vent stack, as reported in paragraph (k)(1)(iv) 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 transmission
storage vent stack where scrubber dump valve leakage occurred.
* * * * *
[[Page 37095]]
(3) If scrubber dump valve leakage occurred for a transmission
storage tank vent stack, as reported in paragraph (k)(1)(iv) of this
section, and the vent stack routed to a flare during the calendar year,
then you must report the information specified in paragraphs (k)(3)(i)
through (iii) of this section.
(i) Indicate whether leak rate was determined using a continuous
flow measurement device for the duration of the time that flaring
occurred or if an annual measurement was conducted in accordance with
paragraph (k)(1)(ii) of this section.
(ii) Measured leakage rate (average leak rate from a continuous
flow measurement device) in standard cubic feet per hour.
(iii) Duration of time that flaring occurred in hours, as defined
in Sec. 98.233(k)(3) (may use best available data if a continuous flow
measurement device was used).
(l) * * *
(1) If you used Equation W-17A of Sec. 98.233 to calculate annual
volumetric natural gas emissions at actual conditions from oil wells
and the emissions are not routed to a flare, then you must report the
information specified in paragraphs (l)(1)(i) through (vii) of this
section.
* * * * *
(2) If you used Equation W-17A of Sec. 98.233 to calculate annual
volumetric natural gas emissions at actual conditions from oil wells
and the emissions are routed to a flare, then you must report the
information specified in paragraphs (l)(2)(i) through (xvii) of this
section. All reported data elements should be specific to the wells for
which Equation W-17A of Sec. 98.233 was used and for which well
testing emissions were routed to flares.
* * * * *
(vi) Indicate whether the flare was monitored with a CEMS in
accordance with Sec. 98.233(n)(8). If a CEMS was used, then paragraphs
(l)(2)(vii) through (xiv), (xvi), and (xvii) of this section do not
apply.
(vii) Indicate whether all of the gas from well testing routed to
flares was measured using continuous flow monitors.
(viii) Indicate whether all of the gas streams from well testing
routed to flares were measured with continuous gas composition
analyzers.
(ix) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
(x) Total volume of gas from well testing routed to all flares, in
standard cubic feet (``Vs'' in Equations W-19 and W-20 of
this subpart).
(xi) Fraction of total flared gas from well testing routed to un-
lit flares (``Zu'' in Equation W-19 of this subpart).
(xii) Average flare combustion efficiency, expressed as a fraction
of gas from well testing combusted by a burning flare.
(xiii) Flow-weighted average mole fraction of CH4 in gas
from well testing routed to flares (``XCH4'' in Equation W-
19 of this subpart).
(xiv) Flow-weighted average mole fraction of CO2 in gas
from well testing routed to flares (``XCO2'' in Equation W-
20 of this subpart).
(xv) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec. 98.233(l).
(xvi) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec. 98.233(l).
(xvii) Annual N2O emissions, in metric tons N2O,
calculated according to Sec. 98.233(l).
(3) If you used Equation W-17B of Sec. 98.233 to calculate annual
volumetric natural gas emissions at actual conditions from gas wells
and the emissions were not routed to a flare, then you must report the
information specified in paragraphs (l)(3)(i) through (vi) of this
section.
* * * * *
(4) If you used Equation W-17B of Sec. 98.233 to calculate annual
volumetric natural gas emissions at actual conditions from gas wells
and the emissions were routed to a flare, then you must report the
information specified in paragraphs (l)(4)(i) through (xvi) of this
section. All reported data elements should be specific to the wells for
which Equation W-17B of Sec. 98.233 was used and for which well
testing emissions were routed to flares.
* * * * *
(v) Indicate whether the flare was monitored with a CEMS in
accordance with Sec. 98.233(n)(8). If a CEMS was used, then paragraphs
(l)(4)(vi) through (xiii), (xv), and (xvi) of this section do not
apply.
(vi) Indicate whether all of the gas from well testing routed to
flares was measured using continuous flow monitors.
(vii) Indicate whether all of the gas streams from well testing
routed to flares were measured with continuous gas composition
analyzers.
(viii) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
(ix) Total volume of gas from well testing routed to all flares, in
standard cubic feet (``Vs'' in Equations W-19 and W-20 of
this subpart).
(x) Fraction of total flared gas from well testing routed to un-lit
flares (``Zu'' in Equation W-19 of this subpart).
(xi) Average flare combustion efficiency, expressed as a fraction
of gas from well testing combusted by a burning flare.
(xii) Flow-weighted average mole fraction of CH4 in gas
from well testing routed to flares (``XCH4'' in Equation W-
19 of this subpart).
(xiii) Flow-weighted average mole fraction of CO2 in gas
from well testing routed to flares (``XCO2'' in Equation W-
20 of this subpart).
(xiv) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec. 98.233(l).
(xv) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec. 98.233(l).
(xvi) Annual N2O emissions, in metric tons
N2O, calculated according to Sec. 98.233(l).
(m) * * *
(4) Average gas to oil ratio, in standard cubic feet of gas per
barrel of oil (average of the ``GOR'' values used in Equation W-18 of
this subpart). 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 in the sub-basin (i.e., if
you did not use Equation W-18 for any wells with associated gas venting
or flaring emissions in the sub-basin).
(5) Volume of oil produced, in barrels, in the calendar year only
during the time periods in which associated gas was vented or flared
(the sum of ``Vp,q'' 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 wildcat wells and/or delineation wells are the only
wells from which associated gas was vented or flared. If you elect to
delay reporting of this data element, you must report by the date
specified in Sec. 98.236(cc) the volume of oil produced for well(s)
with associated gas venting and flaring and the well ID number(s) for
the well(s) included in the measurement. 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 in the sub-basin (i.e., if you did not
use Equation W-18 for any wells with associated gas venting or flaring
emissions in the sub-basin).
[[Page 37096]]
(6) Total volume of associated gas sent to sales, in standard cubic
feet, in the calendar year only during time periods in which associated
gas was vented or flared (the sum of ``SG'' values 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 wildcat wells and/or delineation
wells are the only wells from which associated gas was vented or
flared. 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 well(s) with
associated gas venting and flaring and the well ID number(s) for the
well(s) included in the measurement. 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 in the sub-basin (i.e., if you did not
use Equation W-18 for any wells with associated gas venting or flaring
emissions in the sub-basin).
(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 sub-basin.
(i) Total number of wells for which associated gas was vented
directly to the atmosphere without flaring and a list of their well ID
numbers.
(ii) Indicate whether all of the associated gas volume vented in
the sub-basin was measured using continuous flow monitors.
(iii) Indicate whether all associated gas streams vented in the
sub-basin were measured with continuous gas composition analyzers.
(iv) Total volume of associated gas vented in the sub-basin, in
standard cubic feet.
(v) Flow-weighted average mole fraction of CH4 in
associated gas vented in the sub-basin.
(vi) Flow-weighted average mole fraction of CO2 in
associated gas vented in the sub-basin.
(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).
(8) If you had associated gas emissions that were flared, then you
must report the information specified in paragraphs (m)(8)(i) through
(xiii) of this section for each sub-basin.
(i) Total number of wells for which associated gas was flared and a
list of their well ID numbers.
(ii) Indicate whether the flare was monitored with a CEMS in
accordance with Sec. 98.233(n)(8). If a CEMS was used, then paragraphs
(m)(8)(iii) through (x), (xii), and (xiii) of this section do not
apply.
(iii) Indicate whether all of the associated gas volume routed to
flares in the sub-basin was measured using continuous flow monitors.
(iv) Indicate whether all associated gas streams routed to flares
in the sub-basin were measured with continuous gas composition
analyzers.
(v) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
(vi) Total volume of associated gas routed to all flares in the
sub-basin, in standard cubic feet (``Vs'' in Equations W-19
and W-20 of this subpart).
(vii) Fraction of total flared associated gas in the sub-basin
routed to un-lit flares (``Zu'' in Equation W-19 of this
subpart).
(viii) Average flare combustion efficiency, expressed as a fraction
of associated gas combusted by a burning flare.
(ix) Flow-weighted average mole fraction of CH4 in
associated gas routed to flares in the sub-basin (``XCH4''
in Equation W-19 of this subpart).
(x) Flow-weighted average mole fraction of CO2 in
associated gas routed to flares in the sub-basin (``XCO2''
in Equation W-20 of this subpart).
(xi) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec. 98.233(m)(5).
(xii) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec. 98.233(m)(5).
(xiii) Annual N2O emissions, in metric tons
N2O, calculated according to Sec. 98.233(m)(5).
(n) Flare stacks. You must indicate if your facility has any flare
stacks to which emissions are routed from miscellaneous flared sources
(i.e., sources other than those subject to Sec. 98.233(e), (g), (h),
(j), (l), or (m), as applicable for the industry segment). If you have
any miscellaneous flared sources, you must report the information
specified in paragraph (n)(1) of this section for each flare used to
control emissions from such sources. Additionally, for each flare at
your facility, regardless of the source(s) controlled, you must report
the information specified in paragraph (n)(2) of this section.
(1) For each flare stack used to control miscellaneous flared
sources, you must report the information specified in paragraph
(n)(1)(i) through (xiv) of this section.
(i) 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.
(ii) Indicate whether the flare stack has a continuous flow
measurement device.
(iii) Indicate whether the flare stack has a continuous gas
composition analyzer on feed gas to the flare.
(iv) Indicate whether only the default HHV, only a site-specific
HHV(s), or both the default and site-specific HHVs (depending on the
stream to the flare) were used in Equation W-40 to calculate
N2O emissions.
(v) 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).
(vi) Volume of gas from miscellaneous flared sources sent to the
flare, in standard cubic feet (``Vs'' in Equations W-19 and
W-20 of this subpart).
(vii) Fraction of the feed gas sent to an un-lit flare
(``Zu'' in Equation W-19 of this subpart).
(viii) Flare combustion efficiency, expressed as the fraction of
gas combusted by a burning flare.
(ix) Flow-weighted average mole fraction of CH4 in the
feed gas from miscellaneous flared sources to the flare
(``XCH4'' in Equation W-19 of this subpart).
(x) Flow-weighted average mole fraction of CO2 in the
feed gas from miscellaneous flared sources to the flare
(``XCO2'' in Equation W-20 of this subpart).
(xi) Annual CO2 emissions, in metric tons CO2
(refer to Equation W-20 of this subpart). If gas from an acid gas
removal unit is routed to the flare, then the CO2 emissions
to report should exclude the CO2 emissions reported under
paragraph (d)(1)(v) of this section to prevent double counting of
emissions.
(xii) Annual CH4 emissions, in metric tons
CH4 (refer to Equation W-19 of this subpart).
(xiii) Annual N2O emissions, in metric tons
N2O (refer to Equation W-40 of this subpart).
(xiv) Indicate whether a CEMS was used to measure emissions from
the flare. If a CEMS was used to measure emissions from the flare, then
the information specified in paragraphs
[[Page 37097]]
(n)(1)(ii) through (x), (xii), and (xiii) of this section do not apply
for that flare; report only the CO2 emissions as specified
in paragraph (n)(1)(xi) of this section.
(2) For each flare stack at your facility, you must report the
information specified in paragraphs (n)(2)(i) through (ix) of this
section.
(i) Unique name or ID for the flare stack.
(ii) Indicate each emission source type that routed emissions to
the flare stack during the reporting year (i.e., dehydrator vents, well
venting during completions and workovers with hydraulic fracturing, gas
well venting during completions and workovers without hydraulic
fracturing, onshore production and onshore petroleum and natural gas
gathering and boosting storage tanks, well testing venting and flaring,
associated gas venting and flaring, miscellaneous flared sources).
(iii) Total volume of gas routed to the flare.
(iv) Indicate the type of flare (i.e., open ground-level flare,
enclosed ground-level flare, open elevated flare, or enclosed elevated
flare).
(v) 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).
(vi) Indicate whether the flare has a continuous pilot or
autoigniter.
(vii) If the flare has a continuous pilot, indicate whether the
presence of flame is continuously monitored.
(viii) If the flare has a continuous pilot and the presence of a
flame is not continuously monitored, indicate how periods when the
pilot is not lit are identified (i.e., assumed pilot is always lit,
assumed pilot was unlit for a fixed number of hours or fraction of
operating hours, visual observations of flare flame, other (specify)).
(ix) Estimated fraction of the total volume routed to the flare
when it was not lit.
(o) * * *
(1) Compressor activity data. Report the information specified in
paragraphs (o)(1)(i) through (x) of this section, as applicable, for
each centrifugal compressor located at your facility.
(i) Unique name or ID for the centrifugal compressor.
(ii) Hours in operating-mode.
(iii) Hours in standby-pressurized-mode.
(iv) Hours in not-operating-depressurized-mode.
(v) 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.
(vi) Indicate whether the compressor has blind flanges installed
and associated dates.
(vii) Indicate whether the compressor has wet or dry seals.
(viii) If the compressor has wet seals, the number of wet seals.
(ix) If the compressor has dry seals, the number of dry seals.
(x) Power output of the compressor driver (hp).
(2) * * *
(i) * * *
(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.
* * * * *
(5) * * *
(i) 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).
(ii) Annual CO2 emissions, in metric tons
CO2, from centrifugal compressors with atmospheric wet seal
oil degassing vents.
(iii) Annual CH4 emissions, in metric tons
CH4, from centrifugal compressors with atmospheric wet seal
oil degassing vents.
(p) * * *
(1) Compressor activity data. Report the information specified in
paragraphs (p)(1)(i) through (vii) of this section, as applicable, for
each reciprocating compressor located at your facility.
(i) Unique name or ID for the reciprocating compressor.
(ii) Hours in operating-mode.
(iii) Hours in standby-pressurized-mode.
(iv) Hours in not-operating-depressurized-mode.
(v) 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.
(vi) Indicate whether the compressor has blind flanges installed
and associated dates.
(vii) 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.
* * * * *
(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) * * *
(i) 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 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).
(ii) Annual CO2 emissions, in metric tons
CO2, from reciprocating compressors with rod packing
emissions vented to the atmosphere.
(iii) Annual CH4 emissions, in metric tons
CH4, from reciprocating compressors with rod packing
emissions vented to the atmosphere.
(q) * * *
(1) You must report the information specified in paragraphs
(q)(1)(i) through (vii) of this section.
* * * * *
(iii) 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)(iii)(A) through (E) of this section.
Report the indication per facility, not per component type, and
indicate all that apply for the facility.
[[Page 37098]]
(A) The well site or compressor station fugitive emissions
standards in Sec. 60.5397a of this chapter.
(B) The well site or compressor station fugitive emissions
standards in part 60, subpart OOOOb of this chapter.
(C) The well site 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 plants
in part 60, subpart OOOOb of this chapter.
(E) The standards for equipment leaks at onshore natural gas plants
in an applicable approved state plan or applicable Federal plan in part
62 of this chapter.
* * * * *
(vi) Report whether emissions were calculated using Calculation
Method 1 (leaker factor emission calculation methodology) and/or using
Calculation Method 2 (leaker measurement methodology).
(vii) 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-
1A) by service type for which leak detection surveys were conducted and
emissions calculated according to Sec. 98.233(q).
(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 that is
located at your facility, you must report the information specified in
paragraphs (q)(2)(i) through (v) of this section. If a component type
is located at your facility and no leaks were identified from that
component, then you must report the information in paragraphs (q)(2)(i)
through (v) of this section but report a zero (``0'') for the
information required according to paragraphs (q)(2)(ii) through (v) 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 (v) of this section separately for component surveys
using Calculation Method 1 and Calculation Method 2.
(i) Component type.
(ii) Total number of the surveyed component type 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)(i)).
(iii) 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)).
(iv) Annual CO2 emissions, in metric tons
CO2, for the component type as calculated using Equation W-
30 or Sec. 98.233(q)(3)(vi) (for surveyed components only).
(v) Annual CH4 emissions, in metric tons CH4,
for the component type as calculated using Equation W-30 or Sec.
98.233(q)(3)(vi) (for surveyed components only).
* * * * *
(r) * * *
(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 (v) of this section separately for each emission source type
required to use Equation W-32A that is located at your facility.
Onshore petroleum and natural gas production facilities and onshore
petroleum and natural gas gathering and boosting facilities must report
the information specified in paragraphs (r)(1)(i) through (v)
separately by equipment type and service type.
(i) 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.
* * * * *
(s) Offshore petroleum and natural gas production. You must report
the information specified in paragraphs (s)(1) through (3) of this
section for each emission source type listed in the most recent BOEM
study.
* * * * *
(y) Other large release events. You must indicate whether there
were any other large release events from your facility during the
reporting year. 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 other
large release event, report the information specified in paragraphs
(y)(1) through (8) of this section.
(1) Unique release event identification number (e.g., Event 1,
Event 2).
(2) The approximate start date, start time, and duration (in hours)
of the release event.
(3) 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: fire/explosion, gas well blowout, oil well
blowout, gas well release, oil well release, pressure relief, large
leak, and other (specify).
(iii) A description of the technology or method used to identify
the release.
(iv) An indication of whether the release was identified under the
provisions of part 60, subpart OOOOb of this chapter or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter.
(v) 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.
(4) The total volume of gas released during the event in standard
cubic feet.
(5) The volume fraction of CO2 in the gas released
during the event.
(6) The volume fraction of CH4 in the gas released
during the event.
(7) Annual CO2 emissions, in metric tons CO2,
from the release event.
(8) Annual CH4 emissions, in metric tons CH4,
from the release event.
(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)(xix), (a)(8)(i), or (a)(9)(xiii) of this
section. If your facility contains any combustion units subject to
reporting according to paragraph (a)(1)(xix), (a)(8)(i), 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.
* * * * *
(2) * * *
(i) The type of combustion unit. For internal fuel combustion units
of any heat capacity that are compressor-drivers, you must also specify
the design class as: 2-stroke lean-burn, 4-
[[Page 37099]]
stroke lean-burn, 4-stroke rich-burn, or other.
* * * * *
(iv) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec. 98.233(z)(1) through (3).
(v) Annual CH4 emissions, in metric tons CH4,
calculated according to Sec. 98.233(z)(1) through (3).
(vi) Annual N2O emissions, in metric tons
N2O, calculated according to Sec. 98.233(z)(1) through (3).
(aa) * * *
(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 (viii) of this section. Otherwise, report the
information specified in paragraphs (aa)(3)(i) through (viii) 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.
* * * * *
(10) For onshore petroleum and natural gas gathering and boosting
facilities, report the quantities specified in paragraphs (aa)(10)(i)
through (vi) of this section.
* * * * *
(v) The number of compressor stations in the facility.
(vi) The number of centralized oil production sites in the
facility.
(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.
* * * * *
(bb) 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) 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.
0
60. Amend Sec. 98.238 by:
0
a. Adding a definition for ``Centralized oil production site'' in
alphabetical order;
0
b. Revising the definitions for ``Compressor mode'' and ``Compressor
source'';
0
c. Adding a definition for ``Compressor station'' in alphabetical
order;
0
d. 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
e. Revising the definitions for ``Flare stack emissions'' and ``Forced
extraction of natural gas liquids''; and
0
f. Adding definitions for ``Other large release event,'' ``Routed to
combustion'', ``Well blowout'', and ``Well release'' in alphabetical
order.
The additions and revisions read as follows:
Sec. 98.238 Definitions.
* * * * *
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.
* * * * *
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.
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.
* * * * *
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
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.
* * * * *
Other large release event means an unplanned, unexpected, and
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 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 onshore production and
onshore petroleum and natural gas gathering and boosting storage tanks,
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
[[Page 37100]]
that source using applicable methods in Sec. 98.233 by the threshold
in Sec. 98.233(y).
* * * * *
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.
* * * * *
0
61. Revise table W-1A to subpart W of part 98 to read as follows:
Table W-1A to Subpart W of Part 98--Default Whole Gas Emission Factors
for Onshore Petroleum and Natural Gas Production Facilities and Onshore
Petroleum and Natural Gas Gathering and Boosting Facilities
------------------------------------------------------------------------
Onshore petroleum and natural gas production
and onshore petroleum and natural gas gathering Emission factor (scf/
and boosting hour/component)
------------------------------------------------------------------------
Population Emission Factors--Pneumatic Device Vents and Pneumatic Pumps,
Gas Service \1\
------------------------------------------------------------------------
Continuous Low Bleed Pneumatic Device Vents \2\ 6.8
Continuous High Bleed Pneumatic Device Vents 21.2
\2\...........................................
Intermittent Bleed Pneumatic Device Vents \2\.. 8.8
Pneumatic Pumps \3\............................ 13.3
------------------------------------------------------------------------
Population Emission Factors--Major Equipment, Gas Service
------------------------------------------------------------------------
Wellhead....................................... 0.59
Separator...................................... 0.84
Meters/Piping.................................. 2.8
Compressor..................................... 10
Acid Gas Removal Unit.......................... 2.4
Dehydrator..................................... 3.1
Heater Treater................................. 0.12
Storage Vessel................................. 0.85
------------------------------------------------------------------------
Population Emission Factors--Major Equipment, Crude Service
------------------------------------------------------------------------
Wellhead....................................... 0.14
Separator...................................... 0.43
Meters/Piping.................................. 2.5
Compressor..................................... 10
Acid Gas Removal Unit.......................... 2.4
Dehydrator..................................... 3.1
Heater Treater................................. 0.35
Storage Vessel................................. 0.56
------------------------------------------------------------------------
Population Emission Factors--Gathering Pipelines by Material Type \4\
------------------------------------------------------------------------
Protected Steel................................ 0.91
Unprotected Steel.............................. 8.0
Plastic/Composite.............................. 0.27
Cast Iron...................................... 8.2
------------------------------------------------------------------------
\1\ For multi-phase flow that includes gas, use the gas service emission
factors.
\2\ Emission factor is in units of ``scf/hour/device.''
\3\ Emission factor is in units of ``scf/hour/pump.''
\4\ Emission factors are in units of ``scf/hour/mile of pipeline.''
Table W-1B to Subpart W of Part 98--Default Average Component Counts
for Major Onshore Natural Gas Production Equipment and Onshore
Petroleum and Natural Gas Gathering and Boosting Equipment for
Reporting Year 2022 and Prior Reporting Years
0
62. Revise the table heading for table W-1B to subpart W of part 98 to
read as set forth above.
Table W-1C to Subpart W of Part 98--Default Average Component Counts
for Major Crude Oil Production Equipment for Reporting Year 2022 and
Prior Reporting Years
0
63. Revise the table heading for table W-1C to subpart W of part 98 to
read as set forth above.
Table W-1D to Subpart W of Part 98--Designation of Eastern and Western
U.S. for Reporting Year 2022 and Prior Reporting Years
0
64. Revise the table heading for table W-1D to subpart W of part 98 to
read as set forth above.
0
65. Revise table W-1E to subpart W of part 98 to read as follows:
[[Page 37101]]
Table W-1E to Subpart W of Part 98--Default Whole Gas Leaker Emission Factors for Onshore Petroleum and Natural
Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting
----------------------------------------------------------------------------------------------------------------
Emission factor (scf/hour/component)
--------------------------------------------------------
If you survey If you survey If you survey
Equipment components using method 21 using method 21 using any of the
as specified in as specified in methods in Sec.
Sec. Sec. 98.234(a)(1),
98.234(a)(2)(i) 98.234(a)(2)(ii) (3), or (5)
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--All Components, Gas Service \1\
----------------------------------------------------------------------------------------------------------------
Valve.................................................. 4.9 3.5 16
Flange................................................. 4.1 2.2 11
Connector (other)...................................... 1.3 0.8 7.9
Open-Ended Line \2\.................................... 2.8 1.9 10
Pressure Relief Valve.................................. 4.5 2.8 13
Pump Seal.............................................. 3.7 1.4 23
Other \3\.............................................. 4.5 2.8 15
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--All Components, Oil Service
----------------------------------------------------------------------------------------------------------------
Valve.................................................. 3.2 2.2 9.2
Flange................................................. 2.7 1.4 11
Connector (other)...................................... 1.0 0.6 9.1
Open-Ended Line........................................ 1.6 1.1 6.6
Pump \4\............................................... 3.7 2.6 15
Other \3\.............................................. 3.1 2.0 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
66. Remove table W-2 to subpart W of part 98 and add table W-2A and
table W-2B to subpart W of part 98 in numerical order to read as
follows:
Table W-2A to Subpart W of Part 98--Default Total Hydrocarbon Leaker Emission Factors for Onshore Natural Gas
Processing
----------------------------------------------------------------------------------------------------------------
Emission factor (scf/hour/component)
--------------------------------------------------------
If you survey If you survey If you survey
Onshore natural gas processing plants using method 21 using method 21 using any of the
as specified in as specified in methods in Sec.
Sec. Sec. 98.234(a)(1),
98.234(a)(2)(i) 98.234(a)(2)(ii) (3), or (5)
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--Compressor Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\.............................................. 14.84 9.51 61
Connector.............................................. 5.59 3.58 23
Open-Ended Line........................................ 17.27 11.07 71
Pressure Relief Valve.................................. 39.66 25.42 163
Meter.................................................. 19.33 12.39 79
Other \2\.............................................. 4.1 2.63 17
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--Non-Compressor Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\.............................................. 6.42 4.12 26
Connector.............................................. 5.71 3.66 23
Open-Ended Line........................................ 11.27 7.22 46
Pressure Relief Valve.................................. 2.01 1.29 8.2
Meter.................................................. 2.93 1.88 12
Other \2\.............................................. 4.1 2.63 17
----------------------------------------------------------------------------------------------------------------
\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.
[[Page 37102]]
Table W-2B to Subpart W of Part 98--Default Whole Gas Population
Emission Factors for Onshore Natural Gas Processing
------------------------------------------------------------------------
Emission factor
Population emission factors--gas service onshore (scf whole gas/
natural gas processing hour/device)
------------------------------------------------------------------------
Continuous Low Bleed Pneumatic Device Vents.......... 6.8
Continuous High Bleed Pneumatic Device Vents......... 32.4
Intermittent Bleed Pneumatic Device Vents............ 2.3
------------------------------------------------------------------------
0
67. Revise table W-3A to subpart W of part 98 to read as follows:
Table W-3A to Subpart W of Part 98--Default Total Hydrocarbon Leaker Emission Factors for Onshore Natural Gas
Transmission Compression
----------------------------------------------------------------------------------------------------------------
Emission factor (scf/hour/component)
--------------------------------------------------------
If you survey If you survey If you survey
Onshore natural gas transmission compression using method 21 using method 21 using any of the
as specified in as specified in methods in Sec.
Sec. Sec. 98.234(a)(1),
98.234(a)(2)(i) 98.234(a)(2)(ii) (3), or (5)
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--Compressor Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\.............................................. 14.84 9.51 61
Connector.............................................. 5.59 3.58 23
Open-Ended Line........................................ 17.27 11.07 71
Pressure Relief Valve.................................. 39.66 25.42 163
Meter or Instrument.................................... 19.33 12.39 79
Other \2\.............................................. 4.1 2.63 17
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--Non-Compressor Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\.............................................. 6.42 4.12 26
Connector.............................................. 5.71 3.66 23
Open-Ended Line........................................ 11.27 7.22 46
Pressure Relief Valve.................................. 2.01 1.29 8.2
Meter or Instrument.................................... 2.93 1.88 12
Other \2\.............................................. 4.1 2.63 17
----------------------------------------------------------------------------------------------------------------
\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).
0
68. Revise the table heading and table W-3B to subpart W of part 98 to
read as follows:
Table W-3B to Subpart W of Part 98--Default Whole Gas Population
Emission Factors for Onshore Natural Gas Transmission Compression
------------------------------------------------------------------------
Emission factor
Population emission factors--gas service onshore (scf whole gas/
natural gas transmission compression hour/device)
------------------------------------------------------------------------
Continuous Low Bleed Pneumatic Device Vents.......... 6.8
Continuous High Bleed Pneumatic Device Vents......... 32.4
Intermittent Bleed Pneumatic Device Vents............ 2.3
------------------------------------------------------------------------
0
69. Revise table W-4A to subpart W of part 98 to read as follows:
[[Page 37103]]
Table W-4A to Subpart W of Part 98--Default Total Hydrocarbon Leaker Emission Factors for Underground Natural
Gas Storage
----------------------------------------------------------------------------------------------------------------
Emission factor (scf/hour/component)
--------------------------------------------------------
If you survey If you survey If you survey
Underground natural gas storage using method 21 using method 21 using any of the
as specified in as specified in methods in Sec.
Sec. Sec. 98.234(a)(1),
98.234(a)(2)(i) 98.234(a)(2)(ii) (3), or (5)
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--Storage Station, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\.............................................. 14.84 9.51 61
Connector (other)...................................... 5.59 3.58 23
Open-Ended Line........................................ 17.27 11.07 71
Pressure Relief Valve.................................. 39.66 25.42 163
Meter and Instrument................................... 19.33 12.39 79
Other \2\.............................................. 4.1 2.63 17
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--Storage Wellheads, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\.............................................. 4.5 3.2 18
Connector (other than flanges)......................... 1.2 0.7 4.9
Flange................................................. 3.8 2.0 16
Open-Ended Line........................................ 2.5 1.7 10
Pressure Relief Valve.................................. 4.1 2.5 17
Other \2\.............................................. 4.1 2.5 17
----------------------------------------------------------------------------------------------------------------
\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(f)(6) and (8).
0
70. Revise the table heading and table W-4B to subpart W of part 98 to
read as follows:
Table W-4B to Subpart W of Part 98--Default Population Emission Factors
for Underground Natural Gas Storage
------------------------------------------------------------------------
Emission factor (scf/
Underground natural gas storage hour/component)
------------------------------------------------------------------------
Total Hydrocarbon Population Emission Factors--Storage Wellheads, Gas
Service
------------------------------------------------------------------------
Connector...................................... 0.01
Valve.......................................... 0.1
Pressure Relief Valve.......................... 0.17
Open-Ended Line................................ 0.03
------------------------------------------------------------------------
Whole Gas Population Emission Factors--Other Components, Gas Service
------------------------------------------------------------------------
Continuous Low Bleed Pneumatic Device Vents \1\ 6.8
Continuous High Bleed Pneumatic Device Vents 32.4
\1\...........................................
Intermittent Bleed Pneumatic Device Vents \1\.. 2.3
------------------------------------------------------------------------
\1\ Emission Factor is in units of ``scf whole gas/hour/device.''
0
71. Revise table W-5A to subpart W of part 98 to read as follows:
[[Page 37104]]
Table W-5A to Subpart W of Part 98--Default Methane Leaker Emission Factors for Liquefied Natural Gas (LNG)
Storage
----------------------------------------------------------------------------------------------------------------
Emission factor (scf/hour/component)
--------------------------------------------------------
If you survey If you survey If you survey
LNG storage using method 21 using method 21 using any of the
as specified in as specified in methods in Sec.
Sec. Sec. 98.234(a)(1),
98.234(a)(2)(i) 98.234(a)(2)(ii) (3), or (5)
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--LNG Storage Components, LNG Service
----------------------------------------------------------------------------------------------------------------
Valve.................................................. 1.19 0.23 4.9
Pump Seal.............................................. 4.00 0.73 16
Connector.............................................. 0.34 0.11 1.4
Other \1\.............................................. 1.77 0.99 7.3
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--LNG Storage Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \2\.............................................. 14.84 9.51 61
Connector.............................................. 5.59 3.58 23
Open-Ended Line........................................ 17.27 11.07 71
Pressure Relief Valve.................................. 39.66 25.42 163
Meter and Instrument................................... 19.33 12.39 79
Other \3\.............................................. 4.1 2.63 17
----------------------------------------------------------------------------------------------------------------
\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).
0
72. Revise table W-6A to subpart W of part 98 to read as follows:
Table W-6A to Subpart W of Part 98--Default Methane Leaker Emission Factors for LNG Import and Export Equipment
----------------------------------------------------------------------------------------------------------------
Emission factor (scf/hour/component)
--------------------------------------------------------
If you survey If you survey If you survey
LNG import and export equipment using method 21 using method 21 using any of the
as specified in as specified in methods in Sec.
Sec. Sec. 98.234(a)(1),
98.234(a)(2)(i) 98.234(a)(2)(ii) (3), or (5)
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--LNG Terminals Components, LNG Service
----------------------------------------------------------------------------------------------------------------
Valve.................................................. 1.19 0.23 4.9
Pump Seal.............................................. 4.00 0.73 16.
Connector.............................................. 0.34 0.11 1.4
Other \1\.............................................. 1.77 0.99 7.3
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--LNG Terminals Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \2\.............................................. 14.84 9.51 61
Connector.............................................. 5.59 3.58 23
Open-Ended Line........................................ 17.27 11.07 71
Pressure Relief Valve.................................. 39.66 25.42 163
Meter and Instrument................................... 19.33 12.39 79
Other \3\.............................................. 4.1 2.63 17
----------------------------------------------------------------------------------------------------------------
\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(h)(7) and (8).
0
73. Revise table W-7 to subpart W of part 98 to read as follows:
[[Page 37105]]
Table W-7 to Subpart W of Part 98--Default Total Hydrocarbon Leaker
Emission Factors for Onshore Natural Gas Processing
------------------------------------------------------------------------
Emission factor (scf/hour/component)
-------------------------------------
If you survey If you survey
Natural gas distribution using method 21 using any of the
as specified in methods in Sec.
Sec. 98.234(a)(1),
98.234(a)(2)(i) (3), or (5)
------------------------------------------------------------------------
Leaker Emission Factors--Transmission-Distribution Transfer Station1
Components, Gas Service
------------------------------------------------------------------------
Connector......................... 1.69 6.7
Block Valve....................... 0.557 2.3
Control Valve..................... 9.34 38
Pressure Relief Valve............. 0.27 1.1
Orifice Meter..................... 0.212 0.87
Regulator......................... 0.772 3.2
Open-ended Line................... 26.131 107
------------------------------------------------------------------------
\1\ Excluding customer meters.
0
74. Add table W-8 to subpart W of part 98 to read as follows:
Table W-8 to Subpart W of Part 98--Default Methane Population Emission
Factors for Natural Gas Distribution
------------------------------------------------------------------------
Emission factor (scf/
Natural gas distribution hour/component)
------------------------------------------------------------------------
Population Emission Factors--Below Grade Transmission-Distribution
Transfer Station Components and Below Grade Metering-Regulating
Station1 Components, Gas Service \2\
------------------------------------------------------------------------
Below Grade T-D Transfer Station............... 0.30
Below Grade M&R Station........................ 0.30
------------------------------------------------------------------------
Population Emission Factors--Distribution Mains, Gas Service \3\
------------------------------------------------------------------------
Unprotected Steel.............................. 1.2
Protected Steel................................ 2.3
Plastic........................................ 0.45
Cast Iron...................................... 2.8
------------------------------------------------------------------------
Population Emission Factors--Distribution Services, Gas Service \4\
------------------------------------------------------------------------
Unprotected Steel.............................. 0.086
Protected Steel................................ 0.0077
Plastic........................................ 0.0016
Copper......................................... 0.03
------------------------------------------------------------------------
\1\ Excluding customer meters.
\2\ Emission Factor is in units of ``scf/hour/station.''
\3\ Emission Factor is in units of ``scf/hour/mile.''
\4\ Emission Factor is in units of ``scf/hour/number of services.''
0
75. Add table W-9 to subpart W of part 98 in numerical order to read as
follows:
Table W-9 to Subpart W of Part 98--Default Methane Emission Factors for
Natural Gas-Fired Compressor-Drivers
------------------------------------------------------------------------
Emission factor (kg CH4/
Compressor-driver engine design class mmBtu)
------------------------------------------------------------------------
2-stroke lean-burn........................ 0.658
4-stroke lean-burn........................ 0.522
4-stroke rich-burn........................ 0.045
------------------------------------------------------------------------
Subpart X--Petrochemical Production
0
76. Amend Sec. 98.243 by revising paragraphs (b)(3) and (d)(5) to read
as follows:
Sec. 98.243 Calculating GHG emissions.
* * * * *
(b) * * *
(3) For each flare, calculate CO2, CH4, and
N2O emissions using the methodology specified in Sec.
98.253(b).
* * * * *
(d) * * *
(5) For each flare, calculate CO2, CH4, and
N2O emissions using the methodology specified in Sec.
98.253(b).
0
77. Amend Sec. 98.244 by revising paragraph (b)(4)(iii) to read as
follows:
Sec. 98.244 vMonitoring and QA/QC requirements.
* * * * *
(b) * * *
(4) * * *
(iii) ASTM D2505-88 (Reapproved 2004)e1 Standard Test Method for
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity
Ethylene
[[Page 37106]]
by Gas Chromatography (incorporated by reference, see Sec. 98.7).
* * * * *
0
78. Amend Sec. 98.246 by revising paragraphs (a) introductory text,
(a)(2) and (5), (a)(13) and (15), (b)(7) and (8), (c) introductory
text, and (c)(3) and (4) and adding paragraph (c)(6) to read as
follows:
Sec. 98.246 Data reporting requirements.
* * * * *
(a) If you use the mass balance methodology in Sec. 98.243(c), you
must report the information specified in paragraphs (a)(1) through (15)
of this section for each type of petrochemical produced, reported by
process unit.
* * * * *
(2) The type of petrochemical produced.
* * * * *
(5) Annual quantity of each type of petrochemical produced from
each process unit (metric tons). If you are electing to consider the
petrochemical process unit to be the entire integrated ethylene
dichloride/vinyl chloride monomer process, the portion of the total
amount of EDC produced that is used in VCM production may be a measured
quantity or an estimate that is based on process knowledge and best
available data. The portion of the total amount of EDC produced that is
not utilized in VCM production must be measured in accordance with
Sec. 98.244(b)(2) or (3). Sum the amount of EDC used in the production
of VCM plus the amount of separate EDC product to report as the total
quantity of EDC petrochemical from an integrated EDC/VCM petrochemical
process unit.
* * * * *
(13) Name and annual quantity (in metric tons) of each product
included in Equations X-1, X-2, and X-3 of Sec. 98.243. If you are
electing to consider the petrochemical process unit to be the entire
integrated ethylene dichloride/vinyl chloride monomer process, the
reported quantity of EDC product should include only that which was not
used in the VCM process.
* * * * *
(15) For each gaseous feedstock or product for which the volume was
used in Equation X-1, report the annual average molecular weight of the
measurements or determinations, conducted according to Sec.
98.243(c)(3) or (4). Report the annual average molecular weight in
units of kg per kg mole.
(b) * * *
(7) Information listed in Sec. 98.256(e) of subpart Y of this part
for each flare that burns process off-gas. Additionally, provide
estimates based on engineering judgment of the fractions of the total
CO2, CH4 and N2O emissions that are
attributable to combustion of off-gas from the petrochemical process
unit(s) served by the flare.
(8) Annual quantity of each type of petrochemical produced from
each process unit (metric tons).
* * * * *
(c) If you comply with the combustion methodology specified in
Sec. 98.243(d), you must report under this subpart the information
listed in paragraphs (c)(1) through (c)(6) of this section.
* * * * *
(3) Information listed in Sec. 98.256(e) of subpart Y of this part
for each flare that burns ethylene process off-gas. Additionally,
provide estimates based on engineering judgment of the fractions of the
total CO2, CH4 and N2O emissions that
are attributable to combustion of off-gas from the ethylene process
unit(s) served by the flare.
(4) Name and annual quantity of each carbon-containing feedstock
(metric tons).
* * * * *
(6) Name and annual quantity (in metric tons) of each product
produced in each process unit.
Subpart Y--Petroleum Refineries
0
79. Amend Sec. 98.253 by:
0
a. Revising paragraph (b) introductory text, paragraph (c) introductory
text, and paragraph (e) introductory text;
0
b. Revising Equation Y-18b in paragraph (i)(2);
0
c. Revising parameters ``Mwater'' and ``Hwater'' of Equation Y-18b in
paragraph (i)(2);
0
d. Adding parameter ``fcoke'' to Equation Y-18b in paragraph (i)(2);
and
0
e. Revising parameter ``Msteam'' of Equation Y-18f in paragraph (i)(5).
The revisions and addition read as follows:
Sec. 98.253 Calculating GHG emissions.
* * * * *
(b) For flares, calculate GHG emissions according to the
requirements in paragraphs (b)(1) through (3) of this section. All gas
discharged through the flare stack must be included in the flare GHG
emissions calculations with the exception of the following, which may
be excluded as applicable: (1) gas used for the flare pilots, and (2)
if using the calculation method in paragraph (b)(1)(iii) of this
section, the gas released during start-up, shutdown, or malfunction
events of 500,000 scf/day or less.
* * * * *
(c) For catalytic cracking units and traditional fluid coking
units, calculate the GHG emissions from coke burn-off using the
applicable methods described in paragraphs (c)(1) through (c)(5) of
this section.
* * * * *
(e) For catalytic reforming units, calculate the CO2
emissions from coke burn-off using the applicable methods described in
paragraphs (e)(1) through (e)(3) of this section and calculate the
CH4 and N2O emissions using the methods described
in paragraphs (c)(4) and (c)(5) of this section, respectively.
* * * * *
(i) * * *
(2) * * *
[GRAPHIC] [TIFF OMITTED] TP21JN22.051
* * * * *
Mwater = Mass of water in the delayed coking unit vessel
at the end of the cooling cycle just prior to atmospheric venting or
draining (metric tons/cycle).
* * * * *
Hwater = Typical distance from the bottom of the coking
unit vessel to the top of the water level at the end of the cooling
cycle just prior to atmospheric venting or draining (feet) from
company records or engineering estimates.
fcoke = Fraction of the coke-filled bed that is covered
by water at the end of the cooling cycle just prior to atmospheric
venting or draining. Use 1 if the water fully covers coke-filled
portion of the coke drum.
* * * * *
(5) * * *
* * * * *
Msteam = Mass of steam generated and released per
decoking cycle (metric tons/cycle) as determined in paragraph (i)(4)
of this section.
* * * * *
0
80. Amend Sec. 98.254 by revising paragraph (d) introductory text and
[[Page 37107]]
paragraph (e) introductory text to read as follows:
Sec. 98.254 Monitoring and QA/QC requirements.
* * * * *
(d) Except as provided in paragraph (g) of this section, determine
gas composition and, if required, average molecular weight of the gas
using any of the following methods. Alternatively, the results of
chromatographic or direct mass spectrometer analysis of the gas may be
used, provided that the gas chromatograph or mass spectrometer is
operated, maintained, and calibrated according to the manufacturer's
instructions; and the methods used for operation, maintenance, and
calibration of the gas chromatograph or mass spectrometer are
documented in the written Monitoring Plan for the unit under Sec.
98.3(g)(5).
* * * * *
(e) Determine flare gas higher heating value using any of the
following methods. Alternatively, the results of chromatographic
analysis of the gas may be used, provided that the gas chromatograph is
operated, maintained, and calibrated according to the manufacturer's
instructions; and the methods used for operation, maintenance, and
calibration of the gas chromatograph are documented in the written
Monitoring Plan for the unit under Sec. 98.3(g)(5).
* * * * *
0
81. Amend Sec. 98.256 by revising paragraph (k)(6) to read as follows:
Sec. 98.256 Data reporting requirements.
* * * * *
(k) * * *
(6) The basis for the typical dry mass of coke in the delayed
coking unit vessel at the end of the coking cycle (mass measurements
from company records or calculated using Equation Y-18a of this
subpart). If you use mass measurements from company records to
determine the typical dry mass of coke in the delayed coking unit
vessel at the end of the coking cycle, you must also report:
(i) Internal height of delayed coking unit vessel (feet) for each
delayed coking unit.
(ii) Typical distance from the top of the delayed coking unit
vessel to the top of the coke bed (i.e., coke drum outage) at the end
of the coking cycle (feet) from company records or engineering
estimates for each delayed coking unit.
* * * * *
0
82. Amend Sec. 98.257 by:
0
a. Revising paragraphs (b)(45), (46), and (53); and
0
b. Removing and reserving paragraphs (b)(54), (55), and (56).
The revisions read as follows:
Sec. 98.257 Records that must be retained.
* * * * *
(b) * * *
(45) Mass of water in the delayed coking unit vessel at the end of
the cooling cycle prior to atmospheric venting or draining (metric ton/
cycle) (Equations Y-18b and Y-18e in Sec. 98.253) for each delayed
coking unit.
(46) Typical distance from the bottom of the coking unit vessel to
the top of the water level at the end of the cooling cycle just prior
to atmospheric venting or draining (feet) from company records or
engineering estimates (Equation Y-18b in Sec. 98.253) for each delayed
coking unit.
* * * * *
(53) Fraction of the coke-filled bed that is covered by water at
the end of the cooling cycle just prior to atmospheric venting or
draining (Equation Y-18b in Sec. 98.253) for each delayed coking unit.
* * * * *
Subpart BB--Silicon Carbide Production
0
83. Amend Sec. 98.286 by revising the introductory text and adding
paragraph (c) to read as follows:
Sec. 98.286 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraph (a)
or (b) of this section, and paragraph (c) of this section, as
applicable for each silicon carbide production facility.
* * * * *
(c) If methane abatement technology is used at the silicon carbide
production facility, you must report the information in paragraphs
(c)(1) through (3) of this section. Upon reporting this information
once in an annual report, you are not required to report this
information again unless the information changes during a reporting
year, in which case, the reporter must include any updates in the
annual report for the reporting year in which the change occurred.
(1) Type of methane abatement technology used on each silicon
carbide process unit or production furnace, and date of installation
for each.
(2) Methane destruction efficiency for each methane abatement
technology (percent destruction). You must either use the
manufacturer's specified destruction efficiency or the destruction
efficiency determined via a performance test. If you report the
destruction efficiency determined via a performance test, you must also
report the test method that was used during the performance test.
(3) Percentage of annual operating hours that methane abatement
technology was in use for all silicon carbide process units or
production furnaces combined.
0
84. Amend Sec. 98.287 by revising the introductory text and adding
paragraph (d) to read as follows:
Sec. 98.287 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (d) of this
section for each silicon carbide production facility.
* * * * *
(d) Records of all information reported as required under Sec.
98.286(c).
Subpart DD--Electrical Transmission and Distribution Equipment Use
0
85. Amend Sec. 98.300 by revising paragraphs (a) introductory text and
(a)(3) and (7) to read as follows:
Sec. 98.300 Definition of the source category.
(a) The electrical transmission and distribution equipment use
source category consists of all electric transmission and distribution
equipment and servicing inventory insulated with or containing
fluorinated GHGs, including but not limited to sulfur hexafluoride
(SF6) and perfluorocarbons (PFCs), used within an electric
power system. Electric transmission and distribution equipment and
servicing inventory includes, but is not limited to:
* * * * *
(3) Switchgear, including closed-pressure and hermetically sealed-
pressure switchgear and gas-insulated lines containing fluorinated
GHGs, including but not limited to SF6 and PFCs.
* * * * *
(7) Other containers of fluorinated GHG, including but not limited
to SF6 and PFCs.
* * * * *
0
86. Revise Sec. 98.301 to read as follows:
Sec. 98.301 Reporting threshold.
(a) You must report GHG emissions under this subpart if you are an
electric power system as defined in Sec. 98.308 and your facility
meets the requirements of Sec. 98.2(a)(1). To calculate total annual
GHG emissions for comparison to the 25,000 metric ton CO2e per year
emission threshold in Table A-3, you must calculate emissions of each
fluorinated GHG, including but not limited to SF6 and PFCs,
and then sum the emissions of each fluorinated GHG
[[Page 37108]]
resulting from the use of electrical transmission and distribution
equipment for threshold applicability purposes using Equation DD-1 of
this subpart.
[GRAPHIC] [TIFF OMITTED] TP21JN22.052
Where:
E = Annual emissions for threshold applicability purposes (metric
tons CO2e).
NCEPS,j = the total nameplate capacity of insulating gas j-
containing equipment (excluding hermetically sealed-pressure
equipment) located within the facility plus the total nameplate
capacity of insulting gas j-containing equipment (excluding
hermetically sealed-pressure equipment) that is not located within
the facility but is under common ownership or control
GHGi,w = The weight fraction of fluorinated GHG i in insulating gas
j in the gas insulated equipment included in the total nameplate
capacity NCEPS,j, expressed as a decimal fraction. If
fluorinated GHG i is not part of a gas mixture, use a value of 1.0.
GWPi = Gas-appropriate GWP as provided in Table A-1 to subpart A of
this part.
EF = Emission factor for electrical transmission and distribution
equipment (lbs emitted/lbs nameplate capacity). For all gases, use
an emission factor or 0.1.
i = Fluorinated GHG contained in the electrical transmission and
distribution equipment.
0.000453592 = Conversion factor from lbs to metric tons.
(b) A facility other than an electric power system that is subject
to this part because of emissions from any other source category listed
in Table A-3 or A-4 in subpart A of this part is not required to report
emissions under subpart DD of this part unless the total estimated
emissions from fluorinated gas, including but not limited to SF6 and
PFCs, containing equipment located at the facility, as calculated in
Equation DD-2 for comparison to the 25,000 metric ton CO2e per year
emission threshold in Table A-3 meets or exceeds 25,000 tons CO2e.
[GRAPHIC] [TIFF OMITTED] TP21JN22.053
Where:
E = Annual emissions for threshold applicability purposes (metric
tons CO2e).
NCother,j = For a facility other than an electric power system, the
total nameplate capacity of insulating gas j containing equipment
(excluding hermetically sealed-pressure equipment) located within
the facility
GHGi,w = The weight fraction of fluorinated GHG i in insulating gas
j in the gas insulated equipment included in the total nameplate
capacity NCother,j, expressed as a decimal fraction. If fluorinated
GHG i is not part of a gas mixture, use a value of 1.0.
GWPi = Gas-appropriate GWP as provided in Table A-1 to subpart A of
this part.
EF = Emission factor for electrical transmission and distribution
equipment (lbs emitted/lbs nameplate capacity). For all gases, use
an emission factor or 0.1.
i = Fluorinated GHG contained in the electrical transmission and
distribution equipment.
0.000453592 = Conversion factor from lbs to metric tons.
0
87. Revise Sec. 98.302 to read as follows:
Sec. 98.302 GHGs to report.
You must report emissions of each fluorinated GHG, including but
not limited to SF6 and PFC, from your facility (including
emissions from fugitive equipment leaks, installation, servicing,
equipment decommissioning and disposal, and from storage cylinders)
resulting from the transmission and distribution servicing inventory
and equipment listed in Sec. 98.300(a). For acquisitions of equipment
containing or insulated with fluorinated GHG, you must report emissions
from the equipment after the title to the equipment is transferred to
the electric power transmission or distribution entity.
0
88. Revise Sec. 98.303 to read as follows:
Sec. 98.303 Calculating GHG emissions.
(a) Mass-balance approach. Calculate the annual emissions of each
fluorinated GHG (including but not limited to SF6 and PFC)
using the mass-balance approach in Equation DD-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.054
Where:
User Emissionsi = Emissions of fluorinated GHG i from the
facility (pounds).
GHGi,w = The weight fraction of fluorinated GHG i in
insulating gas j if insulating gas j is a gas mixture, expressed as
a decimal fraction. If fluorinated GHG i is not part of a gas
mixture, use a value of 1.0.
Decrease in Insulating gas j Inventory = (pounds of insulating gas j
stored in containers, but not in energized equipment, at the
beginning of the year) - (pounds of insulating gas j stored in
containers, but not in energized equipment, at the end of the year).
Acquisitions of Insulating gas j = (pounds of each insulating gas j
purchased from chemical producers or distributors in bulk) + (pounds
of each insulating gas j purchased from equipment manufacturers or
distributors with or inside equipment, including hermetically
sealed-pressure switchgear) + (pounds of each insulating gas j
returned to facility after off-site recycling).
Disbursements of Insulating gas j = (pounds of each insulating gas j
in bulk and contained in equipment that is sold to other entities) +
(pounds of each insulating gas j returned to suppliers) + (pounds of
each insulating gas j sent off site for recycling) + (pounds of each
insulating gas j sent off-site for destruction).
Net Increase in Total Nameplate Capacity of Equipment Operated
containing insulating gas j = (The Nameplate Capacity of new
equipment containing insulating gas j in pounds, including
hermetically sealed-pressure switchgear) - (Nameplate Capacity of
retiring equipment containing insulating gas j in pounds, including
hermetically sealed-pressure switchgear). (Note that
[[Page 37109]]
Nameplate Capacity refers to the full and proper charge of equipment
rather than to the actual charge, which may reflect leakage).
(b) Nameplate Capacity Adjustments. Users of closed-pressure
electrical equipment with a voltage capacity greater than 38 kV may
measure and adjust the nameplate capacity value specified by the
equipment manufacturer on the nameplate attached to that equipment, or
within the equipment manufacturer's official product specifications, by
following the requirements in paragraphs (b)(1) through (b)(10) of this
section. Users of other electrical equipment are not permitted to
adjust the nameplate capacity value of the other equipment.
(1) If you elect to measure the nameplate capacity value(s) of one
or more pieces of electrical equipment with a voltage capacity greater
than 38 kV, you must measure the nameplate capacity values of all the
electrical equipment in your facility that has a voltage capacity
greater than 38 kV and that is installed or retired in that reporting
year and in subsequent reporting years.
(2) You must adopt the measured nameplate capacity value for any
piece of equipment for which the absolute value of the difference
between the measured nameplate capacity value and the nameplate
capacity value most recently specified by the manufacturer equals or
exceeds two percent of the nameplate capacity value most recently
specified by the manufacturer.
(3) You may adopt the measured nameplate capacity value for
equipment for which the absolute value of the difference between the
measured nameplate capacity value and the nameplate capacity value most
recently specified by the manufacturer is less than two percent of the
nameplate capacity value most recently specified by the manufacturer,
but if you elect to adopt the measured nameplate capacity for that
equipment, then you must adopt the measured nameplate capacity value
for all of the equipment for which the difference between the measured
nameplate capacity value and the nameplate capacity value most recently
specified by the manufacturer is less than two percent of the nameplate
capacity value most recently specified by the manufacturer. This
applies in the reporting year in which you first adopt the measured
nameplate capacity for the equipment and in subsequent reporting years.
(4) Users of electrical equipment measuring the nameplate capacity
of any new electrical equipment must:
(i) Record the amount of insulating gas in the equipment at the
time the equipment was acquired (pounds), either per information
provided by the manufacturer, or by transferring insulating gas from
the equipment to a gas container and measuring the amount of insulating
gas transferred. The equipment user is responsible for ensuring the gas
is accounted for consistent with the methodologies specified in
paragraphs (b)(4)(ii) through (b)(5) of this section. If no insulating
gas was in the device when it was acquired, record this value as zero.
(ii) If insulating gas is added to the equipment subsequent to the
acquisition of the equipment to energize it the first time, transfer
the insulating gas to the equipment to reach the temperature-
compensated design operating pressure per manufacturer specifications
and measure and calculate the total amount of covered insulating gas
added to the device using one of the methods specified in paragraphs
(b)(4)(ii)(A) and (B) of this section.
(A) To determine the amount of covered insulating gas transferred
to the electrical equipment, weigh the gas container being used to fill
the device prior to, and after, the addition of the covered insulating
gas to the electrical equipment, and subtract the second value (after-
transfer gas container weight) from the first value (prior-to-transfer
gas container weight). Account for any gas contained in hoses before
and after the transfer.
(B) Connect a mass flow meter between the electrical equipment and
a gas cart. Transfer gas to the equipment to reach the temperature-
compensated design operating pressure per manufacturer specifications.
Close the connection to the GIE from the mass flow meter hose and
ensure that the gas trapped in the filling hose returns through the
mass flow meter. Calculate the amount of gas transferred from the mass
reading on the mass flow meter.
(iii) Sum the results of paragraphs (b)(4)(i) and (ii) to obtain
the measured nameplate capacity for the new equipment.
(5) Electrical equipment users measuring the nameplate capacity of
any retiring electrical equipment must:
(i) Record the initial system pressure and vessel temperature prior
to removing any insulating gas.
(ii) Convert the initial system pressure to a temperature-
compensated initial system pressure by using the temperature/pressure
curve for that insulating gas.
(iii) If the temperature-compensated initial system pressure of the
electrical equipment does not match the temperature-compensated design
operating pressure specified by the equipment manufacturer, you may
either:
(A) Add or remove insulating gas to/from the electrical equipment
until the manufacturer-specified value is reached, or
(B) If the temperature-compensated initial system pressure of the
electrical equipment is no less than 90 percent of the temperature-
compensated design operating pressure specified by the manufacturer (in
absolute terms), use Equation DD-4 to calculate the nameplate capacity
based on the mass recorded under paragraph (b)(5)(vi) of this section.
(iv) Follow one of the following processes, depending on the
methodology being used to measure the amount of gas recovered:
(A) Connect a mass flow meter between the electrical equipment and
a gas cart; or
(B) Weigh the gas container being used to receive the gas and
record this value.
(v) Recover insulating gas from the electrical equipment until five
minutes after the pressure in the electrical equipment reaches the
blank-off pressure unless the integrity of the electrical equipment has
been compromised in such a way that air will be drawn into the
electrical equipment and gas cart if the electrical equipment is drawn
into a vacuum. If the integrity of the electrical equipment has been so
compromised, recover the insulating gas until the pressure in the
electrical equipment is no higher than zero pounds per square inch
gauge (0 psig).
(vi) Record the amount of insulating gas recovered (pounds), either
based on the reading from the mass flow meter, or by weighing the gas
container that received the gas and subtracting the weight recorded
pursuant to paragraph (b)(5)(iv)(B) of this section from this value.
Account for any gas contained in hoses before and after the transfer.
The amount of gas recovered shall be the measured nameplate capacity
for the electrical equipment unless the final temperature-compensated
pressure of the electrical equipment exceeds 0.068 psia (3.5 Torr) or
the electrical equipment user is calculating the nameplate capacity
pursuant to paragraph (b)(5)(iii)(B) of this section, in which cases
the measured nameplate capacity shall be the result of Equation DD-4.
(vii) If you are calculating the nameplate capacity pursuant to
paragraph (b)(5)(iii)(B), use Equation DD-4 to do so.
[[Page 37110]]
[GRAPHIC] [TIFF OMITTED] TP21JN22.055
Where:
NCC = Nameplate capacity of the equipment measured and calculated by
the equipment user (pounds).
Pi = Initial temperature-compensated pressure of the equipment,
based on the temperature-pressure curve for the insulating gas
(psia).
Pf = Final temperature-compensated pressure of the equipment, based
on the temperature-pressure curve for the insulating gas (psia).
This may be equated to zero if the final temperature-compensated
pressure of the equipment is equal to or lower than 0.068 psia (3.5
Torr).
PNC = Temperature-compensated pressure of the equipment at the
manufacturer-specified filling density of the equipment (i.e., at
the full and proper charge, psia).
MR = Mass of insulating gas recovered from the equipment, measured
in paragraph (b)(5)(vi) of this section (pounds).
(viii) Record the final system pressure and vessel temperature.
(6) Instead of measuring the nameplate capacity of electrical
equipment when it is retired, users may measure the nameplate capacity
of electrical equipment during maintenance activities that require
opening the gas compartment, but they must follow the procedures set
forth in paragraph (b)(5) of this section.
(7) If the electrical equipment will remain energized, and the
electrical equipment user is adopting the user-measured nameplate
capacity, the electrical equipment user must affix a revised nameplate
capacity label, showing the revised nameplate value and the year the
nameplate capacity adjustment process was performed, to the device by
the end of the calendar year in which the process was completed. The
manufacturer's previous nameplate capacity label must remain visible
after the revised nameplate capacity label is affixed to the device.
(8) For each piece of electrical equipment whose nameplate capacity
was adjusted during the reporting year, the revised nameplate capacity
value must be used in all provisions wherein the nameplate capacity is
required to be recorded, reported, or used in a calculation in this
subpart unless otherwise specified herein.
(9) The nameplate capacity of a piece of electrical equipment may
only be adjusted more than once if the physical capacity of the device
has changed (e.g., replacement of bushings) after the initial
adjustment was performed, in which case the equipment user must adjust
the nameplate capacity pursuant to the provisions of this paragraph
(b).
(10) Measuring devices used to measure the nameplate capacity of
electrical equipment under this paragraph (b) must meet the following
accuracy and precision requirements:
(i) Flow meters must be certified by the manufacturer to be
accurate and precise to within one percent of the largest value that
the flow meter can, according to the manufacturer's specifications,
accurately record.
(ii) Pressure gauges must be certified by the manufacturer to be
accurate and precise to within 0.5% of the largest value that the gauge
can, according to the manufacturer's specifications, accurately record.
(iii) Temperature gauges must be certified by the manufacturer to
be accurate and precise to within +/-1.0 [deg]F.
(iv) Scales must be certified by the manufacturer to be accurate
and precise to within one percent of the true weight.
0
89. Amend Sec. 98.304 by removing and reserving paragraph (a) and
revising paragraphs (b)(1), (2), and (4).
The revisions read as follows:
Sec. 98.304 Monitoring and QA/QC requirements.
* * * * *
(b) * * *
(1) Review inputs to Equation DD-3 of this section to ensure inputs
and outputs to the company's system are included.
(2) Do not enter negative inputs and confirm that negative
emissions are not calculated. However, the Decrease in fluorinated GHG
Inventory and the Net Increase in Total Nameplate Capacity may be
calculated as negative numbers.
* * * * *
(4) Ensure that in addition to fluorinated GHG purchased from bulk
gas distributors, fluorinated GHG purchased from Original Equipment
Manufacturers (OEM) and fluorinated GHG returned to the facility from
off-site recycling are also accounted for among the total additions.
* * * * *
0
90. Revise Sec. 98.305 to read as follows:
Sec. 98.305 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required. Replace missing data, if needed,
based on data from equipment with a similar nameplate capacity for
fluorinated GHGs, and from similar equipment repair, replacement, and
maintenance operations.
0
91. Amend Sec. 98.306 by revising paragraphs (a) introductory text,
(d) through (l), and (n) introductory text and adding paragraphs (o)
through (r) to read as follows:
Sec. 98.306 Data reporting requirements.
* * * * *
(a) Nameplate capacity of equipment (pounds) containing each
insulating gas:
* * * * *
(d) Pounds of each insulating gas stored in containers, but not in
energized equipment, at the beginning of the year.
(e) Pounds of each insulating gas stored in containers, but not in
energized equipment, at the end of the year.
(f) Pounds of each insulating gas purchased in bulk from chemical
producers or distributors.
(g) Pounds of each insulating gas purchased from equipment
manufacturers or distributors with or inside equipment, including
hermetically sealed-pressure switchgear.
(h) Pounds of each insulating gas returned to facility after off-
site recycling.
(i) Pounds of each insulating gas in bulk and contained in
equipment sold to other entities.
(j) Pounds of each insulating gas returned to suppliers.
(k) Pounds of each insulating gas sent off-site for recycling.
(l) Pounds of each insulating gas sent off-site for destruction.
* * * * *
(n) The number of insulating gas containing pieces of equipment in
each of the following equipment categories:
* * * * *
(o) The total of the nameplate capacity values most recently
assigned by the electrical equipment manufacturer(s) to each of the
following groups of equipment:
(1) All new equipment whose nameplate capacity values were measured
by the user under this subpart and for which the user adopted the user-
measured nameplate capacity value during the year.
(2) All retiring equipment whose nameplate capacity values were
measured by the user under this subpart and for which the user adopted
the user-measured nameplate capacity value during the year.
(p) The total of the nameplate capacity values measured by the
[[Page 37111]]
electrical equipment user for each of the following groups of
equipment:
(1) All new equipment whose nameplate capacity values were measured
by the user under this subpart and for which the user adopted the user-
measured nameplate capacity value during the year.
(2) All retiring equipment whose nameplate capacity values were
measured by the user under this subpart and for which the user adopted
the user-measured nameplate capacity value during the year.
(q) For each unique insulating gas reported in paragraphs (a), (d)
through (l), and (n) of this section, an ID number or other appropriate
descriptor.
(r) For each ID number or descriptor reported in paragraph (q) of
this section for each unique insulating gas, the name (as required in
Sec. 98.3(c)(4)(iii)(G)(1)) and weight percent of each fluorinated gas
in the insulating gas.
0
92. Revise Sec. 98.307 to read as follows:
Sec. 98.307 Records that must be retained.
(a) In addition to the information required by Sec. 98.3(g), you
must retain records of the information reported and listed in Sec.
98.306.
(b) For each piece of electrical equipment whose nameplate capacity
is measured by the equipment user, retain records of the following:
(1) Equipment manufacturer name.
(2) Year equipment was manufactured. If the date year the equipment
was manufactured cannot be determined, report a best estimate of the
year of manufacture and record how the estimated year was determined.
(3) Manufacturer serial number. For any piece of equipment whose
serial number is unknown (e.g., the serial number does not exist or is
not visible), another unique identifier must be recorded as the
manufacturer serial number. The electrical equipment user must retain
documentation that allows for each electrical equipment to be readily
identifiable.
(4) Equipment type (i.e., closed-pressure vs. hermetically sealed-
pressure).
(5) Equipment voltage capacity (in kilovolts).
(6) The name and GWP of each insulating gas used.
(7) Nameplate capacity value (pounds), as specified by the
equipment manufacturer. The value must reflect the latest value
specified by the manufacturer during the reporting year.
(8) Nameplate capacity value (pounds) measured by the equipment
user.
(9) The date the nameplate capacity measurement process was
completed.
(10) The measurements and calculations used to calculate the value
in paragraph (b)(8) of this section.
(11) The temperature-pressure curve and/or other information used
to derive the initial and final temperature-adjusted pressures of the
equipment.
(12) Whether or not the nameplate capacity value in paragraph
(b)(8) of this section has been adopted for the piece of electrical
equipment.
0
93. Amend Sec. 98.308 by revising the definition of ``Facility'' and
adding in alphabetical order definitions for ``Energized'',
``Insulating gas'', ``New equipment'', and ``Retired equipment'' to
read as follows:
Sec. 98.308 Definitions.
* * * * *
Facility, with respect to an electric power system, means the
electric power system as defined in this paragraph. An electric power
system is comprised of all electric transmission and distribution
equipment insulated with or containing fluorinated GHGs that is linked
through electric power transmission or distribution lines and functions
as an integrated unit, that is owned, serviced, or maintained by a
single electric power transmission or distribution entity (or multiple
entities with a common owner), and that is located between {1{time} The
point(s) at which electric energy is obtained from an electricity
generating unit or a different electric power transmission or
distribution entity that does not have a common owner, and {2{time}
the point(s) at which any customer or another electric power
transmission or distribution entity that does not have a common owner
receives the electric energy. The facility also includes servicing
inventory for such equipment that contains fluorinated GHGs.
* * * * *
Energized, for the purposes of this subpart, means connected
through busbars or cables to an electrical power system or fully-
charged, ready for service, and being prepared for connection to the
electrical power system. Energized equipment does not include spare gas
insulated equipment (including hermetically-sealed pressure switchgear)
in storage that has been acquired by the facility, and is intended for
use by the facility, but that is not being used or prepared for
connection to the electrical power system.
Insulating gas, for the purposes of this subpart, means any
fluorinated GHG or fluorinated GHG mixture, including but not limited
to SF6 and PFCs, that is used as an insulating and/or arc-quenching gas
in electrical equipment.
New equipment, for the purposes of this subpart, means any gas
insulated equipment, including hermetically-sealed pressure switchgear,
that is not energized at the beginning of the reporting year, but is
energized at the end of the reporting year. This includes equipment
that has been transferred while in use, meaning it has been added to
the facility's inventory without being taken out of active service
(e.g., when the equipment is sold to or acquired by the facility while
remaining in place and continuing operation).
* * * * *
Retired equipment, for the purposes of this subpart, means any gas
insulated equipment, including hermetically-sealed pressure switchgear,
that is energized at the beginning of the reporting year, but is not
energized at the end of the reporting year. This includes equipment
that has been transferred while in use, meaning it has been removed
from the facility's inventory without being taken out of active service
(e.g., when the equipment is acquired by a new facility while remaining
in place and continuing operation).
Subpart FF--Underground Coal Mines
0
94. Amend Sec. 98.323 by revising parameter ``MCFi'' of Equation FF-3
in paragraph (b) introductory text to read as follows:
Sec. 98.323 Calculating GHG emissions.
* * * * *
(b) * * *
MCFi = Moisture correction factor for the measurement period,
volumetric basis.
= 1 when Vi and Ci are measured on a dry basis or if both are measured
on a wet basis.
= 1-(fH2O)i when Vi is measured on a wet basis and Ci is measured on a
dry basis.
= 1/[1-(fH2O)i] when Vi is measured on a dry basis and Ci is measured
on a wet basis.
* * * * *
0
95. Amend Sec. 98.326 by revising paragraph (t) to read as follows:
Sec. 98.326 Data reporting requirements.
* * * * *
(t) Mine Safety and Health Administration (MSHA) identification
number for this coal mine.
Subpart GG--Zinc Production
0
96. Amend Sec. 98.333 by revising paragraph (b)(1) introductory text
to read as follows:
[[Page 37112]]
Sec. 98.333 Calculating GHG emissions.
* * * * *
(b) * * *
(1) For each Waelz kiln or electrothermic furnace at your facility
used for zinc production, you must determine the mass of carbon in each
carbon-containing material, other than fuel, that is fed, charged, or
otherwise introduced into each Waelz kiln and electrothermic furnace at
your facility for each year and calculate annual CO2 process
emissions from each affected unit at your facility using Equation GG-1
of this section. For electrothermic furnaces, carbon containing input
materials include carbon electrodes and carbonaceous reducing agents.
For Waelz kilns, carbon containing input materials include carbonaceous
reducing agents. If you document that a specific material contributes
less than 1 percent of the total carbon into the process, you do not
have to include the material in your calculation using Equation R-1 of
Sec. 98.183.
* * * * *
0
97. Amend Sec. 98.336 by adding paragraph (a)(6) and revising
paragraph (b)(6) to read as follows:
Sec. 98.336 Data reporting requirements.
* * * * *
(a) * * *
(6) Total amount of electric arc furnace dust annually consumed by
all Waelz kilns at the facility (tons).
(b) * * *
(6) Total amount of electric arc furnace dust annually consumed by
all Waelz kilns at the facility (tons).
* * * * *
Subpart HH--Municipal Solid Waste Landfills
0
98. Amend Sec. 98.343 by revising paragraph (a)(2) to read as follows:
Sec. 98.343 Calculating GHG emissions.
(a) * * *
(2) For years when material-specific waste quantity data are
available, apply Equation HH-1 of this section for each waste quantity
type and sum the CH4 generation rates for all waste types to
calculate the total modeled CH4 generation rate for the
landfill. Use the appropriate parameter values for k, DOC, MCF,
DOCF, and F shown in Table HH-1 of this subpart. The annual
quantity of each type of waste disposed must be calculated as the sum
of the daily quantities of waste (of that type) disposed. You may use
the uncharacterized MSW parameters for a portion of your waste
materials when using the material-specific modeling approach for mixed
waste streams that cannot be designated to a specific material type.
For years when waste composition data are not available, use the bulk
waste parameter values for k and DOC in Table HH-1 to this subpart for
the total quantity of waste disposed in those years.
* * * * *
0
99. Amend Sec. 98.346 by adding paragraphs (i)(6)(i) and (ii) to read
as follows:
Sec. 98.346 Data reporting requirements.
* * * * *
(i) * * *
(6) * * *
(i) The percentage of total recovered CH4 that is sent
to each measurement location (decimal, must total to 1 across all
measurement locations at the facility).
(ii) For each measurement location, the percentage of total
recovered CH4 that is sent to a flare, a landfill gas to
energy project, or an unknown option if gas is sent off-site for
destruction and the type of destruction technology is unknown (decimal,
must total to 1 for each measurement location).
* * * * *
0
100. Revise table HH-1 to subpart HH of part 98 to read as follows:
Table HH-1 to Subpart HH of Part 98--Emissions Factors, Oxidation
Factors and Methods
------------------------------------------------------------------------
Factor Default value Units
------------------------------------------------------------------------
DOC and k values--Bulk waste option
------------------------------------------------------------------------
DOC (bulk waste)................ 0.17.............. Weight fraction,
wet basis.
k (precipitation plus 0.055............. yr-1
recirculated leachate \a\ <20
inches/year).
k (precipitation plus 0.111............. yr-1
recirculated leachate \a\ 20-40
inches/year).
k (precipitation plus 0.142............. yr-1
recirculated leachate \a\ >40
inches/year).
------------------------------------------------------------------------
DOC and k values--Modified bulk MSW option
------------------------------------------------------------------------
DOC (bulk MSW, excluding inerts 0.27.............. Weight fraction,
and C&D waste). wet basis.
DOC (inerts, e.g., glass, 0.00.............. Weight fraction,
plastics, metal, concrete). wet basis.
DOC (C&D waste)................. 0.08.............. Weight fraction,
wet basis.
k (bulk MSW, excluding inerts 0.02 to 0.057 \b\. yr-1
and C&D waste).
k (inerts, e.g., glass, 0.00.............. yr-1
plastics, metal, concrete).
k (C&D waste)................... 0.02 to 0.04 \b\.. yr-1
------------------------------------------------------------------------
DOC and k values--Waste composition option
------------------------------------------------------------------------
DOC (food waste)................ 0.15.............. Weight fraction,
wet basis.
DOC (garden).................... 0.2............... Weight fraction,
wet basis.
DOC (paper)..................... 0.4............... Weight fraction,
wet basis.
DOC (wood and straw)............ 0.43.............. Weight fraction,
wet basis.
DOC (textiles).................. 0.24.............. Weight fraction,
wet basis.
DOC (diapers)................... 0.24.............. Weight fraction,
wet basis.
DOC (sewage sludge)............. 0.05.............. Weight fraction,
wet basis.
DOC (inerts, e.g., glass, 0.00.............. Weight fraction,
plastics, metal, cement). wet basis.
DOC (Uncharacterized MSW)....... 0.32.............. Weight fraction,
wet basis.
k (food waste).................. 0.06 to 0.185 \c\. yr-1
k (garden)...................... 0.05 to 0.10 \c\.. yr-1
k (paper)....................... 0.04 to 0.06 \c\.. yr-1
k (wood and straw).............. 0.02 to 0.03 \c\.. yr-1
[[Page 37113]]
k (textiles).................... 0.04 to 0.06 \c\.. yr-1
k (diapers)..................... 0.05 to 0.10 \c\.. yr-1
k (sewage sludge)............... 0.06 to 0.185 \c\. yr-1
k (inerts, e.g., glass, 0.00.............. yr-1
plastics, metal, concrete).
k (uncharacterized MSW)......... 0.055 to 0.142.... yr-1
------------------------------------------------------------------------
Other parameters--All MSW landfills
------------------------------------------------------------------------
MCF............................. 1.................
DOCF............................ 0.5...............
F............................... 0.5...............
OX.............................. See Table HH-4 of
this subpart.
DE.............................. 0.99..............
------------------------------------------------------------------------
\a\ Recirculated leachate (in inches/year) is the total volume of
leachate recirculated from company records or engineering estimates
divided by the area of the portion of the landfill containing waste
with appropriate unit conversions. Alternatively, landfills that use
leachate recirculation can elect to use the k value of 0.142 rather
than calculating the recirculated leachate rate.
\b\ Use the lesser value when precipitation plus recirculated leachate
is less than 20 inches/year. Use the greater value when precipitation
plus recirculated leachate is greater than 40 inches/year. Use the
average of the range of values when precipitation plus recirculated
leachate is 20 to 40 inches/year (inclusive). Alternatively, landfills
that use leachate recirculation can elect to use the greater value
rather than calculating the recirculated leachate rate.
\c\ Use the lesser value when the potential evapotranspiration rate
exceeds the mean annual precipitation rate plus recirculated leachate.
Use the greater value when the potential evapotranspiration rate does
not exceed the mean annual precipitation rate plus recirculated
leachate. Alternatively, landfills that use leachate recirculation can
elect to use the greater value rather than assessing the potential
evapotranspiration rate or recirculated leachate rate.
Subpart OO--Suppliers of Industrial Greenhouse Gases
0
101. Amend Sec. 98.416 by revising paragraphs (c)(6) and (7) and
(d)(4) and adding paragraph (k) to read as follows:
Sec. 98.416 Data reporting requirements.
* * * * *
(c) * * *
(6) Harmonized tariff system (HTS) code of the fluorinated GHGs,
fluorinated HTFs, or nitrous oxide shipped.
(7) Customs entry summary number and importer number for each
shipment.
* * * * *
(d) * * *
(4) Harmonized tariff system (HTS) code of the fluorinated GHGs,
fluorinated HTFs, or nitrous oxide shipped.
* * * * *
(k) For nitrous oxide, saturated perfluorocarbons, and sulfur
hexafluoride, report the end use(s) for which each GHG is transferred
and the aggregated annual quantity of that GHG in metric tons that is
transferred to that end use application, if known.
Subpart PP-- Suppliers of Carbon Dioxide
0
102. Amend Sec. 98.420 by adding paragraph (a)(4) to read as follows:
Sec. 98.420 Definition of the source category.
(a) * * *
(4) Facilities with process units, including but not limited to
direct air capture (DAC), that capture a CO2 stream from
ambient air for purposes of supplying CO2 for commercial
applications or that capture and maintain custody of a CO2
stream in order to sequester or otherwise inject it underground.
* * * * *
0
103. Amend Sec. 98.422 by adding paragraph (e) to read as follows:
Sec. 98.422 GHGs to report.
* * * * *
(e) Mass of CO2 captured from DAC process units.
(1) Mass of CO2 captured from ambient air.
(2) Mass of CO2 captured from any on-site heat and/or
electricity generation, where applicable.
0
104. Amend Sec. 98.423 by revising paragraphs (a)(3)(i) introductory
text and (a)(3)(ii) introductory text to read as follows:
Sec. 98.423 Calculating CO2 supply.
(a) * * *
(3) * * *
(i) For facilities with production process units, DAC process
units, or production wells that capture or extract a CO2
stream and either measure it after segregation or do not segregate the
flow, calculate the total CO2 supplied in accordance with
Equation PP-3a in paragraph (a)(3).
* * * * *
(ii) For facilities with production process units or DAC process
units that capture a CO2 stream and measure it ahead of
segregation, calculate the total CO2 supplied in accordance
with Equation PP-3b.
* * * * *
0
105. Amend Sec. 98.426 by adding paragraph (i) to read as follows:
Sec. 98.426 Data reporting requirements.
* * * * *
(i) If you capture a CO2 stream at a facility with a DAC
process unit, report the annual quantity of on-site and off-site
electricity and heat generated for each DAC process unit as specified
in paragraphs (i)(1) through (3) of this section. The quantities
specified in paragraphs (i)(1) through (3) must be provided per energy
source if known and must represent the electricity and heat used for
the DAC process unit starting with air intake and ending with the
compressed CO2 stream (i.e., the CO2 stream ready
for supply for commercial applications or, if maintaining custody of
the stream, sequestration or injection of the stream underground).
(1) Electricity excluding combined heat and power (CHP). If
electricity is provided to a dedicated meter for the DAC process unit,
report the annual quantity of electricity consumed, in megawatt hours
(MWh), and the information in paragraph (i)(1)(i) or (ii) of this
section.
[[Page 37114]]
(i) If the electricity is sourced from a grid connection, report
the following information:
(A) State where the facility with the DAC process unit is located.
(B) County where the facility with the DAC process unit is located.
(C) Name of the electric utility company that supplied the
electricity as shown on the last monthly bill issued by the utility
company during the reporting period.
(D) Name of the electric utility company that delivered the
electricity. In states with regulated electric utility markets, this
will generally be the same utility reported under paragraph
(i)(1)(i)(C) of this section, but in states with deregulated electric
utility markets, this may be a different utility company.
(E) Annual quantity of electricity consumed in MWh, calculated as
the sum of the total energy usage values specified in all billing
statements received during the reporting year. Most customers will
receive 12 monthly billing statements during the reporting year. Many
utilities bill their customers per kilowatt-hour (kWh); usage values on
bills that are based on kWh should be divided by 1,000 to report the
usage in MWh as required under this paragraph.
(ii) If electricity is sourced from on-site or through a
contractual mechanism for dedicated off-site generation, for each
applicable energy source specified in paragraphs (i)(1)(ii)(A) through
(G) of this section, report the annual quantity of electricity
consumed, in MWh. If the on-site electricity source is natural gas,
oil, or coal, also indicate whether flue gas is also captured by the
DAC process unit.
(A) Non-hydropower renewable sources including solar, wind,
geothermal and tidal.
(B) Hydropower.
(C) Natural gas.
(D) Oil.
(E) Coal.
(F) Nuclear.
(G) Other.
(2) Heat excluding CHP. For each applicable energy source specified
in paragraphs (i)(2)(i) through (vii) of this section, report the
annual quantity of heat, steam, or other forms of thermal energy
sourced from on-site or through a contractual mechanism for dedicated
off-site generation, in megajoules (MJ). If the on-site heat source is
natural gas, oil, or coal, also indicate whether flue gas is also
captured by the DAC process unit.
(i) Solar.
(ii) Geothermal.
(iii) Natural gas.
(iv) Oil.
(v) Coal.
(vi) Nuclear.
(vii) Other.
(3) CHP--(i) Electricity from CHP. If electricity from CHP is
sourced from on-site or through a contractual mechanism for dedicated
off-site generation, for each applicable energy source specified in
paragraphs (i)(3)(i)(A) through (G) of this section, report the annual
quantity consumed, in MWh. If the on-site electricity source for CHP is
natural gas, oil, or coal, also indicate whether flue gas is also
captured by the DAC process unit.
(A) Non-hydropower renewable sources including solar, wind,
geothermal and tidal.
(B) Hydropower.
(C) Natural gas.
(D) Oil.
(E) Coal.
(F) Nuclear.
(G) Other.
(ii) Heat from CHP. For each applicable energy source specified in
paragraphs (i)(3)(ii)(A) through (G) of this section, report the
quantity of heat, steam, or other forms of thermal energy from CHP
sourced from on-site or through a contractual mechanism for dedicated
off-site generation, in MJ. If the on-site heat source is natural gas,
oil, or coal, also indicate whether flue gas is also captured by the
DAC process unit.
(A) Solar.
(B) Geothermal.
(C) Natural gas.
(D) Oil.
(E) Coal.
(F) Nuclear.
(G) Other.
0
106. Amend Sec. 98.427 by revising paragraph (a) to read as follows:
Sec. 98.427 Records that must be retained.
* * * * *
(a) The owner or operator of a facility containing production
process units or DAC process units must retain quarterly records of
captured or transferred CO2 streams and composition.
* * * * *
Subpart SS--Electrical Equipment Manufacture or Refurbishment
0
107. Revise Sec. 98.450 to read as follows:
Sec. 98.450 Definition of the source category.
The electrical equipment manufacturing or refurbishment category
consists of processes that manufacture or refurbish gas-insulated
substations, circuit breakers, other switchgear, gas-insulated lines,
or power transformers (including gas-containing components of such
equipment) containing fluorinated GHGs, including but not limited to
sulfur-hexafluoride (SF6) and perfluorocarbons (PFCs). The processes
include equipment testing, installation, manufacturing, decommissioning
and disposal, refurbishing, and storage in gas cylinders and other
containers.
0
108. Revise Sec. 98.451 to read as follows:
Sec. 98.451 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains an electrical equipment manufacturing or refurbishing process
and the facility meets the requirements of Sec. 98.2(a)(2). To
calculate total annual GHG emissions for comparison to the 25,000
metric ton CO2e per year emission threshold in Sec. 98.2(a)(2), follow
the requirements of Sec. 98.2(b), with one exception. Instead of
following the requirement of Sec. 98.453 to calculate emissions from
electrical equipment manufacture or refurbishment, you must calculate
emissions of each fluorinated GHG, including but not limited to SF6 and
PFCs, and then sum the emissions of each fluorinated GHG resulting from
manufacturing and refurbishing electrical equipment using Equation SS-1
of this subpart.
[GRAPHIC] [TIFF OMITTED] TP21JN22.056
Where:
E = Annual production process emissions for threshold applicability
purposes (metric tons CO2e).
Pj = Total annual purchases of insulating gas j (lbs).
GHGi,w = The weight fraction of fluorinated GHG i in
insulating gas j if insulating gas j is a gas mixture. If not a
mixture, use 1.
GWPi = Gas-appropriate GWP as provided in Table A-1 to
subpart A of this part.
EF = Emission factor for electrical transmission and distribution
equipment (lbs emitted/lbs purchased). For all gases, use an
emission factor of 0.1.
[[Page 37115]]
i = fluorinated GHG contained in the electrical transmission and
distribution equipment.
0.000453592 = conversion factor from lbs to metric tons.
0
109. Amend Sec. 98.452 by revising paragraph (a) to read as follows:
Sec. 98.452 GHGs to report.
(a) You must report emissions of each fluorinated GHG, including
but not limited to SF6 and PFCs, at the facility level. Annual
emissions from the facility must include fluorinated GHG emissions from
equipment that is installed at an off-site electric power transmission
or distribution location whenever emissions from installation
activities (e.g., filling) occur before the title to the equipment is
transferred to the electric power transmission or distribution entity.
* * * * *
0
110. Amend Sec. 98.453 by:
0
a. Revising paragraph (a);
0
b. Removing and reserving paragraph (b); and
0
c. Revising paragraphs (c) through (g), (h) introductory text, and (i).
The revisions read as follows:
Sec. 98.453 Calculating GHG emissions.
(a) For each electrical equipment manufacturer or refurbisher,
estimate the annual emissions of each fluorinated GHG using the mass-
balance approach in Equation SS-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.057
Where:
User emissionsi = Annual emissions of each fluorinated
GHG i (pounds).
GHGi,w = The weight fraction of fluorinated GHG i in
insulating gas j if insulating gas j is a gas mixture, expressed as
a decimal fraction. If fluorinated GHG i is not part of a gas
mixture, use a value of 1.0.
Decrease in insulating gas j Inventory = (Pounds of insulating gas j
stored in containers at the beginning of the year) - (Pounds of
insulating gas j stored in containers at the end of the year).
Acquisitions of insulating gas j = (Pounds of each insulating gas j
purchased from chemical producers or suppliers in bulk) + (Pounds of
each insulating gas j returned by equipment users) + (Pounds of each
insulating gas j returned to site after off-site recycling).
Disbursements of insulating gas j = (Pounds of each insulating gas j
contained in new equipment delivered to customers) + (Pounds of each
insulating gas j delivered to equipment users in containers) +
(Pounds of each insulating gas j returned to suppliers) + (Pounds of
each insulating gas j sent off site for recycling) + (Pounds of each
insulating gas j sent off-site for destruction).
* * * * *
(c) Estimate the disbursements of each insulating gas j (including,
but not limited to SF6 and PFCs) sent to customers in new
equipment or cylinders or sent off-site for other purposes including
for recycling, for destruction or to be returned to suppliers using
Equation SS-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.058
Where:
DGHG = The annual disbursement of each insulating gas j
sent to customers in new equipment or cylinders or sent off-site for
other purposes including for recycling, for destruction or to be
returned to suppliers.
Qp = The mass of each insulating gas j charged into
equipment or containers over the period p sent to customers or sent
off-site for other purposes including for recycling, for destruction
or to be returned to suppliers.
n = The number of periods in the year.
(d) Estimate the mass of each insulating gas j (including, but not
limited to SF6 and PFCs) disbursed to customers in new
equipment or cylinders over the period p by monitoring the mass flow of
each insulating gas j into the new equipment or cylinders using a
flowmeter, or by weighing containers before and after gas from
containers is used to fill equipment or cylinders, or by using the
nameplate capacity of the equipment.
(e) If the mass of insulating gas j disbursed to customers in new
equipment or cylinders over the period p is estimated by weighing
containers before and after gas from containers is used to fill
equipment or cylinders, estimate this quantity using Equation SS-4 of
this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.059
Where:
Qp = The mass of each insulating gas j charged into
equipment or containers over the period p sent to customers or sent
off-site for other purposes including for recycling, for destruction
or to be returned to suppliers.
MB = The mass of the contents of the containers used to
fill equipment or cylinders at the beginning of period p.
ME = The mass of the contents of the containers used to
fill equipment or cylinders at the end of period p.
EL = The mass of each insulating gas j emitted during the
period p downstream of the containers used to fill equipment or
cylinders and in cases where a flowmeter is used, downstream of the
flowmeter during the period p (e.g., emissions from hoses or other
flow lines that connect the container to the equipment or cylinder
that is being filled).
(f) If the mass of each insulating gas j (including, but not
limited to SF6 and PFCs) disbursed to customers in new
equipment or cylinders over the period p is determined using a
flowmeter, estimate this quantity using Equation SS-5 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.060
[[Page 37116]]
Where:
Qp = The mass of each insulating gas j (including, but
not limited to SF6 and PFCs) charged into equipment or
containers over the period p sent to customers or sent off-site for
other purposes including for recycling, for destruction or to be
returned to suppliers.
Mmr = The mass of each insulating gas j that has flowed
through the flowmeter during the period p.
EL = The mass of each insulating gas j emitted during the
period p downstream of the containers used to fill equipment or
cylinders and in cases where a flowmeter is used, downstream of the
flowmeter during the period p (e.g., emissions from hoses or other
flow lines that connect the container to the equipment that is being
filled).
(g) Estimate the mass of each insulating gas j emitted during the
period p downstream of the containers used to fill equipment or
cylinders (e.g., emissions from hoses or other flow lines that connect
the container to the equipment or cylinder that is being filled) using
Equation SS-6 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.061
Where:
EL = The mass of each fluorinated GHG (including, but not
limited to SF6 and PFCs) or fluorinated GHG mixture
emitted during the period p downstream of the containers used to
fill equipment or cylinders and in cases where a flowmeter is used,
downstream of the flowmeter during the period p (e.g., emissions
from hoses or other flow lines that connect the container to the
equipment or cylinder that is being filled).
FCi = The total number of fill operations over the period
p for the valve-hose combination Ci.
EFCi = The emission factor for the valve-hose combination
Ci.
n = The number of different valve-hose combinations C used during
the period p.
(h) If the mass of each insulating gas j disbursed to customers in
new equipment or cylinders over the period p is determined by using the
nameplate capacity, or by using the nameplate capacity of the equipment
and calculating the partial shipping charge, use the methods in either
paragraph (h)(1) or (h)(2) of this section.
* * * * *
(i) Estimate the annual emissions of each insulating gas j from the
equipment that is installed at an off-site electric power transmission
or distribution location before the title to the equipment is
transferred by using Equation SS-7 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.062
Where:
EI = Total annual emissions of each insulating gas j from equipment
installation at electric transmission or distribution facilities.
GHGi,w = The weight fraction of fluorinated GHG i in
insulating gas j if insulating gas j is a gas mixture, expressed as
a decimal fraction. If the GHG i is not part of a gas mixture, use a
value of 1.0.
MF = The total annual mass of each insulating gas j, in
pounds, used to fill equipment during equipment installation at
electric transmission or distribution facilities.
MC = The total annual mass of each insulating gas j, in
pounds, used to charge the equipment prior to leaving the electrical
equipment manufacturer facility.
NI = The total annual nameplate capacity of the
equipment, in pounds, installed at electric transmission or
distribution facilities.
0
111. Amend Sec. 98.454 by removing and reserving paragraph (a) and
revising paragraphs (b), (d) through (f), and (h)(1) through (4).
The revisions read as follows:
Sec. 98.454 Monitoring and QA/QC requirements.
* * * * *
(b) Ensure that all the quantities required by the equations of
this subpart have been measured using either flowmeters with an
accuracy and precision of 1 percent of full scale or better
or scales with an accuracy and precision of 1 percent of
the filled weight (gas plus tare) of the containers of each insulating
gas that are typically weighed on the scale. For scales that are
generally used to weigh cylinders containing 115 pounds of gas when
full, this equates to 1 percent of the sum of 115 pounds
and approximately 120 pounds tare, or slightly more than 2
pounds. Account for the tare weights of the containers. You may accept
gas masses or weights provided by the gas supplier (e.g., for the
contents of cylinders containing new gas or for the heels remaining in
cylinders returned to the gas supplier) if the supplier provides
documentation verifying that accuracy standards are met; however, you
remain responsible for the accuracy of these masses and weights under
this subpart.
* * * * *
(d) For purposes of Equations SS-6 of this subpart, the emission
factor for the valve-hose combination (EFC) must be
estimated using measurements and/or engineering assessments or
calculations based on chemical engineering principles or physical or
chemical laws or properties. Such assessments or calculations may be
based on, as applicable, the internal volume of hose or line that is
open to the atmosphere during coupling and decoupling activities, the
internal pressure of the hose or line, the time the hose or line is
open to the atmosphere during coupling and decoupling activities, the
frequency with which the hose or line is purged and the flow rate
during purges. You must develop a value for EFc (or use an
industry-developed value) for each combination of hose and valve
fitting, to use in Equation SS-6 of this subpart. The value for
EFC must be determined for each combination of hose and
valve fitting of a given diameter or size. The calculation must be
recalculated annually to account for changes to the specifications of
the valves or hoses that may occur throughout the year.
(e) Electrical equipment manufacturers and refurbishers must
account for emissions of each insulating gas that occur as a result of
unexpected events or accidental losses, such as a malfunctioning hose
or leak in the flow line, during the filling of equipment or containers
for disbursement by including these losses in the estimated mass of
each insulating gas emitted downstream of the container or flowmeter
during the period p.
(f) If the mass of each insulating gas j disbursed to customers in
new equipment over the period p is determined by assuming that it is
equal to the equipment's nameplate capacity or, in cases where
equipment is shipped
[[Page 37117]]
with a partial charge, equal to its partial shipping charge, equipment
samples for conducting the nameplate capacity tests must be selected
using the following stratified sampling strategy in this paragraph. For
each make and model, group the measurement conditions to reflect
predictable variability in the facility's filling practices and
conditions (e.g., temperatures at which equipment is filled). Then,
independently select equipment samples at random from each make and
model under each group of conditions. To account for variability, a
certain number of these measurements must be performed to develop a
robust and representative average nameplate capacity (or shipping
charge) for each make, model, and group of conditions. A Student T
distribution calculation should be conducted to determine how many
samples are needed for each make, model, and group of conditions as a
function of the relative standard deviation of the sample measurements.
To determine a sufficiently precise estimate of the nameplate capacity,
the number of measurements required must be calculated to achieve a
precision of one percent of the true mean, using a 95 percent
confidence interval. To estimate the nameplate capacity for a given
make and model, you must use the lowest mean value among the different
groups of conditions, or provide justification for the use of a
different mean value for the group of conditions that represents the
typical practices and conditions for that make and model. Measurements
can be conducted using SF6, another gas, or a liquid. Re-
measurement of nameplate capacities should be conducted every five
years to reflect cumulative changes in manufacturing methods and
conditions over time.
* * * * *
(h) * * *
(1) Review inputs to Equation SS-2 of this subpart to ensure inputs
and outputs to the company's system are included.
(2) Do not enter negative inputs and confirm that negative
emissions are not calculated. However, the decrease in the inventory
for each insulating gas may be calculated as negative.
(3) Ensure that for each insulating gas, the beginning-of-year
inventory matches the end-of-year inventory from the previous year.
(4) Ensure that for each insulating gas, in addition to the
insulating gas purchased from bulk gas distributors, the insulating gas
returned from equipment users with or inside equipment and the
insulating gas returned from off-site recycling are also accounted for
among the total additions.
0
112. Amend Sec. 98.456 by revising paragraphs (a) through (k) and (n)
through (s) and adding paragraphs (u) and (v) to read as follows:
Sec. 98.456 Data reporting requirements.
* * * * *
(a) Pounds of each insulating gas stored in containers at the
beginning of the year.
(b) Pounds of each insulating gas stored in containers at the end
of the year.
(c) Pounds of each insulating gas purchased in bulk.
(d) Pounds of each insulating gas returned by equipment users with
or inside equipment.
(e) Pounds of each insulating gas returned to site from off site
after recycling.
(f) Pounds of each insulating gas inside new equipment delivered to
customers.
(g) Pounds of each insulating gas delivered to equipment users in
containers.
(h) Pounds of each insulating gas returned to suppliers.
(i) Pounds of each insulating gas sent off site for destruction.
(j) Pounds of each insulating gas sent off site to be recycled.
(k) The nameplate capacity of the equipment, in pounds, delivered
to customers with insulating gas inside, if different from the quantity
in paragraph (f) of this section.
* * * * *
(n) The total number of fill operations for each hose and valve
combination, or, FCi of Equation SS-6 of this subpart.
(o) If the mass of each insulating gas disbursed to customers in
new equipment over the period p is determined according to the methods
required in Sec. 98.453(h), report the mean value of nameplate
capacity in pounds for each make, model, and group of conditions.
(p) If the mass of each insulating gas disbursed to customers in
new equipment over the period p is determined according to the methods
required in Sec. 98.453(h), report the number of samples and the upper
and lower bounds on the 95-percent confidence interval for each make,
model, and group of conditions.
(q) Pounds of each insulating gas used to fill equipment at off-
site electric power transmission or distribution locations, or
MF, of Equation SS-7 of this subpart.
(r) Pounds of each insulating gas used to charge the equipment
prior to leaving the electrical equipment manufacturer or refurbishment
facility, or MC, of Equation SS-7 of this subpart.
(s) The nameplate capacity of the equipment, in pounds, installed
at off-site electric power transmission or distribution locations used
to determine emissions from installation, or NI, of Equation
SS-7 of this subpart.
* * * * *
(u) For each unique insulating gas reported in paragraphs (a)
through (j) and (o) through (r) of this section, an ID number or other
appropriate descriptor.
(v) For each ID number or descriptor reported in paragraph (u) of
this section for each unique insulating gas, the name (as required in
Sec. 98.3(c)(4)(iii)(G)(1)) and weight percent of each fluorinated gas
in the insulating gas.
0
113. Revise Sec. 98.458 to read as follows:
Sec. 98.458 Definitions.
Except as specified in this section, all terms used in this subpart
have the same meaning given in the CAA and subpart A of this part.
Insulating gas, for the purposes of this subpart, means any
fluorinated GHG or fluorinated GHG mixture, including but not limited
to SF6 and PFCs, that is used as an insulating and/or arc-
quenching gas in electrical equipment.
Subpart UU--Injection of Carbon Dioxide
0
114. Amend Sec. 98.470 by redesignating paragraph (c) as paragraph (d)
and adding new paragraph (c) to read as follows:
Sec. 98.470 Definition of the source category.
* * * * *
(c) If you report under subpart VV of this part for a well or group
of wells, you are not required to report under this subpart for that
well or group of wells.
* * * * *
0
115. Add subpart VV to read as follows:
Subpart VV--Geologic Sequestration of Carbon Dioxide With Enhanced
Oil Recovery Using ISO 27916
Sec.
98.480 Definition of the source category.
98.481 Reporting threshold.
98.482 GHGs to report.
98.483 Calculating CO2 geologic sequestration.
98.484 Monitoring and QA/QC requirements.
98.485 Procedures for estimating missing data.
98.486 Data reporting requirements.
98.487 Records that must be retained.
98.488 EOR Operations Management Plan.
98.489 Definitions.
[[Page 37118]]
Subpart VV--Geologic Sequestration of Carbon Dioxide With Enhanced
Oil Recovery Using ISO 27916
Sec. 98.480 Definition of the source category.
(a) This source category pertains to carbon dioxide
(CO2) that is injected in enhanced recovery operations for
oil and other hydrocarbons (CO2-EOR) in which all of the
following apply:
(1) You are using the International Standards Organization (ISO)
standard designated as CSA/ANSI ISO 27916:2019 (incorporated by
reference, see Sec. 98.7) as a method of quantifying geologic
sequestration of CO2 in association with EOR operations.
(2) You are not reporting under subpart UU of this part.
(3) You are not reporting under subpart RR of this part.
(b) This source category does not include wells permitted as Class
VI under the Underground Injection Control program.
(c) If you are subject to only this subpart, you are not required
to report emissions under subpart C of this part or any other subpart
listed in Sec. 98.2(a)(1) or (a)(2).
Sec. 98.481 Reporting threshold.
(a) You must report under this subpart if your CO2-EOR
project uses CSA/ANSI ISO 27916:2019 (incorporated by reference, see
Sec. 98.7) as a method of quantifying geologic sequestration of
CO2 in association with CO2-EOR operations. There
is no threshold for reporting.
(b) The requirements of Sec. 98.2(i) do not apply to this subpart.
Once a CO2-EOR project becomes subject to the requirements
of this subpart, you must continue for each year thereafter to comply
with all requirements of this subpart, including the requirement to
submit annual reports until the facility has met the requirements of
paragraphs (b)(1) and (2) of this section and submitted a notification
to discontinue reporting according to paragraph (b)(3) of this section.
(1) Discontinuation of reporting under this subpart must follow the
requirements set forth under Clause 10 of CSA/ANSI ISO 27916:2019.
(2) CO2-EOR project termination is completed when all of
the following occur:
(i) Cessation of CO2 injection.
(ii) Cessation of hydrocarbon production from the project
reservoir; and
(iii) Wells are plugged and abandoned unless otherwise required by
the appropriate regulatory authority.
(3) You must notify the Administrator of your intent to cease
reporting and provide a copy of the CO2-EOR project
termination documentation.
Sec. 98.482 GHGs to report.
You must report the following from Clause 8 of CSA/ANSI ISO
27916:2019 (incorporated by reference, see Sec. 98.7):
(a) The mass of CO2 received by the CO2-EOR
project.
(b) The mass of CO2 loss from the CO2-EOR
project operations.
(c) The mass of native CO2 produced and captured.
(d) The mass of CO2 produced and sent off-site.
(e) The mass of CO2 loss from the EOR complex.
(f) The mass of CO2 stored in association with
CO2-EOR.
Sec. 98.483 Calculating CO2 geologic sequestration.
You must calculate CO2 sequestered using the following
quantification principles from Clause 8.2 of CSA/ANSI ISO 27916:2019
(incorporated by reference, see Sec. 98.7).
(a) You must calculate the mass of CO2 stored in
association with CO2-EOR (mstored) in the
reporting year by subtracting the mass of CO2 loss from
operations and the mass of CO2 loss from the EOR complex
from the total mass of CO2 input (as specified in Equation
VV-1 of this section).
[GRAPHIC] [TIFF OMITTED] TP21JN22.063
Where:
mstored = the annual quantity of associated storage in
metric tons of CO2 mass.
minput = the total mass of CO2
mreceived by the EOR project plus mnative (see
Clause 8.3 and paragraph (c) of this section), metric tons. Native
CO2 produced and captured in the CO2-EOR
project (mnative) can be quantified and included in
minput.
mloss operations = the total mass of CO2 loss
from project operations (see Clauses 8.4.1 through 8.4.5 and
paragraph (d) of this section), metric tons.
mloss EOR complex = the total mass of CO2 loss
from the EOR complex (see Clause 8.4.6), metric tons.
(b) The manner by which associated storage is quantified must
assure completeness and preclude double counting. The annual mass of
CO2 that is recycled and reinjected into the EOR complex
must not be quantified as associated storage. Loss from the
CO2 recycling facilities must be quantified.
(c) You must quantify the total mass of CO2 input
(minput) in the reporting year according to paragraphs
(c)(1) through (3) of this section.
(1) You must include the total mass of CO2 received at
the custody transfer meter by the CO2-EOR project
(mreceived).
(2) The CO2 stream received (including CO2
transferred from another CO2-EOR project) must be metered.
(i) The native CO2 recovered and included as
mnative must be documented.
(ii) CO2 delivered to multiple CO2-EOR
projects must be allocated among those CO2-EOR projects.
(3) The sum of the quantities of allocated CO2 must not
exceed the total quantities of CO2 received.
(d) You must calculate the total mass of CO2 from
project operations (mloss operations) in the reporting year
as specified in Equation VV-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP21JN22.066
Where:
mloss leakage facilities = Loss of CO2 due to
leakage from production, handling, and recycling CO2-EOR
facilities (infrastructure including wellheads), metric tons.
mloss vent/flare = Loss of CO2 from venting/
flaring from production operations, metric tons.
mloss entrained = Loss of CO2 due to
entrainment within produced gas/oil/water when this CO2
is not separated and reinjected, metric tons.
mloss transfer = Loss of CO2 due to any
transfer of CO2 outside the CO2-EOR project,
metric tons. You must quantify any CO2 that is
subsequently produced from the EOR complex and transferred offsite.
[[Page 37119]]
Sec. 98.484 Monitoring and QA/QC requirements.
You must use the applicable monitoring and quality assurance
requirements set forth in Clause 6.2 of CSA/ANSI ISO 27916:2019
(incorporated by reference, see Sec. 98.7).
Sec. 98.485 Procedures for estimating missing data.
Whenever the value of a parameter is unavailable or the quality
assurance procedures set forth in Sec. 98.484 cannot be followed, you
must follow the procedures set forth in Clause 9.2 of CSA/ANSI ISO
27916:2019 (incorporated by reference, see Sec. 98.7).
Sec. 98.486 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), the
annual report shall contain the following information, as applicable:
(a) The annual quantity of associated storage in metric tons of
CO2 (mstored).
(b) The density of CO2 if volumetric units are converted
to mass in order to be reported for annual quantity of CO2
stored.
(c) The annual quantity of CO2 input (minput)
and the information in paragraphs (c)(1) and (2) of this section.
(1) The annual total mass of CO2 received at the custody
transfer meter by the CO2-EOR project, including
CO2 transferred from another CO2-EOR project
(mreceived).
(2) The annual mass of native CO2 produced and captured
in the CO2-EOR project (mnative).
(d) The annual mass of CO2 that is recycled and
reinjected into the EOR complex.
(e) The annual total mass of CO2 loss from project
operations (mloss operations), and the information in
paragraphs (e)(1) through (4) of this section.
(1) Loss of CO2 due to leakage from production,
handling, and recycling CO2-EOR facilities (infrastructure
including wellheads) (mloss leakage facilities).
(2) Loss of CO2 from venting/flaring from production
operations (mloss vent/flare).
(3) Loss of CO2 due to entrainment within produced gas/
oil/water when this CO2 is not separated and reinjected
(mloss entrained).
(4) Loss of CO2 due to any transfer of CO2
outside the CO2-EOR project (mloss transfer).
(f) The total mass of CO2 loss from the EOR complex
(mloss EOR complex).
(g) Annual documentation that contains the following components as
described in Clause 4.4 of CSA/ANSI ISO 27916:2019 (incorporated by
reference, see Sec. 98.7):
(1) The formulas used to quantify the annual mass of associated
storage, including the mass of CO2 delivered to the
CO2-EOR project and losses during the period covered by the
documentation (see Clause 8 and Annex B).
(2) The methods used to estimate missing data and the amounts
estimated as described in Clause 9.2.
(3) The approach and method for quantification utilized by the
operator, including accuracy, precision, and uncertainties (see Clause
8 and Annex B).
(4) A statement describing the nature of validation or verification
including the date of review, process, findings, and responsible person
or entity.
(5) Source of each CO2 stream quantified as associated
storage (see Clause 8.3).
(6) A description of the procedures used to detect and characterize
the total CO2 leakage from the EOR complex.
(7) If only the mass of anthropogenic CO2 is considered
for mstored, a description of the derivation and application
of anthropogenic CO2 allocation ratios for all the terms
described in Clauses 8.1 to 8.4.6.
(8) Any documentation provided by a qualified independent engineer
or geologist, who certifies that the documentation provided, including
the mass balance calculations as well as information regarding
monitoring and containment assurance, is accurate and complete.
(h) Any changes made within the reporting year to containment
assurance and monitoring approaches and procedures in the EOR
operations management plan.
Sec. 98.487 Records that must be retained.
You must follow the record retention requirements specified by
Sec. 98.3(g). In addition to the records required by Sec. 98.3(g),
you must comply with the record retention requirements in Clause 9.1 of
CSA/ANSI ISO 27916:2019 (incorporated by reference, see Sec. 98.7).
Sec. 98.488 EOR Operations Management Plan.
(a) You must prepare and update, as necessary, a general EOR
operations management plan that provides a description of the EOR
complex and engineered system (see Clause 4.3 (a)), establishes that
the EOR complex is adequate to provide safe, long-term containment of
CO2, and includes site-specific and other information
including:
(1) Geologic characterization of the EOR complex.
(2) A description of the facilities within the CO2-EOR
project.
(3) A description of all wells and other engineered features in the
CO2-EOR project.
(4) The operations history of the project reservoir.
(5) The information set forth in Clauses 5 and 6 of CSA/ANSI ISO
27916:2019 (incorporated by reference, see Sec. 98.7).
(b) You must prepare initial documentation at the beginning of the
quantification period, and include the following as described in the
EOR operations management plan:
(1) A description of the EOR complex and engineered systems (see
Clause 5).
(2) The initial containment assurance (see Clause 6.1.2).
(3) The monitoring program (see Clause 6.2).
(4) The quantification method to be used (see Clause 8 and Annex
B).
(5) The total mass of previously injected CO2 (if any)
within the EOR complex at the beginning of the CO2-EOR
project (see Clause 8.5 and Annex B).
(c) The EOR operation management plan in paragraph (a) of this
section and initial documentation in paragraph (b) of this section must
be submitted to the Administrator with the annual report covering the
first reporting year that the facility reports under this subpart. In
addition, any documentation provided by a qualified independent
engineer or geologist, who certifies that the documentation provided is
accurate and complete, must also be provided to the Administrator.
(d) If the EOR operations management plan is updated, the updated
EOR management plan must be submitted to the Administrator with the
annual report covering the first reporting year for which the updated
EOR operation management plan is applicable.
Sec. 98.489 Definitions.
Except as provided in paragraphs (a) and (b) of this section, all
terms used in this subpart have the same meaning given in the Clean Air
Act and subpart A of this part.
(a) Additional terms and definitions are provided in Clause 3 of
CSA/ANSI ISO 27916:2019 (incorporated by reference, see Sec. 98.7).
(b) All references in this subpart preceded by the word Clause
refer to the Clauses in CSA/ANSI ISO 27916:2019.
[FR Doc. 2022-09660 Filed 6-17-22; 8:45 am]
BILLING CODE 6560-50-P