Mandatory Reporting of Greenhouse Gases: Technical Revisions to the Electronics Manufacturing and the Petroleum and Natural Gas Systems Categories of the Greenhouse Gas Reporting Rule, 56010-56051 [2011-21725]
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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 98
[EPA–HQ–OAR–2011–0512; FRL–9456–4]
RIN 2060–AR09
Mandatory Reporting of Greenhouse
Gases: Technical Revisions to the
Electronics Manufacturing and the
Petroleum and Natural Gas Systems
Categories of the Greenhouse Gas
Reporting Rule
Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
AGENCY:
This action proposes
technical revisions to the electronics
manufacturing and the petroleum and
natural gas systems source categories of
the greenhouse gas reporting rule.
Proposed changes include providing
clarification on existing requirements,
increasing flexibility for certain
calculation methods, amending data
reporting requirements clarifying terms
and definitions, and technical
corrections. In addition, the
Environmental Protection Agency is
proposing to amend the definition of
heat transfer fluids in subpart I to
include more fluorocarbons used as heat
transfer fluids in the electronics
manufacturing industry.
DATES: Comments. Comments must be
received on or before October 11, 2011,
unless a public hearing is held, in
which case comments must be received
on or before October 24, 2011.
Public Hearing. A public hearing will
be held if requested. To request a
hearing, please contact the person listed
in the following FOR FURTHER
INFORMATION CONTACT section by
September 16, 2011. If requested, the
hearing will be conducted on September
26, 2011, in the Washington, DC area.
EPA will publish further information
about the hearing in the Federal
Register if a hearing is requested.
ADDRESSES: You may submit your
comments, identified by Docket ID No.
EPA–HQ–OAR–2011–0512 by any of the
following methods:
• Federal eRulemaking Portal: https://
www.regulations.gov. Follow the online
instructions for submitting comments.
E-mail: GHG_Reporting_Rule_Oil_
And_Natural_Gas@epa.gov. Include
Docket ID No. EPA–HQ–OAR–2011–
0512 in the subject line of the message.
• Fax: (202) 566–9744.
• Mail: Environmental Protection
Agency, EPA Docket Center (EPA/DC),
Mail Code 28221T, Attention Docket ID
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SUMMARY:
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No. EPA–HQ–OAR–2011–0512, 1200
Pennsylvania Avenue, NW.,
Washington, DC 20460.
• Hand/Courier Delivery: EPA Docket
Center, Public Reading Room, EPA West
Building, Room 3334, Attention Docket
ID No. EPA–HQ–OAR–2011–0512, 1301
Constitution Avenue, NW., Washington,
DC 20004. Such deliveries are only
accepted during the docket’s normal
hours of operation, and special
arrangements should be made for
deliveries of boxed information.
Instructions: Direct your comments to
Docket ID No. EPA–HQ–OAR–2011–
0512, Mandatory Reporting of
Greenhouse Gases: Petroleum and
Natural Gas Systems. EPA’s policy is
that all comments received will be
included in the public docket without
change and may be made available
online at https://www.regulations.gov,
including any personal information
provided, unless the comment includes
information claimed to be confidential
business information (CBI) or other
information whose disclosure is
restricted by statute. Do not submit
information that you consider to be CBI
or otherwise protected through https://
www.regulations.gov or e-mail. The
https://www.regulations.gov Web site is
an ‘‘anonymous access’’ system, which
means EPA will not know your identity
or contact information unless you
provide it in the body of your comment.
If you send an e-mail comment directly
to EPA without going through https://
www.regulations.gov your e-mail
address will be automatically captured
and included as part of the comment
that is placed in the public docket and
made available on the Internet. If you
submit an electronic comment, EPA
recommends that you include your
name and other contact information in
the body of your comment and with any
disk or CD–ROM you submit. If EPA
cannot read your comment due to
technical difficulties and cannot contact
you for clarification, EPA may not be
able to consider your comment.
Electronic files should avoid the use of
special characters, any form of
encryption, and be free of any defects or
viruses.
Docket: All documents in the docket
are listed in the https://
www.regulations.gov index. Although
listed in the index, some information is
not publicly available, e.g., CBI or other
information whose disclosure is
restricted by statute. Certain other
material, such as copyrighted material,
will be publicly available for viewing at
the EPA Docket Center. Publicly
available docket materials are available
either electronically in https://
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www.regulations.gov or in hard copy at
the EPA Docket Center, EPA/DC, EPA
West Building, Room 3334, 1301
Constitution Ave., NW., Washington,
DC. This Docket Facility is open from
8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The
telephone number for the Public
Reading Room is (202) 566–1744, and
the telephone number for the Air Docket
is (202) 566–1742.
FOR FURTHER INFORMATION CONTACT:
Carole Cook, Climate Change Division,
Office of Atmospheric Programs (MC–
6207J), Environmental Protection
Agency, 1200 Pennsylvania Ave., NW.,
Washington, DC 20460; telephone
number: (202) 343–9263; fax number:
(202) 343–2342; e-mail address:
GHGReportingRule@epa.gov. For
technical questions, please see the
Greenhouse Gas Reporting Program Web
site https://www.epa.gov/climatechange/
emissions/ghgrulemaking.html. To
submit a question, select Rule Help
Center, followed by Contact Us. To
obtain information about the public
hearing or to register to speak at the
public hearing, please go to https://
www.epa.gov/climatechange/emissions/
ghgrulemaking.html. Alternatively, you
may contact Carole Cook at 202–343–
9263.
SUPPLEMENTARY INFORMATION:
Worldwide Web (WWW). In addition
to being available in the docket, an
electronic copy of today’s proposal will
also be available through the WWW.
Following the Administrator’s signature,
a copy of this action will be posted on
EPA’s greenhouse gas reporting rule
Web site at https://www.epa.gov/
climatechange/emissions/
ghgrulemaking.html.
Additional information on submitting
comments. To expedite review of your
comments by Agency staff, you are
encouraged to send a separate copy of
your comments, in addition to the copy
you submit to the official docket, to
Carole Cook, U.S. EPA, Office of
Atmospheric Programs, Climate Change
Division, Mail Code 6207–J,
Washington, DC 20460, telephone (202)
343–9263, e-mail address:
GHGReportingRule@epa.gov.
Regulated Entities. The Administrator
determined that this action is subject to
the provisions of Clean Air Act (CAA)
section 307(d). If finalized, these
amended regulations could affect
owners or operators of petroleum and
natural gas systems and certain
electronic manufacturers. Regulated
categories and entities may include
those listed in Table 1 of this preamble:
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TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY
Source category
NAICS
Petroleum and Natural Gas Systems ....................
Electronics 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
action. Although Table 1 of this
preamble lists the types of facilities of
which EPA is aware that could be
potentially affected by this action, other
types of facilities not listed in the table
could also be affected. To determine
whether you are affected by this action,
you should carefully examine the
applicability criteria found in 40 CFR
part 98 subpart A, 40 CFR part 98
subpart I and 40 CFR part 98 subpart W.
If you have questions regarding the
applicability of this action to a
particular facility, consult the person
listed in the preceding FOR FURTHER
INFORMATION CONTACT section.
Acronyms and Abbreviations. The
following acronyms and abbreviations
are used in this document.
AGA American Gas Association
API American Petroleum Institute
AXPC American Exploration and
Production Council
BAMM Best Available Monitoring Methods
BOEMRE Bureau of Ocean Energy
Management, Regulation and Enforcement
CAA Clean Air Act
CBI confidential business information
CEC Chesapeake Energy Corporation
CEMS continuous emission monitoring
systems
cfd cubic feet per day
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e CO2-equivalent
COR certificate of representation
e-GGRT electronic greenhouse gas reporting
tool
EIA Economic Impact Analysis
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
FCML Field Code Master List
FERC Federal Energy Regulatory
Commission
FR Federal Register
GHG greenhouse gas
GPA Gas Processors Association
GOR gas to oil ratio
GRI Gas Research Institute
Hp horsepower
GWP global warming potential
HHV high heat value
HTF heat transfer fluid
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Examples of affected facilities
486210
221210
211
211112
334111
334413
334419
334419
Pipeline transportation of natural gas.
Natural gas distribution facilities.
Extractors of crude petroleum and natural gas.
Natural gas liquid extraction facilities.
Microcomputers manufacturing facilities.
Semiconductor, photovoltaic (solid-state) device manufacturing facilities.
Liquid Crystal Display (LCD) unit screens manufacturing facilities.
Micro-electro-mechanical systems (MEMS) manufacturing facilities.
IBR incorporation by reference
ICR information collection request
LDC Local Distribution Company
ISO International Organization for
Standardization
kg kilograms
LDCs local natural gas distribution
companies
LNG liquefied natural gas
M&R meters and regulators
mmBtu million British thermal units
mmHg millimeters of Mercury
MMscfd million standard cubic feet per day
mTCO2e million metric tons carbon dioxide
equivalent
MRR mandatory GHG reporting rule
N2O nitrous oxide
NAICS North American Industry
Classification System
NF3 nitrogen trifluoride
NGLs natural gas liquids
NPS nominal pipe size
NTTAA National Technology Transfer and
Advancement Act
OAQPS Office of Air Quality, Planning and
Standards
OMB Office of Management and Budget
PHMSA Pipeline and Hazardous Material
Safety Administration
QA/QC quality assurance/quality control
RFA Regulatory Flexibility Act
SBA Small Business Administration
SBREFA Small Business Regulatory
Enforcement and Fairness Act
SF6 sulfur hexafluoride
T–D Transmission Distribution
TSD technical support document
U.S. United States
UMRA Unfunded Mandates Reform Act of
1995
USC United States Code
Table of Contents
I. Background
A. How is this preamble organized?
B. Background on the Proposed Action
C. Legal Authority
D. How would these amendments apply to
2012 reports?
II. Technical Corrections and Other
Amendments
A. Subpart A—General Provisions
B. Subpart I—Electronics Manufacturing
C. Subpart W—Petroleum and Natural Gas
Systems
III. 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
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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
I. Background
A. How is this preamble organized?
The first section of this preamble
contains the basic background
information about the origin of these
proposed rule amendments and request
for public comment. This section also
discusses EPA’s use of legal authority
under the CAA to collect data on GHGs.
The second section of this preamble
describes in detail the changes that are
being proposed to correct technical
errors or to address implementation
issues identified by EPA and others.
This section also presents EPA’s
rationale for the proposed changes and
identifies issues on which EPA is
particularly interested in receiving
public comments.
Finally, the last (third) section
discusses the various statutory and
executive order requirements applicable
to this proposed rulemaking.
B. Background on the Proposed Action
EPA published subpart I: Electronics
Manufacturing of the Greenhouse Gas
Reporting Program (GHGRP) on
December 1, 2010 (75 FR 74774) subpart
I of the GHGRP requires monitoring and
reporting of GHG emissions from
electronics manufacturing. Electronics
manufacturing facilities covered by
subpart I are those that have emissions
equal to or greater than 25,000 mtCO2e.
Following the publication of subpart
I in the Federal Register, 3M Company
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(3M) sought reconsideration of the final
rule requirements for reporting
fluorinated heat transfer fluids (HTFs).
In this action EPA, is proposing
amendments to the provisions in
subpart I related to calculating and
reporting fluorinated HTFs to reflect the
Agency’s intent to cover all
fluorocarbons (except for ozone
depleting substances regulated under
EPA’s Stratospheric Protection
Regulations at 40 CFR part 82) that can
enter the atmosphere under the
conditions in which HTFs are used in
the electronics manufacturing industry.
EPA published Subpart W: Petroleum
and Natural Gas Systems of the
Greenhouse Gas Reporting Rule on
November 30, 2010(75 FR 74458).
Subpart W of the GHGRP, which applies
to facilities in specific segments of the
petroleum and natural gas industry that
emit GHGs greater than or equal to
25,000 mtCO2e per year, covers
approximately 85 percent of GHG
emissions—including vented,
equipment leak, and combustion
emissions—from facilities in specific
segments of the petroleum and natural
gas industry.
Following the publication of subpart
W in the Federal Register, several
industry groups requested
reconsideration of several provisions in
the final rule. Part of the proposed
amendments in this action are in
response to those requests for
reconsideration. Today we are granting
reconsideration of, and requesting
comment on, those issues raised in the
petitions listed in Table 2 where
indicated in such Table that the issue is
addressed in this action. While we do
not necessarily agree that each of those
identified issues meet the criteria for
reconsideration, we nonetheless believe
that they do raise important
implementation issues and are thus
granting reconsideration of those issues
and proposing concomitant revisions to
the rule. At this time we are not granting
reconsideration of other issues raised in
those petitions where indicated in the
following table that they are not being
addressed in this action but will
consider those issues at a later time.
TABLE 2—PETITIONS FOR RECONSIDERATION
Issue raised for reconsideration
American Gas Association by letter dated
March 2, 2011.
Non custody transfer city gate station terminology. AGA asserted that ‘‘[s]everal provisions in the Subpart W rule and preamble
seem to imply that a ‘non-custody-transfer
city gate station’ will always have a meter’’.
Yes.
Custody transfer city gate station terminology.
AGA asserted that the term ‘‘custody transfer city gate station’’ in subpart W was unclear and needed clarification.
Yes.
Use of GTI emission factors. AGA requested
reconsideration of the emissions factors for
Local Distribution Companies in the final
rule.
Partially.
New emission factor formulas are confusing
or contain math errors that vastly inflate
emission estimates. AGA asserted that the
‘‘[t]he new emissions factor equations W–
30, W–31 and W–32 in the final rule are
confusing. Since these formulas were not
included in the proposed rule, AGA did not
have an opportunity to comment on them’’.
Yes.
New electronic reporting form is not yet available for comment or testing. AGA asserted
that ‘‘[s]takeholders should be given the opportunity to comment and to have access to
the reporting software to perform trial runs.
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Petitioner and date of letter
No. This is being addressed in a separate
package.
EPA should exclude small internal combustion
sources, not just external combustion. AGA
asserted that ‘‘EPA should revise the final
rule to provide a de minimis exemption for
small internal and external combustion
sources at underground storage facilities.’’
Also ‘‘AGA request reconsideration of this
new exclusion for small combustion sources
and revision to include both small internal
and external combustion sources * * *’’.
Yes.
AGA asserted that ‘‘[t]he rule contains conflicting provisions regarding whether emissions from dehydrator units at underground
storage facilities should or should not be reported’’.
No.
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Is this issue addressed in this action?
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TABLE 2—PETITIONS FOR RECONSIDERATION—Continued
Petitioner and date of letter
Issue raised for reconsideration
Is this issue addressed in this action?
AGA asserted that ‘‘EPA did not provide rational explanation for using outdated inaccurate emission factors rather than modern
updated emission factors’’.
AGA asserted that ‘‘[d]efinition of ‘facility’ is
overbroad and confusing.’’ The facility definition referred to here is found in
40 CFR 98.238.
No.
AGA asserted that ‘‘It was arbitrary and capricious for EPA to create a subpart W reporting regulation for a null set—LNG storage
facilities will not exceed the 25,000 ton per
year threshold’’.
No.
AGA asserted that ‘‘It was arbitrary and capricious for EPA to create a subpart W reporting regulation for LNG import and export facilities—which have only minimal methane
leaks’’.
Chesapeake Energy/American Exploration and
Production Council by Letter Dated January
31, 2011.
Yes.
No.
Measurement of Emissions. CEC/AXPC asserted that ‘‘EPA proposed to require costly
measurement and reporting of emissions
from hundreds of thousands of sources.
Commenters asked EPA to adopt a reasonable threshold for measurement, so that
emissions could still be accounted for, but
in a cost-effective way. Commenters recommended using the API Compendium for
that purpose’’.
No.
De minimis emissions from portable equip- Yes.
ment. CEC/AXPC asserted that ‘‘[t]he final
rule likewise fails to adequately support requiring the reporting of de minimis emissions from portable equipment as EPA
proposedEPA asserts a truism that all emissions contribute to sector emissions overall’’.
No.
Compressor Monitoring. CEC/AXPC asserts
that ‘‘[t]he final rule imposes a new obligation to monitor and report that would require
major piping modifications and that would
unduly threaten worker safety’’.
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No. This is being addressed in a separate action (76 FR 37300).
Emissions Manifolded to Common Vents.
CEC/AXPC asserted that the final provisions for centrifugal compressor monitoring
‘‘[n]ot only expands the rule to cover equipment that was not identified in the proposed
rule, but it is also inconsistent and creates
ambiguity for covered sources regarding
what is required’’.
17:00 Sep 08, 2011
No.
Best Available Monitoring Methods.
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Yes.
Dump Valves. CEC/AXPC asserts that ‘‘[t]he
requirement to measure and report emissions from dump valves associated with onshore production storage tanks * * * is a
new and unreasonable ongoing monitoring
and record keeping burden * * *’’.
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Designated Representative. CEC/AXPC requested reconsideration of the designated
representative provisions in the final rule.
No.
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TABLE 2—PETITIONS FOR RECONSIDERATION—Continued
Petitioner and date of letter
Issue raised for reconsideration
Is this issue addressed in this action?
Yes.
Mapping Wells to Fields. CEC/AXPC asserted
that ‘‘EPA has not clarified how reporting
entities are supposed to map wells to a particular ‘field.’ ’’ Also, CEC/AXPC asserted
that ‘‘[w]ithout sufficient clarity regarding
what wells are in a particular field, it is difficult for covered sources to know with certainty what gas composition is considered
representative for each well’’.
Yes.
Definition of Facility for Onshore Petroleum
and Natural Gas Production. CEC/AXPC
asserted that the ‘‘EPA has not provided a
reasoned explanation for why a term other
than ‘facility’ cannot be adopted for Subpart
w (such as ‘Reporting Area’) in order to
avoid unintended confusion and inaccuracies in reporting’’.
No.
Pipeline Quality Natural Gas. CEC/AXPC asserted that ‘‘[t]here is not a clear and unambiguous definition in the final rule for ‘pipeline quality’ natural gas’’.
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Yes.
Gathering Lines and Boosting Stations. CEC/
AXPC asserted that ‘‘EPA noted that the
‘final rule does not require reporting of
emissions from [the] gathering and boosting
segment of the industry.’ Thisis not helpful
and gives industry no clarity regarding
which compressor stations are required to
report’’.
17:00 Sep 08, 2011
Yes.
Onshore Natural Gas Processing Industry
Segment Definition. CEC/AXPC asserted
that ‘‘[a]s presently drafted, the unclear and
inconsistent final provisions render the rule
arbitrary and capricious and contrary to
law.’’ CEC/AXPC further stated concerns
with the definition for onshore natural gas
processing industry segment definition and
where the segment differs from onshore
natural gas transmission industry segment,
and from gathering lines and boosting stations.
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Yes.
Onshore Natural Gas Transmission Compression Industry Segment Definition. CEC/
AXPC asserted that ‘‘[a]s presently drafted,
the unclear and inconsistent final provisions
render the rule arbitrary and capricious and
contrary to law.’’ And ‘‘The term ‘onshore
natural gas transmission compression’
means a stationary combination of compressors that move natural gas at elevated
pressure from production fields or natural
gas processing facilities in transmission
pipelines or into storage. 40 CFR
§ 98.230(a)(4). A transmission compressor
station can include equipment to separate
liquids or dehydrate natural gas Id. However, according to the final rule this source
category does not include gathering lines
and boosting stations’’.
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Excluding Boosting Stations. CEC/AXPC asserted that ‘‘[t]he final rule fails to distinguish between a boosting station, which is
exempt, and an ‘onshore natural gas transmission compression facility’ which must report under the rule’’.
Yes.
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TABLE 2—PETITIONS FOR RECONSIDERATION—Continued
Petitioner and date of letter
Issue raised for reconsideration
Is this issue addressed in this action?
Producing Horizon/formation definition. CEC/
AXPC asserted that ‘‘[t]here is not a clear
and unambiguous definition provided in the
final rule for the term ‘producing horizon/formation’ ’’.
Well testing venting and flaring clarification.
CEC/AXPC asserted that ‘‘[t]he final rule is
unclear regarding the requirement to report
emissions from well testing venting and flaring’’.
Best Available Monitoring Methods .................
No. This is being addressed in a separate action (76 FR 37300).
Yes.
Stuck dump valves to separators/tanks in onshore production operations. API asserted
that ‘‘[t]he new requirement to report emissions from stuck dump valves requires reporters to check all dump valves on a well
site * * * These requirements represent an
administrative burden for reports that was
not contemplated in the proposed rule’’.
No.
Reporting requirements for centrifugal and reciprocating compressor venting at onshore
natural gas processing facilities. API requested EPA to reconsider an asserted expansion of reporting requirements for centrifugal and reciprocating compressor venting at onshore natural gas processing facilities.
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Yes.
Exclusion for ‘small’ internal combustion
sources is needed. API asserted that ‘‘EPA
should extend the exclusion for small external combustion sources to small internal
combustion sources’’.
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Yes.
Blowdown Vent Stacks. CEC/AXPC asserted
that ‘‘[t]he sources that are required to report emissions from blowdown vent stacks
are not clear’’.
17:00 Sep 08, 2011
No.
Pneumatic Devices. CEC/AXPC asserted that
‘‘EPA has not given sufficient consideration
to the burden imposed by requiring that the
bleed rate of each device be determined in
order to count and classify the devices’’.
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Yes.
Associated Gas Venting and Flaring. CEC/
AXPC asserted that ‘‘40 CFR 98.233(m) imposes a requirement to report emissions
from associated gas venting and flaring not
in conjunction with well testing. While this
regulation references 40 CFR 98.233(l),
that definition is unclear. Therefore industry
is left without clarity regarding what emissions are included in ‘associated gas venting and flaring not in conjunction with well
testing’ ’’.
American Petroleum Institute by Letter Dated
January 31, 2011.
Yes.
No.
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TABLE 2—PETITIONS FOR RECONSIDERATION—Continued
Petitioner and date of letter
Issue raised for reconsideration
Is this issue addressed in this action?
Yes.
Separate calculations for subsonic and supersonic flow when both happen during a single completion. API asserted that ‘‘[t]he proposed rule did not include a requirement
that well completions have separate calculations for subsonic and supersonic flow
when both occur during a single completion. The final rule adds this requirement,
which is not technically possible’’.
Yes.
Flow meter requirements. API asserts that
‘‘[t]he final rule adds a requirement at 40
CFR 98.234(b) that all flow meters, composition analyzers and pressure gauges be
operated and calibrated according to the
procedures in Section 98.3(i) of the
MRR * * * API is concerned about the potential unintended consequence following
the addition of stationary source combustion equipment at a well pad at new 40
CFR 98.232(C)(22), which required compliance with 40 CFR 98.233(z)(2)(1)’’.
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Yes.
Portable combustion equipment that cannot
move on roadways under its own power
and drive train that is stationed at a wellhead for less than 30 days in a reporting
year. API asserts that ‘‘[t]he final rule requires reporters to account for this equipment, despite the fact that it is on site for
an extremely short period of time * * * it is
unrealistic to expect reporters to measure
emissions from every piece of portable
combustion equipment that is only onsite
for a matter of days’’.
17:00 Sep 08, 2011
No.
Use of gas composition based on available
sample analysis for reporters without continuous gas composition analyzer. API asserts that ‘‘EPA should resolve the ambiguity created by the current language’’.
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Yes.
Reporting requirements for all venting and
flaring activities in the production source
category. API asserts that ‘‘EPA’s expansion of the reporting obligations in
98.233(m) to include upset or maintenance
gas from producing wells imposes additional and extensive burdens on regulated
parties which was not included in the proposal’’.
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Requirements for flare stack emission associated with onshore oil and gas production.
API asserted that ‘‘[e]missions from flare
stacks associated with onshore oil and gas
production were not included in the Petroleum and Natural Gas production industry
segment in the proposed rule * * * the inclusion of emissions from flare stacks associated with onshore oil and gas production
is duplicative, burdensome, and a potential
source of reporting inaccuracies’’.
Yes.
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TABLE 2—PETITIONS FOR RECONSIDERATION—Continued
Petitioner and date of letter
Issue raised for reconsideration
Is this issue addressed in this action?
No.
Basin level reporting for onshore petroleum
and natural gas production. API asserted
that ‘‘[t]his broad definition of onshore production facility is impractical. Subpart W imposes reporting requirements on over
22,000 entities operating hundreds of thousands of wells and millions of pieces of
equipment scattered over hundreds of thousands of square miles’’.
Yes.
Field level reporting for onshore petroleum
and natural gas production. API asserts that
‘‘[t]his level of reporting is problematic when
applied to new requirements of the final
rule. For the same reasons, it remains
problematic when applied to those requirements in the proposed rule that remain in
the final rule’’.
Yes.
Designated Representative of Subpart W Facility. API asserted that ‘‘[t]he new basinlevel facility definition for onshore petroleum
and natural gas production systems adopted in Subpart W adds unreasonable complexity to several of the existing administrative requirements for the designated representative set forth in 40 CFR 98.4’’.
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Yes.
Floating Production Storage and Offloading
Equipment. API asserted that ‘‘[t]he proposed rule did not include floating production storage and offloading equipment in the
definition of offshore petroleum and natural
gas production. API questions the need for
this addition at 40 CFR 98.230(a)(1)’’.
17:00 Sep 08, 2011
Yes.
Number of plunger lifts and average casing
diameter in inches. API asserted that ‘‘[t]he
final rule adds 40 CFR 98.236(c)(5) requirements to report the number of plunger lifts
and average casing diameter in inches by
field. The difficulty with these additions is
not with the requirement for counting plunger lifts and noting casing diameter, but that
reporting must take place at the field level’’.
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Yes.
Definitions to Industry Categories. API asserted that the ‘‘[a]ltered final rule creates
ambiguity as to whether certain facilities are
included in the production category, excluded as gathering or booster stations, or
included under the gas processing category’’.
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Emission factors for continuous high-bleed,
continuous low-bleed, and intermittent bleed
pneumatic devices. API asserted that
‘‘[a]lthough EPA has provided emission factors in Table W–1A that apply to continuous
high-bleed, continuous low-bleed, and intermittent bleed pneumatic devices, EPA has
not provided guidance on how to classify
pneumatic devices according to these three
categories’’.
Yes.
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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules
TABLE 2—PETITIONS FOR RECONSIDERATION—Continued
Petitioner and date of letter
Issue raised for reconsideration
Is this issue addressed in this action?
Reporting of GHG emissions from leased,
rented, or contracted activities. API asserts
that ‘‘[t]hese requirements create significant
complications. A single well pad may be
owned by one entity, operated by another
entity, lease portable equipment from a
third entity, and have that portable equipment operated by yet another entity. The
rule places the burden of reporting entirely
on the owner of the well or the holders of
the operating permit and makes the designated representatives legally responsible
for the accuracy of the emissions data provided by third parties’’.
Threshold for ‘‘small’’ size units that are exempt from consideration. API asserts that
‘‘[t]he final rule’s threshold of 0.4 MMscf per
day for dehydrator calculations using software and individual reporting is too low’’.
Gas Processors Association by Letter Dates
February 11, 2011.
Partially.
No.
Best Available Monitoring Methods. GPA asserted that ‘‘[s]ubpart W’s best available
monitoring method provisions do not provide reporting entities with adequate time to
ensure compliance with the final rule’’.
Compressor venting monitoring requirements.
GPA asserted that ‘‘[c]urrent compressor
venting monitoring requirements are overly
burdensome and present significant safety
and operational process concerns to reporting entities’’.
No. This is being addressed in a separate action (76 FR 37300).
No.
Use of the terms ‘‘gathering lines’’ and
‘‘booster stations’’ not being defined in final
rule. GPA asserted that ‘‘[t]he terms ‘gathering lines’ and ‘booster stations’ are not
defined in the final rule, nor is sufficient detail provided regarding the definition of ‘gas
processing facility.’ ’’ GPA further asserted
that ‘‘[a]bsent such definitions and clarifications, there will be substantial confusion as
to which facilities are required to report
emissions data’’.
Facility definition for onshore petroleum and
natural gas production. GPA asserted ‘‘[t]he
definition of a facility in Subpart W differs
from the definition of a facility provided in
all other applicable regulations under the
Clean Air Act. This inconsistency will create
unnecessary confusion among related programs and is not necessary or justified’’.
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Interstate Natural Gas Association of America ..
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No.
Terms in Subpart W. Southwest Gas Corporation asserted that ‘‘[t]he USEPA’s final rule
fails to provide clear definitions that can be
used uniformly throughout the natural gas
distribution industry’’.
Yes.
Errors in Calculations. Southwest Gas Corporation asserted that the USEPA published errors in equations in 40 CFR
98.233, namely equation W–32.
Southwest Gas Corporation by Letter Dated
January 31, 2011.
Yes.
Yes.
Best Available Monitoring Methods .................
No. This is being addressed in a separate action (76 FR 37300).
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56019
TABLE 2—PETITIONS FOR RECONSIDERATION—Continued
Petitioner and date of letter
Issue raised for reconsideration
Technical Provisions in Subpart W. INGAA
asserted that ‘‘[n]umerous technical elements of Subpart W remain unclear, confusing, overly complicated or conflicting’’.
Is this issue addressed in this action?
Partially.
INGAA petitioned EPA to reconsider the de- Yes.
fault gas compositions and requested the
use of separate default gas compositions
for methane and CO2 for vented and fugitive emissions for the natural gas transmission compression and storage segments.
Yes.
INGAA requested that EPA reconsider provisions for monitoring emissions from centrifugal and reciprocating compressors and
to consider including clarifications to rule
text.
No.
INGAA requested EPA to reconsider provisions related to monitoring and QA/QC requirements including provisions for the alternative work practice.
Yes.
INGAA requested EPA to reconsider missing
data provisions and broaden access.
No.
INGAA requested EPA to reconsider provisions as stated in 40 CFR 98.236 and requested several clarifications to final text.
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Yes.
INGAA requested that EPA to reconsider provisions related to flaring.
17:00 Sep 08, 2011
Yes.
INGAA requested EPA to reconsider the provisions in the rule for emissions from blowdown vent stacks and to include an additional equation to allow facilities who currently track emissions by equipment type to
submit emission to EPA in that manner.
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Yes.
INGAA requested EPA to reconsider the provisions in the rule related to blowdown vent
stacks and requested a reconsideration of
those provisions.
The proposed amendments in this
action include technical corrections and
clarifications to ensure that the 2010
final rule is implemented as intended.
Amendments to subparts I and W are
also being proposed in other actions.
Please see 76 FR 47392 (Herein referred
to as the ‘‘technical corrections rule’’)
and 76 FR 37300. This proposal
complements these proposed rules and
is not intended to duplicate or replace
those proposed amendments. In limited
cases, an amendment to subpart W was
Yes.
INGAA requested EPA to reconsider the provisions in the final rule for determining the
type of pneumatic device at a facility.
INGAA requested EPA to consider the option of using engineering estimates to determine the type of pneumatic devices.
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INGAA petitioned EPA to reconsider minor
clarifications to 40 CFR 98.233(t), (u), and
(v) for clarity.
Partially.
proposed in the technical corrections
rule and we are proposing to amend it
further in this action. Additional
proposed amendments were determined
to be necessary to address questions and
issues raised by stakeholders since
development of the proposal of the
technical corrections rule. Where
amendments have been made to the
same paragraph in this action and in the
technical corrections rule, the proposal
below provides the complete proposed
amendatory language for how EPA
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proposes to amend the provision. We
are seeking public comment only on the
issues specifically identified in this
proposal for the identified subparts. We
will not respond to any comments
addressing other aspects of part 98 or
any other related rulemakings.
EPA promulgated confidentiality
determinations for certain data elements
required to be reported under part 98
and finalized amendments to the
Special Rules Governing Certain
Information Obtained Under the Clean
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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules
Air Act, which authorizes EPA to
release or withhold as confidential
reported data according to the
confidentiality determinations for such
data without taking further procedural
steps (76 FR 30782, May 26, 2011
hereinafter referred to as the ‘‘May 26,
2011 Final CBI Rule’’). That notice
addressed reporting of data elements in
34 subparts that were determined not to
be inputs to emission equations and
therefore were not proposed to have
their reporting deadline deferred. That
rule did not make confidentiality
determinations for eight subparts,
including subpart W, for which
reporting requirements were finalized
after publication of the July 7, 2010 CBI
proposal and July 20, 2010
supplemental CBI proposal.
EPA is planning to address the
confidentiality determinations for the
data elements in subpart W in a separate
action. EPA plans to issue and finalize
the confidentiality determinations for
subpart W prior to the 2012 reporting
deadline.
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C. Legal Authority
EPA is proposing these rule
amendments under its existing CAA
authority, specifically authorities
provided in section 114 of the CAA.
As stated in the preamble to the 2009
Final Greenhouse Gas Reporting Rule
(part 98) (74 FR 56260, October 30,
2009), CAA section 114 provides EPA
broad authority to require the
information proposed to be gathered by
this rule because such data would
inform and are relevant to EPA’s
carrying out a wide variety of CAA
provisions. As discussed in the
preamble to the initial proposed rule (74
FR 16448, April 10, 2009), section
114(a)(1) of the CAA authorizes the
Administrator to require emissions
sources, persons subject to the CAA,
manufacturers of control or process
equipment, or persons whom the
Administrator believes may have
necessary information to monitor and
report emissions and provide such other
information the Administrator requests
for the purposes of carrying out any
provision of the CAA. For further
information about EPA’s legal authority,
see the preambles to the proposed and
2009 final part 981.1
D. How would these amendments apply
to 2012 reports?
EPA is planning to address the
comments on these proposed
amendments and publish the final
amendments before the end of 2011.
1 74 FR 16448 (April 10, 2009) and 74 FR 56260
(October 30, 2009).
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Therefore, for subpart W, reporters
would be expected to calculate
emissions and other relevant data for
the reports that are submitted in 2012
using part 98, as amended by this rule,
as finalized. We have determined that it
is feasible for the sources to implement
these changes for the 2011 reporting
year since the proposed revisions
primarily provide additional
clarifications or flexibility regarding the
existing regulatory requirements,
generally do not affect the type of
information that must be collected, and
do not substantially affect how
emissions are calculated.
For amendments being proposed
today to subpart I, EPA is requesting
comment on whether to require
electronics manufacturing facilities to
estimate and report 2011 emissions in
2012 for HTFs that would be newly
included in the scope of subpart I if
today’s proposed rule amendments were
finalized.
For facilities subject to the provisions
in 40 CFR part 98—subpart W, many
proposed revisions simply provide
additional information and clarity on
existing requirements. For instance, we
are proposing to amend 40 CFR
98.1(c)(1) to clarify that for onshore
petroleum and natural gas facilities, the
references in 40 CFR 98.4 that apply to
owner(s) and operator(s) refer to the
onshore petroleum and natural gas
production owner or operator, as
defined in 40 CFR 98.238. Therefore, we
are proposing to explicitly make this
clarification in 40 CFR 98.1 (Purpose
and Scope). The proposed amendment
does not change the burden of the 2010
final rule, and in fact, EPA believes that
it alleviates concerns expressed by
industry that the designated
representative provisions are overly
burdensome.
Some of the proposed amendments
for subpart W provide greater flexibility
or simplified calculation methods for
certain facilities. For example, we are
proposing to amend 40 CFR 98.233(i) to
provide an additional option to
calculate GHG emissions from
blowdown vent stacks. Specifically, we
are proposing to allow reporters the
option of tracking blowdowns by each
occurrence for the same blowdown
volume, consistent with current practice
at some facilities, whereas in the final
rule, reporters were required to track
total blowdown vent emissions from all
occurrences for the same blowdown
volume in a year.
Further, some proposed amendments
for subpart W are to the data reporting
requirements to provide additional
clarity on which GHG emissions have to
be reported and at which level of
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aggregation. For example, in 40 CFR
98.236 EPA is proposing to clarify
where ‘‘vented’’ emissions should be
reported separately from ‘‘flared’’
emissions and that reporting of CH4,
CO2, and N2O emissions should be
reported individually for each source
type in CO2e. We have concluded that
amendments such as these could be
implemented for the reports submitted
to EPA in 2012 because the proposed
changes are, with one exception,
consistent with the calculation
methodologies already in part 98 and
the owners or operators are not required
to actually report until March 2012,2
several months after we expect this
proposal to be finalized.
The one exception where both the
underlying calculation requirements
and reporting requirements in subpart
W are proposed to be changed is related
to the requirements for field level
reporting for four emissions sources in
the onshore petroleum and natural gas
production segment. As described
further in Section II.C of this preamble,
we are proposing to amend the
calculation and reporting requirements
for well completions and well
workovers, well venting for liquids
unloading, and storage tanks to require
calculations and reporting to be
undertaken at the county level and by
geologic formation (by formation type).
EPA believes that the proposed
amendments for subpart W can still be
implemented for the 2011 reporting year
for a couple of reasons. First, these
amendments are being proposed based
on industry concern about associating
wells with a particular ‘‘field’’ given
possible ambiguity surrounding EIA
field designations. While EPA maintains
its belief that reporting by the field is a
viable and workable option, however,
EPA does acknowledge that counties are
readily identifiable, and provide clear
geographic boundaries. AS a result,
implementation of this alternative
method should be straightforward for
facilities. Second, if facilities are
concerned about their ability to
implement these provisions for the 2011
reporting year, they may use best
available monitoring methods (BAMM)
pursuant to 40 CFR 98.234(f). In the
event that facilities have already taken
a measurement at the field level, they
could still use those same
measurements for the 2011 reporting
year, but apply them to the sub-basin
categories based on BAMM.
2 EPA has proposed to extend the 2012 reporting
deadline for source categories first required to begin
data collection in 2011 from March 31, 2012 to
September 28, 2012. Please see the technical
corrections rule previously referenced.
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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules
Other amendments to subpart W are
proposed to address issues identified as
a result of working with the affected
facilities during rule implementation.
These proposed revisions provide
additional flexibility to the sources, or
reduce the reporting burden. For
example, the 2010 final rule required
leak detection for emissions from dump
valves in transportation storage tanks,
and if a leak is detected, measurement
of the quantity of emissions would be
required. However, industry raised
questions as to whether a facility could
forgo leak detection and directly
measure the emissions from leaking
dump valves under the natural gas
transmission industry segment. This
action provides this additional
flexibility, because it reduces burden
without compromising the quality of the
data reported to EPA.
We are also proposing corrections to
terms and definitions in certain
equations in subpart W. For example,
we are proposing to amend the
calculation for estimating CO2 emissions
from acid gas removal vents in Equation
W–4. Although the existing equation is
appropriate when the amount of CO2 in
gas is relatively low, such as 1 percent,
the error rate in the estimate increases
significantly as the amount of CO2 in gas
increases. Therefore, EPA is proposing a
new equation, which uses the exact
same input parameters and thus will not
result in any additional burden to
reporters, but will improve the quality
of the information submitted to EPA.
These clarifications do not result in
additional requirements; therefore, we
have concluded that reporters can
follow part 98, as amended, in
submitting their first reports to EPA in
2012.
Finally, we are proposing other
technical corrections in subpart W that
have no impact on a facility’s data
collection efforts in 2011. For example,
we are proposing to correct cross
references in equations and change
incorrect use of the term ‘‘facility’’ in
the definition of the source category.
In summary, these proposed
amendments to subpart W generally
would not require any additional
monitoring or information collection
above what is already included in part
98. Therefore, we expect that sources
can use the same information that they
have been collecting under the current
version of part 98 to calculate and report
GHG emissions for 2011 and submit
reports in 2012 under Part 98, as
amended by this action.
We seek comment on whether it is
appropriate to implement these
amendments and incorporate the
requirements in the data reported to
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EPA by March 31, 2012. Further, we
seek comment on whether there are
specific provisions in subpart W for
which this timeline may not be feasible
or appropriate due to the nature of the
proposed changes or the way in which
data have been collected thus far in
2011. We request that commenters
provide specific examples of how the
proposed implementation schedule
would or would not work.
II. Technical Corrections and Other
Amendments
Following promulgation of the 2010
final subpart I and subpart W, EPA has
identified errors in the regulatory
language that we are now proposing to
correct. These issues were identified as
a result of working with affected
industries to implement rules. We have
also identified certain rule provisions
that should be amended to provide
greater clarity. For additional
background information on the
questions raised, please refer to the
Technical Support Document for this
proposed rulemaking available in the
docket to this rulemaking (EPA–HQ–
OAR–2011–0512).
The amendments we are now
proposing include the following types of
changes:
• Changes to correct cross references
within the subparts.
• Additional information to allow
reporters to better or more fully understand
compliance obligations in a specific
provision.
• Corrections to terms and definitions in
certain equations.
• Corrections to data reporting
requirements so that they more closely
conform to the information used to perform
emission calculations.
• Other amendments related to certain
issues identified as a result of working with
the affected sources during rule
implementation and outreach.
We are seeking public comment only
on the issues specifically identified in
this notice for the identified subparts.
We will not respond to any comments
addressing other aspects of part 98 or
any other related rulemakings.
A. Subpart A—General Provisions
Designated Representative. Two
industry associations raised concerns
about the provisions related to
determination of the designated
representative in the context of how the
subpart A definition would affect
subpart W reporters. Through a letter
dated January 31, 2011, the American
Petroleum Institute (API) encouraged
EPA to reconsider the implications on
owners and operators in the onshore
petroleum and natural gas production
segment in the context of the provisions
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56021
in 40 CFR 98.4. Specifically, API was
concerned that given the definition of
‘‘facility’’ for onshore petroleum and
natural gas production, coupled with
the relatively complex ownership
structures in the industry (as compared
to other subparts covered under part
98), EPA should modify several
requirements in 40 CFR 98.4
(authorization and responsibilities of
the designated representative). API
encouraged EPA to eliminate the
requirement of notifying co-owners of
the designated representative selection
(40 CFR 98.4(i)(4)(iv)), eliminate the
requirement for listing of co-owners as
part of the certificate of representation
(40 CFR 98.4(i)(3), and eliminate the
requirement for new certificates of
representation following ownership
changes (40 CFR 98.4(h)).
Similar concerns were expressed in a
letter from Chesapeake Energy
Corporation (CEC) and the American
Exploration & Production Council
(AXPC) dated January 31, 2011. CEC/
AXPC was also concerned that the
current operational reality in the
onshore petroleum and natural gas
industry would make it difficult for a
designated representative to make the
certifications required in 40 CFR
98.4(i)(4). Specifically, CEC/AXPC was
concerned about attesting to the fact that
the designated representative was
selected by an agreement binding on the
owners and operators of the facility, that
all owners and operators are fully bound
by representations of the designated
representative, that the owners and
operators of the facility would be bound
by any order issued to the designated
representative by the administrator or a
court, and that the designated
representative has given written notice
of their selection and of the agreement
by which the designated was selected by
the owner and operator of the facility.
EPA maintains, as described in the
October 2009 final rule (74 FR 56357),
that the high level of public interest in
the data collected under this rule, as
well as its importance to future policy,
warrants establishment, by rule
pursuant to CAA sections 114, 208, and
301(a)(1), of a high standard for data
quality and consistency and a high level
of accountability for reported data,
which will help ensure that the data
quality and consistency standard is met.
The designated representative is the
primary point of contact between the
owner or operator and the EPA.
Therefore, it is important that EPA
knows who the designated
representative is, and that the
designated representative has made the
necessary certification statements.
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EPA recognizes that the onshore
petroleum and natural gas industry has
a different organizational structure and
operational realities than other
industries subject to part 98. As such, in
the 2010 final rule for subpart W (75 FR
74512), EPA specifically defined who is
an onshore petroleum and natural gas
production owner or operator. Under 40
CFR 98.238, onshore petroleum and
natural gas production owner or
operator means ‘‘the person or entity
who holds the permit to operate
petroleum and natural gas wells on the
drilling permit or an operating permit
where no drilling permit is issued,
which operates an onshore petroleum
and/or natural gas production facility
(as described in 40 CFR 98.230(a)(2).
Where petroleum and natural gas wells
operate without a drilling or operating
permit, the person or entity that pays
the state or federal business income
taxes is considered the owner or
operator.’’ It was EPA’s intent that this
definition of owner and operator apply
not only in subpart W, but also in
subpart A for the obligations of Subpart
W ‘‘owners and operators’’ (e.g., those
related to identifying the designated
representative and requirement for who
must be included on the Certificate of
Representation (COR)).
EPA acknowledges that the final
subpart W rule is not clear, and it could
be interpreted that all ‘‘owners’’ and all
‘‘operators’’, as defined in 40 CFR 98.6,
are required to identify the designated
representative for the facility and be
held accountable for all requirements
under 40 CFR 98.4. EPA never intended
that 4,000 owners and operators, e.g.,
would have to be listed on the COR, an
example provided by API in their
Petition for Reconsideration. Rather,
EPA intended that for onshore
petroleum and natural gas facilities, the
references in 40 CFR 98.4 that apply to
owner(s) and operator(s) refer to the
onshore petroleum and natural gas
production operator, as defined in 40
CFR 98.238. Therefore, we are
proposing to explicitly make this
clarification in 40 CFR 98.1 (Purpose
and Scope).
Definitions: We are proposing
amendments to the definition of
continuous bleed pneumatic device in
40 CFR 98.6 to clarify that continuous
bleed devices supply gas to process
control devices; these are not
necessarily measurement devices, as
suggested by the 2010 final rule.
Similarly, we are proposing to amend
the definition of an intermittent bleed
pneumatic device to clarify that these
devices automatically maintain the
process conditions and that the devices
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discharge all or a portion of the full
volume of the actuator intermittently.
Incorporation by Reference (IBR).
Finally we are also proposing to amend
40 CFR 98.7 (What standardized
methods are incorporated by reference
into this part?) to remove paragraph 40
CFR 98.7(q). As elaborated further
below, we are proposing to change the
calculation and reporting requirements
for specific equipment in the onshore
petroleum and natural gas production
segment from a ‘‘field’’ level, to a subbasin category. Consistent with this
proposed amendment, there is no longer
a need to incorporate the Energy
Information Administration (EIA) Oil
and Gas Field Code Master List, 2008.
B. Subpart I—Electronics Manufacturing
In this action, EPA is proposing to
amend the provisions contained within
subpart I to calculate and report
emissions from fluorinated GHGs used
as HTFs. First, EPA is proposing to
amend the definition of HTFs in 40 CFR
98.98, to include all fluorocarbons used
as HTFs in the electronics
manufacturing industry. The definition
of HTFs incorporates the term
‘‘fluorinated GHGs’’ as defined in the
general provisions of the greenhouse gas
reporting rule (subpart A) at 40 CFR
98.6. The definition of ‘‘fluorinated
greenhouse gas’’ in subpart A excludes
‘‘substances with vapor pressures of less
than 1 mm of Hg absolute at 25 degrees
C.’’ EPA is proposing to specify that the
vapor pressure cutoff clause in the
subpart A definition of fluorinated
GHGs does not apply to fluorinated
HTFs in subpart I. As a result, emissions
of fluorinated HTFs with vapor
pressures of less than 1 mm of Hg
absolute at 25 degrees C would no
longer be excluded from reporting under
subpart I. Second, also in the definition
of HTFs, EPA is proposing to add the
phrase ‘‘but not limited to’’ before
listing examples of fluorinated HTFs to
ensure that potential future alternatives
are covered. Third, EPA is proposing to
remove the last sentence in the
definition (‘‘Electronics manufacturers
may also use these same fluorinated
chemicals to clean substrate surfaces or
other parts’’) and move the concept of
using HTFs to clean substrate surfaces
or other parts to the first sentence.
Fourth, EPA is proposing minor
revisions throughout the subpart I
regulatory text to clarify the use of the
terms fluorinated GHGs and fluorinated
HTFs (e.g., referring to fluorinated HTFs
rather than fluorinated GHGs used as
HTFs). And last, in 40 CFR 98.92(a)(5),
under GHGs to report, EPA is proposing
to revise the clause ‘‘fluorinated GHG
emitted from heat transfer use’’ to read
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‘‘emissions of fluorinated heat transfer
fluids.’’
EPA published Subpart I: Electronics
Manufacturing of part 98 on December
1, 2010 (75 FR 74774). This subpart
requires monitoring and reporting of
GHG emissions from electronics
manufacturing. Included in the
December 1, 2010 final rule are
provisions that require electronics
manufacturing facilities to calculate and
report emissions from the use of
fluorinated HTFs. Pursuant to 40 CFR
98.93(h), electronics manufacturing
facilities must calculate HTF emissions
using a mass balance approach based
on: the beginning and end of year
inventories; acquisitions and
disbursements of HTFs; and the
nameplate capacities of newly installed
and removed equipment containing
HTFs. For purposes of subpart I, HTFs
are defined as the following:
‘‘fluorinated GHGs used for temperature
control, device testing, and soldering in
certain types of electronic
manufacturing production processes.
HTFs used in the electronics sector
include perfluoropolyethers,
perfluoroalkanes, perfluoroethers,
tertiary perfluoroamines, and
perfluorocyclic ethers. Electronics
manufacturers may also use these same
fluorinated chemicals to clean substrate
surfaces and other parts’’ (40 CFR
98.98).
The definition of HTFs in subpart I
includes the term ‘‘fluorinated
greenhouse gases’’ (fluorinated GHGs),
which is defined in subpart A: General
Provisions (40 CFR 98.6). EPA initially
proposed a definition of fluorinated
GHGs in the April 2009 proposed rule
for part 98 (74 FR 16448) as follows:
‘‘Fluorinated GHG means sulfur
hexafluoride (SF6), nitrogen trifluoride
(NF3), and any fluorocarbon except for
controlled substances as defined at 40
CFR part 82, subpart A. In addition to
(SF6) and NF3, ‘‘fluorinated GHG’’
includes but is not limited to any
hydrofluorocarbon, any
perfluorocarbon, any fully fluorinated
linear, branched or cyclic alkane, ether,
tertiary amine or aminoether, any
perfluoropolyether, and any
hydrofluoropolyether.’’
EPA received numerous comments on
the definition, particularly in regards to
Subpart OO–Suppliers of Industrial
GHGs. For example, some commenters
argued that the proposed definition of
fluorinated GHGs was too broad because
it would include nonvolatile materials
that could not be emitted to the
atmosphere. More specifically, one
commenter suggested establishing a
lower vapor pressure limit for
fluorinated GHGs (heat transfer fluids)
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of 400 Pa (0.004 bar, or three mm Hg
absolute) at 25 C.3
In response to comments, in the 2009
final part 98 (74 FR 56260), EPA
finalized the following definition of
fluorinated GHG: ‘‘Fluorinated GHG
means sulfur hexafluoride (SF6),
nitrogen trifluoride (NF3), and any
fluorocarbon except for controlled
substances as defined at 40 CFR part 82,
subpart A and substances with vapor
pressures of less than 1 mm of Hg
absolute at 25 degrees C. With these
exceptions, ‘‘fluorinated GHG’’ includes
but is not limited to any
hydrofluorocarbon, any
perfluorocarbon, any fully fluorinated
linear, branched or cyclic alkane, ether,
tertiary amine or aminoether, any
perfluoropolyether, and any
hydrofluoropolyether.’’ As EPA stated
in the preamble to the final rule, ‘‘This
modification ensures that non-volatile
fluorocarbons such as fluoropolymers
are excluded from reporting
requirements, while requiring reporting
of fluorocarbons (as well as SF6 and
NF3) that could reasonably be expected
to be emitted to the atmosphere’’ (74 FR
56348, October 30, 2009).
EPA proposed the subpart I definition
for HTFs, which included the term
‘‘fluorinated GHG,’’ in an April 12, 2010
Federal Register notice (75 FR 18652).
In a December 1, 2010 final rule
‘‘Mandatory Reporting of Greenhouse
Gases: Additional Sources of
Fluorinated GHGs’’ (75 FR 74775), EPA
finalized a definition for HTFs that was
substantially similar to the definition in
the April 2010 proposed rule.
Following publication of the final
rule, 3M Company (3M) sought
reconsideration of the reporting
requirements for fluorinated GHGs used
as HTFs under subpart I. Specifically, in
its Petition for Reconsideration dated
January 28, 2011 (available in docket
EPA–HQ–OAR–2009–0927), 3M stated
that ‘‘* * * as currently written the
reporting requirements for heat transfer
fluids will exclude a significant portion
of fluorinated GHGs used as heat
transfer fluids. Thus, the GHG emissions
associated with heat transfer fluids will
not be accurately reported under the
rule.’’ Further, 3M stated, ‘‘By tying the
reporting requirements for heat transfer
fluids to the definition of a fluorinated
GHG under § 98.6 in Subpart A, the
scope of Subpart I’s reporting
3 For more information on comments and
responses, please see the preamble to the final rule
Mandatory Reporting of Greenhouse Gases (74 FFR
56348), and the Response to Public Comment on
subpart OO (‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public Comments, subpart
OO: Suppliers of Industrial GHGs’’ available in
docket, EPA–HQ–OAR–2008–0508.)
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requirements are limited to those heat
transfer fluids that have vapor pressures
of > 1 mmHg at 25 degrees C. Although
3M understands the reasons behind the
vapor pressure threshold in the general
definition of a fluorinated GHG, the
same rationale should not apply to heat
transfer fluids. Heat transfer fluids are
used at elevated temperatures and
pressures, and as a result the vapor
pressure of these materials at 1 mm Hg
absolute T 25 degrees C is not
predicative of emissions. Heat transfer
fluids are used through a broad range of
boiling points and are routinely lost
from systems primarily through
mechanical leaks but also from
evaporative loss. Once emitted from a
system, the fate of heat transfer fluids is
primarily the atmosphere.’’
In addition to the concern that the
rule will result in ‘‘dramatic under
reporting of heat transfer fluid use and
emissions,’’ 3M also raised the concern
that ‘‘although all the heat transfer
fluids that have relatively low global
warming potentials will be required to
be reported as GHGs, a substantial
percentage of heat transfer fluids that
have global warming potentials in the
range of 10,000 times that of CO2 will
be exempt from reporting
requirements.’’ Consequently, 3M
argued, ‘‘the rule will likely lead to a
migration toward use of exempt
compounds and an increase in GHG
emissions from the sector.’’
To address the problem, 3M suggested
that subpart I should be amended to
specify that for reporting requirements
under subpart I, the vapor pressure
cutoff in the general definition of
fluorinated GHG does not apply to
HTFs.
In finalizing the HTF provisions in
subpart I, EPA did not intend to exclude
a significant portion of fluorocarbon
HTFs that can enter the atmosphere; any
such exclusion was inadvertent. Given
the high temperatures in which HTFs
may be used, EPA believes that such
fluids are able to enter the atmosphere
even when their vapor pressures at 25
degrees C (77 degrees F) are low. This
is because the vapor pressures of
substances increase as their
temperatures increase, and HTFs with
low vapor pressures are likely to be
used in high-temperature applications.4
4 HTFs are selected for particular applications
based on their viscosities within operating
temperature ranges and/or their boiling points. For
example, for liquid phase applications (e.g., some
cooling applications) HTFs are selected that have
boiling points above the operating temperature
range and low viscosities at the lower operating
temperatures. As temperature decreases, viscosity
increases. Low viscosities are more desirable
because they will provide good heat transfer and
will be easily pumped. For higher temperature
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(Vapor pressure is an indicator of the
rapidity with which a substance
evaporates.) For example, an HTF with
a vapor pressure of about 0.2 mm Hg at
25 degrees C might be used at a
temperature of 140 degrees C for heat
transfer applications, where it may have
a vapor pressure of over 80 mm Hg.
Similarly, an HTF with a vapor pressure
of about 0.1 mm Hg at 25 degrees C
might be used for vapor phase soldering
at a temperature above its boiling point.
Under these conditions, all of the
material is in the vapor phase.
Supporting technical information is
available in the docket (EPA–HQ–OAR–
2011–0512).
EPA understands that at any
particular temperature, an HTF with a
low vapor pressure at 25 degrees C is
likely to evaporate more slowly than an
HTF with a higher vapor pressure at 25
degrees C. Nevertheless, if the
temperature is high, evaporation will
occur.
EPA views data on emissions of HTFs
as an important component in
improving future efforts to characterize
GHG emissions from the electronics
manufacturing sector. EPA believes that
the changes being proposed today will
ensure that all fluorinated HTFs used in
electronics manufacturing are
appropriately monitored and reported
under subpart I.
In this action, EPA is proposing that
the definition of HTFs in subpart I be
revised to read as follows: ‘‘Fluorinated
heat transfer fluids means fluorinated
GHGs used for temperature control,
device testing, cleaning substrate
surfaces and other parts, and soldering
in certain types of electronics
manufacturing production processes.
For fluorinated heat transfer fluids
under this subpart I, the lower vapor
pressure limit of 1 mm of Hg in absolute
at 25 degrees C in the definition of
‘‘fluorinated greenhouse gas’’ in 40 CFR
98.6 shall not apply. Fluorinated heat
transfer fluids used in the electronics
manufacturing sector include, but are
not limited to, perfluoropolyethers,
perfluoroalkanes, perfluoroethers,
tertiary perfluoroamines, and
perfluorocyclic ethers.’’
The effect of making the vapor
pressure cut-off portion of the definition
of fluorinated GHGs inapplicable to
fluorinated HTFs under subpart I would
be to subject emissions from fluorinated
HTFs that have vapor pressures less
than one mm of Hg absolute at 25
applications, such as vapor phase soldering, HTFs
with low vapor pressures—at room temperature
(high boiling points) are generally selected. (See,
e.g., ‘‘Fluorochemicals in Heat Transfer
Applications: Frequently Asked Questions,’’ 3M,
available in the docket for this rulemaking.)
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degrees C to the reporting requirements.
Consequently, EPA would receive
valuable emissions information on the
full range of volatile fluorinated HTFs
used in electronics manufacturing.
The purpose of the Mandatory
Reporting Rule is to collect accurate
facility-specific GHG emissions data for
use in developing future GHG policies
and programs. For this reason, EPA
believes that the definition of HTFs
being proposed today is prudent and
appropriate because it will provide EPA
with comprehensive information on
emissions of fluorinated HTFs.
Considering the simple mass balance
methodology required for reporting
emissions of fluorinated HTFs in
subpart I, the potential value of this
information justifies a comprehensive
definition. If some HTFs (or HTFs in
some currently included applications)
are found to have very low emission
rates, this information will itself be
valuable for informing future GHG
policies. However, given that HTFs are
capable of entering the atmosphere at
the temperatures where they are used,
any conclusion that the emissions of
some HTFs are low must be supported
by actual measurements.
EPA considered including a modified
vapor pressure limit in the proposed
definition of HTF. One approach we
considered was to adopt a vapor
pressure limit associated with a
particular temperature higher than 25
degrees C. The goal of such a limit
would be to require reporting of those
HTFs that may readily enter the vapor
phase in their current and potential
future applications. However, we
believe that today’s proposed,
application-based definition achieves
this goal more simply and effectively
than would a definition that includes a
vapor pressure limit associated with a
particular temperature higher than 25
degrees C. First, given the breadth of
conditions under which HTFs are used
currently in the electronics industry, as
well as the rapidity of technological
change within this industry, it would be
difficult to specify an appropriate
upper-limit temperature to which to
link the vapor pressure. Some
applications occur at very high
temperatures, and those temperatures
could conceivably rise in the future.
Second, such a limit, if not linked to
particular HTF applications, could
include fluorinated chemicals that are
used exclusively in low-temperature
applications where they would not
quickly enter the atmosphere if released,
such as certain lubricants or oils. Third,
the major application of HTFs is for
process cooling. In this application, as
discussed above, HTFs with lower vapor
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pressures at a particular temperature are
likely to be used at higher temperatures.
This is a systematic relationship that
almost guarantees that the HTF will be
capable of volatilizing at the
temperature of use. Similar
relationships are likely to hold in other
applications where viscosity or boiling
point is a concern, e.g., thermal shock
testing. Finally, other applications, such
as substrate cleaning or vapor phase
soldering, occur when the material is in
the vapor phase. Any upper-bound
temperature linked to a vapor pressure
would have to fall above the
temperatures where vapor phase
soldering occurs. The proposed
definition achieves the same goal much
more directly by including the
applications ‘‘soldering,’’ ‘‘temperature
control,’’ ‘‘device testing,’’ and
‘‘cleaning substrate surfaces.’’
Another approach we considered was
to require reporting only of HTFs that
achieve a particular vapor pressure (e.g.,
1 mm Hg absolute) at their maximum
temperature of use, where the maximum
temperature of use could vary from
facility to facility or even application to
application within a facility. This
approach would explicitly focus
monitoring and reporting on those HTFs
and applications where volatilization
could occur. However, because the
coverage of particular chemicals would
depend on their maximum temperature
of use within a particular facility or
application, this approach would be
significantly more difficult to
implement and enforce than the
proposed, application-based definition.
Facilities would be required to
investigate the temperatures at which
each HTF is used and to distinguish
between low- and high-temperature
applications of the same HTF in
developing emissions estimates. The
proposed approach, in contrast, would
clearly define the applicability of the
rule and would enable facilities (and
EPA) to rely on facility-wide massbalances to estimate emissions of
particular chemicals.
EPA does not intend for its definition
of HTFs to include greases or lubricants
such as those used in vacuum pump
applications because such applications
do not typically occur at temperatures at
which the lubricants would volatilize.
EPA does not believe that the current or
proposed definitions include such
lubricants. However, EPA requests
comment on whether the definition
should be amended to explicitly
exclude lubrication or other
applications. To address situations in
which a particular chemical may be
used in both HTF and non-HTF
applications, EPA also requests
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comment on whether we should give
reporters flexibility to report under 40
CFR 98.93(h) either a chemical’s
emissions from all applications or its
emissions from only the applications
included in the HTF definition. This
would give facilities the option to avoid
maintaining a separate supply of the
chemical for purposes of tracking HTF
emissions, as would otherwise be
required for the mass-balance
calculation. Emissions from the nonHTF applications would presumably
make up a small fraction of the total.
The narrow exception to the vapor
pressure cutoff would only apply to
fluorinated HTFs used in the electronics
manufacturing industry; EPA continues
to believe that the vapor pressure cutoff
is appropriate to maintain in the
definition of fluorinated GHG in 40 CFR
82 subpart A (e.g., for purposes of the
industrial gas supply provisions at
subpart OO). EPA is not aware of other
fluorocarbon applications in which the
vapor pressure of the fluorocarbon falls
below 1 millimeter of Hg at 25 degrees
C but typically rises significantly above
it at the temperature of use.
In addition, EPA is also proposing
four other minor amendments to the
regulatory text related to fluorinated
HTFs. First, in the definition of HTF
(40 CFR 98.98), EPA is proposing to add
the phrase ‘‘but not limited to’’ before
listing examples of fluorinated HTFs.
Electronics manufacturing is an
innovative and quickly evolving
industry in which new chemicals are
frequently adopted. EPA is proposing
this change to ensure that potential
future alternatives are covered. Second,
also in the definition of HTFs (40 CFR
98.98), EPA is proposing to delete the
last sentence (‘‘Electronics
manufacturers may also use these same
fluorinated chemicals to clean substrate
surfaces or other parts’’) and move the
concept of cleaning substrates surfaces
or other parts to the first sentence. EPA
is proposing this change to improve
readability of the definition. Third, EPA
is proposing minor revisions throughout
the subpart I regulatory text to clarify
the use of the terms fluorinated GHGs
and fluorinated HTFs (e.g., referring to
fluorinated HTFs rather than fluorinated
GHGs used as HTFs). For example, in
instances where EPA used the term
‘‘fluorinated GHG used as heat transfer
fluids,’’ EPA is proposing to use
‘‘fluorinated heat transfer fluids.’’
Where EPA refers to HTFs, EPA does
not intend the full definition of
fluorinated GHGs (as defined in subpart
A) to apply. And last, in 40 CFR
98.92(a)(5), under GHGs to report, EPA
is proposing to revise the clause
‘‘fluorinated GHG emitted from heat
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transfer use’’ to read ‘‘emissions of
fluorinated heat transfer fluids.’’ EPA is
proposing this change to clarify that
emissions of fluorinated HTFs, not just
fluorinated GHGs, are required to be
reported under subpart I. In addition,
EPA is proposing the change to clarify
the Agency’s intention that emissions
from HTFs can occur through all phases
of the equipment’s lifetime, including
installation, use, servicing, and
disposal. Under subpart I, all of those
emissions of HTFs should be calculated
and reported.
EPA does not anticipate an increase in
burden resulting from these proposed
changes because this action is clarifying
the intent of the requirements finalized
in subpart I. In finalizing the reporting
requirements for fluorinated HTFs, EPA
did not intend to exclude fluorocarbons
that can enter the atmosphere under the
conditions in which HTFs are used in
the electronics manufacturing industry.
EPA’s burden estimates were based on
reporting of all fluorinated HTFs;
therefore, the clarification of intent does
not impose additional burden on
reporters.
EPA requests comment on the
proposed amendments to the HTF
provisions of subpart I. In particular,
EPA requests comment whether the
proposed definition effectively captures
fluorinated HTFs used in electronics
manufacturing (i.e., whether any type of
fluorinated HTFs other than those
included in the proposed definition are
currently being used or are anticipated
to be used in the future for electronics
manufacturing). EPA also requests
comment on whether any other
conforming changes need to be made.
EPA plans to address the comments
on these proposed amendments and
publish the final amendments to subpart
I before the end of 2011. Therefore, EPA
requests comment on whether to require
electronics manufacturing facilities to
estimate and report 2011 emissions in
2012 of the HTFs that would be newly
included in the scope of subpart I if
today’s proposed rule were finalized.
Specifically, EPA requests comment on
whether information collected as part of
routine business practices, such as
records of HTF stocks, disbursements,
and acquisitions, could be used to
estimate 2011 emissions to be reported
in 2012. If it is not feasible to estimate
HTF emissions in 2011 for substances
that are currently excluded from
reporting using information collected as
part of routine business practices, EPA
requests detailed information
illustrating why it is not feasible.
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C. Subpart W—Petroleum and Natural
Gas Systems
EPA is proposing several technical
clarifications and amendments to
subpart W to address issues raised
during the first year of promulgation of
the rule in response to petitions
submitted to EPA for reconsideration, as
well as clarifications to specified
provisions in the rule to ensure
consistency with subpart W, and across
all subparts, where appropriate. In
addition, several technical corrections
are proposed to clarify provisions that
were either erroneous or unclear to
reporters.
The following section describes EPA’s
proposed amendments. We first discuss
the proposed amendments related to
field-level reporting in the onshore
petroleum and natural gas production
section, since this proposed amendment
affects multiple emissions sources (well
completions, well workovers, well
venting for liquids unloading, and
onshore storage tanks) and also affects
many sections of the rule (e.g.,
calculation, monitoring and quality
assurance/quality control (QA/QC), and
the data reporting requirements).
Following the discussion for onshore
production, we discuss the proposed
amendments to the Definition of the
Source Category (40 CFR 98.230), GHG’s
to Report (40 CFR 98.232), Calculating
GHG Emissions (40 CFR 98.233),
Monitoring and QA/QC Requirements
(40 CFR 98.234), Data Reporting
Requirements (40 CFR 98.236) and
Records to be Retained (40 CFR 98.237)
under subpart W.
Sub-Basin Category for Onshore
Petroleum and Natural Gas Production.
EPA has received several requests to
reconsider the use of a field-level
measurement plan for emission sources
(mainly monitoring of GHGs from well
unloading, well completions, and well
workovers) that require one
measurement per field as designated by
the U.S. Energy Information
Administration (EIA) Field Code Master
List (FCML). Onshore petroleum and
natural gas production reporters have
expressed concerns over the use of this
field designation and proposed that a
sub-basin category be assigned instead
of a field designation to take
measurements. Specifically, petitioners
indicated that EPA has not clarified how
reporting entities are supposed to map
wells to a particular field. They
contested that there are no coordinates
provided in the EIA FCML 2008. They
also suggested there is no formal way to
designate appropriate field names and
the rule does not have a mechanism to
deal with wells that are not in a
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recognized field in the EIA Master List.
Mapping wells to the proper field is
central to compliance with the rule,
they assert, because the rule requires
aggregation of information by field for
the different emissions sources. To
address these concerns, industry
petitioned EPA to replace the field-level
approach with a ‘‘sub-basin category’’
approach.
In general, EPA continues to believe
that the field-level designation is
workable, although perhaps not the only
means of obtaining representative
emissions estimates. EPA has
determined that the EIA field codes are
developed using field names that
operators provide and agree on with
States, which is finally provided by the
States to the EIA. Therefore, EPA
believes that operators can determine
the EIA field they are in using the EIA
field codes. EPA also agrees that the
2010 final rule did not state a clear
mechanism to address wells in fields
that were not included in the EIA
FCML. However, EPA has determined
that this is not an acute problem. EPA
has analyzed the EIA FCML for several
years and found that the changes in the
database from year to year are not
significant. For example, there were
only 30 changes in field definitions
between 2007 and 2008 of the total
64,454 fields in the database. Similar
numbers result from comparing 2006
with 2007 (170 changes in field
definition of a total 63,873 fields in the
database) and comparing 2006 with
2005 (44 changes in field definition of
a total 63,356 fields in the database).
The changes include both the revision
of some field names as well as new
additions.
In this action we are proposing an
alternative approach to replace ‘‘fieldlevel’’ with ‘‘sub-basin categories.’’ EPA
considered, but is not proposing at this
time modifications to the current field
level reporting method that would
address the outstanding concerns raised
by industry. Specifically, EPA
considered an amendment that would
allow reporters to use a temporary field
name when submitting reports to EPA
in instances where a well does not fall
within a designated EIA field code. This
alternative approach would include a
provision for reporters to report a
preliminary field name where a field
has not been formally designated by the
State and as such may not yet be
included in the EIA FCML. These
preliminary fields entered by the
reporter would be annotated in the final
report to EPA and would be flagged in
the data system for further follow up to
determine the final field name
designated by the State. Because States
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operate on different schedules for which
final determinations are made on field
designation requests, reporters would be
required to certify with official
documentation submitted to EPA upon
each reporting period on the status of
their field designation request. Under
this alternate approach, for field
designations that are made prior to the
next reporting date, reporters should
confirm the field designation with
official documentation during the next
submission of their emission report to
EPA. This proposed method would
address concerns raised by industry
about fields not yet included in the EIA
FCML.
In addition, EPA is considering but
did not propose a provision that would
delineate how reporters would
determine appropriate field names for
wells for which the designated field is
unknown due to unclear location or
coordinates of the well. Under such a
provision, reporters would determine
the EIA FCML field for a given well by
determining the well coordinates and
follow the procedures outlined in the
2008 EIA FCML or most approximate
year’s documentation that accompanies
the EIA FCML field list which outlines
the method for matching up well
coordinates with field names. Although
EPA is proposing an alternative means
to calculate and report emissions based
on a sub-basin category, we are seeking
comment on this approach to modify
the current field-level calculation and
reporting requirements for utilizing the
EIA FCML for sampling. Although EPA
maintains that the current field level
calculation and reporting requirements
are feasible and provide representative
emissions estimates (with an
amendment to clarify how to address
non-designated fields), EPA is
proposing an alternative sub-basin
approach that we believe also achieves
an appropriate level of
representativeness. Please see Economic
Impact Analysis Memorandum in
Docket ID EPA–HQ–OAR–2001–0512.
This proposed sub-basin category
classification would provide similar
quality data as the EIA FCML
designation but believes will also
address some of the questions and
concerns regarding current
implementation of the field-level
approach.
The foundation of the proposed subbasin approach is defining a sub-basin
category through the use of a county
level designation and the distinction of
the type of hydrocarbon formation. The
various hydrocarbon formations can be
grouped into four categories:
conventional, coal bed methane, tight
formations, and shale. For example,
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wells producing coal bed methane from
formation ‘‘X’’ with wellhead
coordinates within county ‘‘A’’ would
be one sub-basin category. Further,
wells producing from tight formation
‘‘Y’’ with wellhead coordinates within
county ‘‘A’’ would be a second subbasin category. In the event that a
specific county includes more than one
formation (e.g., coal bed methane and
tight sands), then the reporter would use
the most specific designation (e.g., coal
bed methane).
With this basic formulation of subbasin category, EPA has determined that
it is necessary to provide a second level
of classification to get a representative
emissions profile of emissions sources.
For example, the emissions from well
completions or hydraulic fracturing can
vary by several multiples within the
same producing formation because of
different fracture zones and fracture
extent. Similarly, well liquids unloading
emissions can vary widely because of
different well dimensions and liquid
accumulation. EPA further notes that
the activity of emissions sources are
highly concentrated within certain
counties and formation types. For
example, of the 3,143 counties in the
United States, there are only 54 counties
that had any form of well completion in
year 2010. In such a case, where 25,000
well completions are concentrated in 54
counties, a single measurement from a
sub-basin category, may not be
sufficiently representative.
Therefore, to obtain a sufficient
number of data points to be able to
characterize the variability in the
emissions profile, EPA is proposing a
measurement plan that uses some
operational criteria to generate more
than one sample per sub-basin category
for specific emissions sources.
Specifically, EPA is proposing the use of
pressure ranges for liquids unloading
measurements, because the volume of
gas released during an unloading is
related to the wellhead pressure. For
example, reporters would take one
measurement per pressure range within
a sub-basin category. An example of
pressure ranges is 0–25 psig, > 25–60
psig, > 60–110 psig, > 110–200 psig, and
200 psig and above. These pressure
ranges were developed based on an
analysis that reviewed well data from
the HPDI© database which determined
the optimal pressure ranges that also
minimize variability of a single data
point as a representation of that
pressure range. For more information on
this analysis, please see the Technical
Support Document for this proposed
rulemaking in the docket.
The rationale for applying these
pressure ranges is that wells generally
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have more liquids unloading problems
when they are flowing at low pressures
and lower velocities. Hence, it is
reasonable to provide more ranges in the
lower pressure spectrum. EPA expects
to see few wells over 200 psig that
necessitate liquids unloading to
atmospheric pressure. For well
completions and workovers, EPA is
proposing to divide the population of
wells between vertical and horizontal
wells, as defined in proposed amended
40 CFR 98.238, and then using a
graduated number of measurements per
number of wells completed or worked
over in these categories. For example,
one measurement per 25 wells with
hydraulic fracture, two measurements
per 50 wells with hydraulic fracture,
three measurements per 100 wells with
hydraulic fracture, and four
measurements per 200 or more wells
with hydraulic fracture. EPA
understands that there are many
operational factors that impact the
magnitude of emissions from well
hydraulic fracture completions and
workovers and therefore is proposing
more than one measurement where
there is a larger number of wells in the
sub-basin category.
Source Category Definitions. In
general, we are proposing several
amendments to the source category
definitions to clarify the boundaries
between the different industry
segments. The proposed amendments
below seek merely to clarify coverage in
the rule and were not intended to
change who is required to report within
and across the industry segments.
Onshore Petroleum and Natural Gas
Production. We are proposing several
amendments to the definition for the
onshore petroleum and natural gas
production (also referred to as onshore
production) industry segment in 40 CFR
98.230(a)(2). EPA received feedback
from reporters on the finalized
definition for the onshore production
industry segment on November 30, 2010
(see 75 FR 74489) requesting
clarification on the term ‘‘associated
with a well-pad.’’ Specifically, reporters
requested clarification on what the term
‘‘associated with a well-pad’’ meant in
the context of the boundaries of the
onshore production industry segment.
Reporters stated that there is unclear
demarcation between equipment that
are considered part of the onshore
production industry segment and
equipment that are considered part of
the onshore natural gas processing
industry segment.
To address concerns on the meaning
of ’’associated with a well-pad’’, EPA is
first proposing to revise the term itself
to state that the onshore production
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industry segment includes that
equipment that is ‘‘on a single well-pad
or associated with a single well-pad.’’
EPA has determined that equipment
located on a single well-pad is
considered part of the onshore
production industry segment
irrespective of the hydrocarbon streams
that it is handling. For example, a
separator located on a well-pad that
handles hydrocarbon streams from
multiple well-pads would be considered
to be part of the onshore production
industry segment, i.e. equipment that is
not located on a well-pad would be
considered to be associated with a wellpad. Also, hydrocarbon streams from
multiple wellheads located on a single
well-pad is considered to be a single
hydrocarbon stream from that well-pad.
In addition, EPA is proposing to
clarify in the onshore production
industry segment definition that
dehydrators that are on a single wellpad or associated with a single well-pad
are included as types of equipment that
is considered part of this segment.
Following promulgation of subpart W in
November 2010, EPA received several
questions from the reporting community
requesting clarification on whether or
not dehydrators associated with a single
well-pad would be a part of the industry
segment. It was EPA’s intent that these
dehydrators that are on a well-pad or
associated with a single well-pad be
considered part of the onshore
production industry segment. EPA also
received similar requests for
clarification on whether or not storage
vessels, not necessarily the entire
storage facility, were also considered
part of the onshore production industry
segment. To address these concerns,
EPA is proposing to clarify in the
definition that both dehydrators and
storage vessels are included in the
equipment list that are considered part
of the onshore production industry
segment. Finally, EPA proposes to
clarify that Enhanced Oil Recovery
(EOR) that use either CO2 or natural gas
are a part of the source category. The
equipment located on a well-pad is part
of the onshore production industry
segment irrespective of the hydrocarbon
streams located on a well-pad.
Onshore Natural Gas Processing. EPA
is proposing several clarifications to the
onshore natural gas processing industry
segment definition in 40 CFR
98.230(a)(3). By letter dated January 31,
2011, the Gas Processors Association
(GPA), CEC/AXPC, and API, all
expressed concerns with overlap
between the onshore production,
onshore natural gas processing, and
onshore natural gas transmission
industry segments. API stated that ‘‘The
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definitions of the industry categories
‘onshore oil and gas production’ and
‘natural gas processing’ do not provide
a clear line between onshore oil and gas
production, gas gathering/collection and
booster stations, and natural gas
processing facilities.’’ The letter stated
‘‘API is particularly concerned that the
final rule could be interpreted to
include gathering and boosting stations
in the processing sector, despite EPA’s
stated intent to exclude gathering and
boosting stations from coverage at this
time.’’ Industry raised concerns that
boosting stations would be covered
under the finalized natural gas
processing industry segment definition
because they typically have processes
that require removal of liquids for
operation of specific equipment that
boost gas pressure. For example,
scrubbers are used upstream of
compressors to take out any liquids for
optimal operation of the compression
equipment. However, the presence of
scrubbers in and of itself should not
result in the facility being defined as a
processing facility.
To address the concerns with
boundaries between industry segments,
we are proposing several revisions to
clarify our intent. First we are proposing
to strike the term ‘‘and recovers’’ from
the first sentence in order to more
clearly characterize the unique activities
performed at the processing plant.
Processing plants extract heavy
hydrocarbons and non hydrocarbon
gases from the gaseous phase of an inlet
feed to the plant. By inclusion of the
term ‘‘recovers’’ in the industry segment
definition, the natural gas processing
plant definition may have been
incorrectly interpreted to bring in other
types of processes that were not
intended to be covered.
We are also proposing to clarify that
this industry segment includes one or a
combination of the following three
processes: Separation of natural gas
liquids (NGLs) from natural gas,
separation of non-methane gases from
produced natural gas, or separation of
NGLs into one or more component
mixtures. This proposed revision would
clarify that the natural gas processing
industry segment differs from what
typically happens at boosting stations in
that natural gas processing plants
typically perform one or more of these
processes, whereas boosting stations do
not.
We are also proposing a clarification
on what separation means by stating
that separation means one or more of
the following processes: Forced
extraction of natural gas liquids, sulfur
and carbon dioxide removal,
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fractionation of NGLs, or the capture of
CO2 separated from natural gas streams.
We are proposing to strike the term
‘‘this industry segment does not include
reporting of emissions from gathering
lines and boosting stations’’ because the
edits proposed above clarify what
‘‘onshore natural gas processing’’
means, and therefore it is unnecessary
to discuss that which is excluded.
Further, if we had decided to maintain
the ‘‘gathering lines and boosting’’
stations in the rule, EPA would have to
propose and finalize a definition of the
term ‘‘gathering line and boosting’’
station, which EPA has previously
noted we intend to consider in a future
rulemaking (75 FR 74468).
Finally we are proposing to strike the
term ‘‘facility’’ and replace it with the
term ‘‘plant’’ as ‘‘facility’’ has a specific
definition in 40 CFR 98.6 that was not
intended here. A natural gas processing
plant may be located at a facility that
also contains other source categories
covered by 40 CFR part 98.
Onshore Natural Gas Transmission
Compression. EPA is proposing several
clarifications to the onshore natural gas
transmission compression industry
segment definition in 40 CFR
98.230(a)(4). As noted earlier, by letter
dated January 31, 2011, API, CEC/
AXPC, and GPA raised their concerns
that the boundaries between the onshore
production, onshore natural gas
processing, and onshore natural gas
transmission compression industry
segment boundaries were unclear based
on the provisions in the November 30,
2010 final rule.
First, we are proposing to strike the
term ‘‘at elevated pressure’’ because it
was not clear what ‘‘elevated pressure’’
meant. For example, elevated with
respect to what baseline? Based on
questions received on the definition for
transmission compressor stations, we
have proposed to clearly define
transmission pipelines using a widely
accepted designation for what is a
transmission pipeline, avoiding the
need to retain the language of ‘‘elevated
pressure.’’ We are proposing to define in
40 CFR 98.238 that a transmission
pipeline means a Federal Energy
Regulatory Commission (FERC) rateregulated interstate pipeline, a state
rate-regulated intrastate pipeline, or a
pipeline that falls under the ‘‘Hinshaw
Exemption’’ as referenced in the Natural
Gas Act.
Next, we are proposing to clarify the
end points between which a natural gas
transmission compression facility
would move natural gas. Specifically,
we are proposing to explicitly state that
natural gas transmission compression
facilities not only move natural gas from
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production fields or gas processing
plants, but also move natural gas
coming from other transmission
compressors. In addition, we are
proposing to explicitly state that natural
gas transmission compression facilities
may move natural gas into not only
distribution pipelines, but also into
liquefied natural gas storage or into
underground storage.
We are also proposing to strike the
term ‘‘natural gas dehydration’’ from the
industry segment definition because this
term does not represent a unique
characteristic to facilities with natural
gas transmission compression. We
believe that deleting this term from the
definition of the natural gas
transmission compression industry
segment, will result in this industry
segment definition being more
representative and accurate. Finally, as
described above under onshore natural
gas processing, we are proposing to
strike the reference to ‘‘gathering lines
and boosting stations’’ and ‘‘facility.’’
Natural Gas Distribution. EPA is
proposing several amendments to the
natural gas distribution industry
segment definition to further clarify its
intent. First, we are proposing in 40 CFR
98.230(a)(8) to eliminate the term ‘‘city
gate station’’ and add the term ‘‘meterregulating station.’’ The term ‘‘city
gate,’’ was used in the 2010 final rule
because it was believed to be widely
used throughout the natural gas
distribution industry. However, since
publication, we have learned that the
term can have several meanings and the
interpretation of what is a ‘‘city gate’’
station may vary among potential
reporters. By letter dated March 2, 2011
from the American Gas Association, it
was stated that ‘‘[t]he term ‘city gate’ is
widely used in the industry, but
unfortunately it means different things
to different companies. It can mean the
place where an LDC takes custody of
natural gas from the upstream supplier
(either directly from a producer or from
an interstate pipeline company). The
term ‘city gate’ is also used by some to
refer to the place where natural gas is
conveyed into a lower pressure
distribution system for a town or city—
either directly from the upstream
supplier (producer or interstate
pipeline) or from the LDC’s own
intrastate high pressure transmission
pipelines. Some companies do not use
the term ‘city gate’ to refer to the
situation where natural gas goes from
the company’s own transmission pipes
to one of its distribution systems.
Instead, these companies may use other
terms such as ‘district regulator’ or
‘metering and regulating stations,’ or
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‘M&R’ equipment, and these terms also
can have varying meanings.’’
Further, subpart A provides a
definition for ‘‘city gate,’’ which was
intended to apply to subpart NN and is
based on financial custody transfer.
Whereas the connotation of the term
city gate as defined in subpart A works
sufficiently for subpart NN, it has
created confusion for subpart W and
does not clearly identify the types of
facilities EPA intended to cover. The
amendments that EPA is proposing are
designed to more clearly portray EPA’s
intent using language readily
understandable to industry.
First, we are proposing to strike the
parenthetical term ‘‘(not interstate
transmission pipelines or intrastate
transmission pipelines).’’ The
parenthetical was deemed unnecessary
because EPA is proposing to add a
definition for ‘‘distribution pipeline’’ in
40 CFR 98.238 that clarifies that
‘‘distribution pipelines’’ are only those
designated as such by the Pipeline and
Hazardous Material Safety
Administration (PHMSA). Next, we are
proposing to replace the term ‘‘city
gate’’ with ‘‘meter-regulating’’ station.
Because of the wide range of views in
industry on the meaning of the term
‘‘city gate’’ EPA is proposing to remove
the term ‘‘city gate’’ from subpart W and
replace it with a term that reflects the
types of activities occurring at the
stations of interest. Specifically, we are
proposing to add a definition for the
term ‘‘meter-regulating station’’ in 40
CFR 98.238 to mean, ‘‘An above ground
station that meters the flow rate,
regulates the pressure, or both, of
natural gas in a natural gas distribution
facility. This does not include customer
meters, customer regulators, or farm
taps.’’ With this change, EPA intends to
clarify a key concept in the natural gas
distribution segment definition, but
does not intend to change who is
actually covered by the rule’s
requirements.
EPA is proposing to strike the terms
‘‘excluding customer meters’’ and
‘‘physically deliver natural gas to end
users’’ because the proposed definition
for ‘‘meter-regulator’’ stations already
addresses this exclusion.
Finally, we are proposing to clarify in
the industry segment definition that we
are only seeking for LDCs that are
within a single state, consistent with the
definition for LDCs in subpart NN.
Greenhouse Gases to Report. We are
proposing several amendments to the
subpart W provisions on the greenhouse
gases that must be reported.
We are proposing to amend 40 CFR
98.232(c) to clarify that the equipment
listed in 98.232(c)(1) thru (22) are for
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equipment on a single well-pad or
associated with a single well-pad in
order to make the language consistent
with the proposed changes to the
onshore production industry segment
definition in 40 CFR 98.230(a)(2)
described above.
We are proposing to amend 40 CFR
98.232(i) by replacing the term ‘‘custody
transfer city gate station’’ with the term
‘‘transmission-distribution transfer
station’’ and replacing the term ‘‘noncustody transfer station’’ with the term
‘‘metering-regulating station.’’ EPA is
proposing this amendment to clarify
that the sources covered be consistent
with the proposed terms for the natural
gas distribution industry segment in 40
CFR 98.230(a)(8). We are also proposing
to amend the source types by removing
the text ‘‘Customer meters are
excluded.’’ The exclusion is already
covered in both the industry segment
definition and in the definition of
‘‘metering-regulating station’’ provided
in 40 CFR 98.238 and does not provide
added clarity in this context. Next, we
are proposing to strike 40 CFR 98.232(j)
in order to address concerns raised that
the inclusion of this provision resulted
in confusion amongst reporters as they
were unsure how this provision aligned
with the flare emissions that are
captured under the applicable emissions
source calculations throughout 40 CFR
98.233. In addition to the proposal to
strike 40 CFR 98.232(j), we are
proposing to revise the introductory
sentences to 40 CFR 98.232(e), (f), (g),
(h), and (i) to clarify that N2O emissions,
which are the primary GHG emission
from flaring, are also required to be
reported under these industry segments.
This proposed amendment also clarifies
that flare emissions must only be
calculated where ‘‘flare stacks’’ are
either specifically identified in a
specific industry segment (e.g., onshore
natural gas processing) or where an
emissions source that is covered in an
industry segment is routed to a flare
(e.g., centrifugal compressors under
onshore natural gas transmission).
Finally, we are proposing to further
clarify in 40 CFR 98.232(k) that the
onshore production and natural gas
distribution industry segments are to
report their combustion emissions
under subpart W, while the remaining
industry segments are to report their
combustion emissions under subpart C
of part 98.
Calculating Greenhouse Gas
Emissions. We are proposing several
clarifications, corrections, and
amendments throughout 40 CFR 98.233.
Natural Gas Pneumatic Device
Venting. EPA is proposing to revise
Equation W–1 in 40 CFR 98.233(a) by
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adding 40 CFR 98.233(a)(3) that allows
the type of pneumatic devices to be
determined using engineering
estimation based on best available
information. The proposed amendment
for pneumatic devices was in response
to questions received about how to
determine whether a pneumatic device
is high bleed or low bleed and the
unanticipated burden for industry if
they would have to measure the bleed
rate of all pneumatic devices in order to
determine how to characterize each
pneumatic device.
EPA is also proposing to amend
Equation W–1, to include a parameter
‘‘T’’ that estimates the total number of
hours the devices were operational.
Previously, this equation assumed that
all natural gas pneumatic devices were
operational all year, which would
overestimate the emissions where the
pneumatic devices operate less than a
full year. Overall, we are proposing
these amendments to Equation W–1 to
more accurately reflect operating
conditions for natural gas pneumatic
device venting. Furthermore, EPA is
clarifying in the definition for ‘‘GHGi’’
that compositions in 40 CFR 98.233(u)
may be used for the onshore petroleum
and natural gas production, onshore
natural gas transmission compression,
and underground natural gas storage
industry segments.
In addition, with respect to the
pneumatic device venting category, we
are proposing in 40 CFR 98.236(c)(1)(iv)
to clarify that emissions should be
reported collectively for all high bleed
pneumatic devices, then separately for
all intermittent bleed pneumatic
devices, and separately for all low bleed
pneumatic devices. The 2010 final rule
stated merely ‘‘report emissions
collectively.’’ The proposed amendment
is consistent with how data are
collected and emissions calculated.
Natural Gas Driven Pneumatic Pump
Venting. We are proposing to amend
Equation W–2 in 40 CFR 98.233(c),
which is used for calculating GHG
emissions from natural gas pneumatic
pump venting, to include a parameter
‘‘T’’ that estimates the total amount of
hours the pumps were operational.
Previously, this equation assumed that
all natural gas pneumatic pumps were
operational all year, which would
overestimate the emissions where the
pneumatic devices operate less than a
full year. We are proposing this
amendment to Equation W–2 to more
accurately reflect operating conditions
for natural gas pneumatic pump
venting.
Acid Gas Removal Vents. We are
proposing to amend the calculation for
estimating CO2 emissions from acid gas
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removal vents in Equation W–4 in 40
CFR 98.233(d). EPA notes that the
equation in the 2010 final rule is an
approximation and works well when the
amount of CO2 in gas is relatively low,
such as 1 percent. However, the error
rate in the estimate increases
significantly as the amount of CO2 in gas
increases. Therefore, EPA is proposing a
new equation, which uses the exact
same input parameters and thus will not
result in any additional burden to
reporters, but will improve the quality
of the information submitted to EPA.
We are also proposing to amend 40
CFR 98.233(d)(1) to specify that the use
of CEMS is required if a CO2
concentration monitor and volumetric
flow rate monitor are installed. This
amendment was made to clarify what
conditions must be met to satisfy the
subpart C: Stationary Combustion Tier 4
calculation requirement for Acid Gas
Removal vents and to make the
requirements consistent in subpart W
where use of CEMS is required.
In 40 CFR 98.236(c)(3) we are
proposing to clarify that reporting of
CO2 content should reflect the annual
average of the measurements
undertaken in 40 CFR 98.233(d). The
2010 final rule was not clear on whether
or not to aggregate the measurements,
and if so, how.
Dehydrator Vents. EPA is proposing
several amendments to the provisions in
40 CFR 98.233(e) for calculating GHGs
from dehydrator vents. First, we are
proposing to clarify that gases other
than natural gas, such as nitrogen, flash
gas from the flash tanks, or dry gas from
the absorber, that are used as stripping
gases satisfy the requirements stated in
40 CFR 98.233(e)(1) introductory
language. The final rule explicitly stated
that natural gas was the gas considered
to be the stripping gas. We are
proposing this amendment to more
accurately reflect operating conditions
for glycol dehydrators in which gases
other than natural gas are used as
stripping gases.
We are also proposing to amend 40
CFR 98.233(e)(6) to clarify that GHG
mass emissions from glycol dehydrators
are to be calculated from volumetric
GHG emissions using calculations in 40
CFR 98.233(v). In addition, we are
proposing to clarify that only for
dehydrators that use desiccant should
GHG volumetric and mass emissions be
calculated using paragraphs 40 CFR
98.233(u) and 98.233(v). We are
proposing this amendment to account
for calculation methodology 1 and 2, 40
CFR 98.233(e)(1)–(e)(3), that calculates
total GHGi volumetric emissions in
standard cubic feet and will only need
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conversion to GHG mass emissions
using 40 CFR 98.233(v).
With respect to the data reporting
requirements, we are proposing to
clarify the requirement to report vented
and flared emissions individually. In
the 2010 final rule, EPA intended that
vented emissions be reported as one
value, and flared emissions as a separate
value. However, because these were
entered in the same sub-paragraph, 40
CFR 98.236(c)(4)(i)(J), there was some
ambiguity as to the aggregation for
reporting. Therefore, EPA is proposing
to create separate reporting
requirements for vented and flared
emissions. A similar amendment is
proposed for 40 CFR 98.236(c)(4)(ii)(D).
Also for dehydrators, EPA is
proposing to clarify that in specifying
whether any vent gas controls have been
used, the owners or operators should
report which vent gas controls were
used.
Well Venting for Liquids Unloadings.
First, we are proposing to revise 40 CFR
98.233(f) methodology 1, methodology
2, and methodology 3 such that
sampling would be done in a sub-basin
category as opposed to the field level as
described earlier in Section II.C. of this
preamble (Sub-basin Category for
Onshore Petroleum and Natural Gas
Production).
In the technical corrections rule, EPA
proposed several technical corrections
to the provisions in 40 CFR 98.233(f)
including corrections to Equation W–8,
W–9, and their respective definitions. In
today’s action, we are proposing
additional revisions to Equations W–8
and W–9 and their respective
definitions. Because both proposed
actions affect the same paragraph of the
rule, for clarity the part 98 amendatory
language at the end of this preamble
contain the full set of revisions from
both proposed actions. The changes
proposed today are explained below in
this preamble.
First we are proposing to revise
Equation W–8 by correcting the
definition for parameter Ea,n to be Es,n to
accurately reflect that the calculated
emissions should be in standard
conditions and not actual conditions.
The proposed revision from actual
conditions to standard conditions was
made to be more uniform in approach
to calculate emissions. The parameters
in Equation W–8 have been made
applicable to each venting instance, q,
and for each well, p, in a pressure
grouping and sub-basin category. These
changes are notational amendments that
correct the summation operation. Next,
we are proposing to amend the
definition for ‘‘SFR’’ which is the
average sales flowrate to state that the
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average sales flow rate of gas is to be
obtained at standard conditions, and
also that Equation W–33 may be used to
convert the sales flow rate from actual
to standard conditions. In addition, the
definition for parameter WDwp has been
clarified to mean the distance between
the lowest packer to the bottom of the
well. We are also proposing to remove
40 CFR 98.233(f)(2)(i) to remove
redundancy with 40 CFR 98.233(f)(4).
As stated previously, we are proposing
to amend Equation W–9 in the same
manner as Equation W–8: By revising
the definition for ‘‘Ea,n’’ to accurately
state that the definition should result in
standard conditions, thus ‘‘Es,n’’, and by
revising the definition for SFR to state
that the average sales flow rate is to be
calculated at standard conditions using
Equation W–33; and the parameters,
where applicable, have been made
applicable to each venting event, q for
each well, p, in a pressure grouping and
sub-basin category to correct the
summation. Finally, we are proposing to
amend Equation W–8 and W–9 to
account for a change in aggregation from
field level to sub-basin category for
reporting.
For Calculation Method 1, where a
representative measurement is taken
from one well unloading and then
applied to all other wells of a similar
type, EPA is defining the categorization
of ‘‘similar types’’ by five pressure
ranges and three tubing diameters. The
pressure ranges were optimized using
HPDI well counts in 5 psig pressure
increments from zero gauge pressure to
200 psig. The fifth ‘‘unbounded’’
pressure range is ‘‘greater than 200
psig,’’ which EPA believes will have
very few well liquids unloading venting
to the atmosphere. The three tubing
diameter ranges, equal or less than 1
inch, greater than 1 inch and equal or
less than 2 inch, and greater than 2 inch,
were derived from gas well tubing
suppliers’ specifications. The relevancy
of these pressure ranges and tubing
diameter ranges is that liquids
unloading venting is dependent on both
the shut-in pressure of the reservoir
(shut-in by liquids accumulation) and
velocity of gas pushing liquids up the
tubing, which is a function of tubing
diameter.
Finally, in the data reporting
requirements in 40 CFR 98.236(c)(5), we
are proposing to make a harmonizing
change, consistent with the
amendments described above in (Subbasin Category for Onshore Petroleum
and Natural Gas Production), that
reporting should be for each well tubing
diameter grouping and pressure
grouping within each sub-basin
category.
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Gas Well Venting During Completions
and Workovers From Hydraulic
Fracturing. We are proposing several
amendments to 40 CFR 98.233(g) to
account for the proposed change in
aggregation from field level to sub-basin
category for taking measurements. For
example, we are replacing the term
‘‘field’’ with ‘‘sub-basin and well type
combination’’ in the definitions and
clarifying that the GHG emissions are
determined for each sub-basin and well
type combination. For further
discussion on the proposed changes
from field level calculations and
reporting to sub-basin category, please
refer to Section II.C of this preamble
(Sub-basin Category for Onshore
Petroleum and Natural Gas Production).
We are also proposing to revise
equation W–10 by including a provision
to account for the time period in which
we believe normal production of a well
would be established. In this action, we
are revising equation W–10 by defining
a parameter, FRM, which would
represent the ratio of emissions (FRp) to
the average 30 day production from the
well immediately following hydraulic
fracturing (PRP). The emissions, FRp,
which in the final rule as the average
flow rate in cubic feet per hour
converted to standard conditions, are
calculated using W–11A and W–11B.
FRM is calculated using the newly
assigned Equation W–12. We believe
that this proposed revision will more
accurately represent the production
flow from a well immediately following
a well or completion using hydraulic
fracturing and will more accurately
represent when a completion or
workover ends and when normal
production begins. Finally, in Equation
W–10, EPA is proposing to add the
parameter W, which is the number of
wells completed or worked over using
hydraulic fracturing in a sub-basin and
well type combination, and, where
appropriate, made the parameters
applicable to each well p. This
amendment corrects the summation
operator to make it mathematically
accurate.
EPA also added Equation W–11C,
which allows reporters to determine
whether the well flow rate of gas during
venting to the atmosphere or a flare (i.e.,
FRWP, is sonic or sub-sonic flow. Thus,
reporters can determine whether to use
Equation W–11A, which is for sub-sonic
flow, or Equation W–11B, which is for
sonic flow.
We are also proposing several minor
edits to 40 CFR 98.233(g)(3) and 40 CFR
98.233(g)(5) to clarify that all
requirements in 40 CFR 98.233(g) apply
to gas well venting during completions
and workovers from hydraulic
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fracturing, consistent with the emission
source name of ‘‘Gas well venting
during completions and workovers from
hydraulic fracturing’’.
In 40 CFR 98.233(g)(3) we are also
proposing to delete the reference to how
to calculate the volume of recovered
completion or workover gas. The first
sentence in that paragraph is already
clear that company records may be
used, therefore the second sentence
does not provide any additional
information and is duplicative.
We are proposing several harmonizing
changes to the data reporting
requirements for this emissions source.
We are proposing to indicate that
reporting is required for each ‘‘sub-basin
category’’ and well type (horizontal or
vertical). We are also proposing to
clarify that reporting of reduced
emissions completions for both well
completions and workovers is required.
Although this information is required to
be collected for both well completions
and well workovers, EPA inadvertently
omitted the reporting requirement for
reduced emissions completions for well
workovers.
Also in 40 CFR 98.236, we are
proposing to clarify that reporters are
only required to count the number of
workovers that flare or vent gas to the
atmosphere. There is no reporting
requirement for workovers that do not
flare or vent gas.
Gas Well Venting During Completions
and Workovers Without Hydraulic
Fracturing. In this section we are
proposing to strike the term ‘‘well
workovers not involving hydraulic
fracturing’’ from the introductory text in
paragraph (h) because it was repetitive.
Second we are proposing to replace
the term ‘‘field’’ used in the definition
for the parameter ‘‘Nwo’’ and ‘‘f’’ for the
same reasons stated in Section II.C. of
this preamble (Sub-basin Category for
Onshore Petroleum and Natural Gas
Production).
Finally, EPA is proposing to amend
the summation operator in Equation W–
13 to make it mathematically accurate.
This includes making specific
parameters in Equation W–13 applicable
to each well completion, p.
Blowdown Vent Stacks. In a previous
action we proposed amendments to the
introductory sentences to 40 CFR
98.233(i). In this action, based on
additional questions received during
implementation of subpart W, we are
proposing to further clarify the types of
blowdowns that EPA intended to cover.
First, we are proposing to delete ‘‘to
atmosphere’’ because not every
blowdown will result in the blowdown
chamber being brought to atmospheric
pressure. Operators often release only
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part of the gas in the blowdown
chamber and maintain it at low
pressure. It was always EPA’s intent to
cover these types of ‘‘blowdowns’’ and
thus we are proposing to delete ‘‘to
atmosphere’’. Further we are clarifying
that we only intend to cover the types
of blowdowns typically tracked by
operators for planned maintenance or
emergency shutdowns. EPA had earlier
proposed to exclude emergency
shutdowns in a previous action.
However, EPA has since been informed
that operators track emergency
shutdowns already. Therefore, EPA is
proposing to require emergency
shutdowns to be reported. In addition,
we did not intend to capture
blowdowns that are not typically
tracked by operators, such as pressure
release valve releases designed to keep
equipment under safe operating mode.
EPA has also considered other factors
that could impact emissions from
blowdowns, for example
compressibility. We have considered
accounting for gas compressibility but
have not proposed this because we
believe that the effort in adjusting for a
compressibility factor outweighs the
benefits in terms of increased accuracy.
EPA seeks comments on why such an
allowance should be provided and how
to standardize this option so that those
who choose to use it all do so in the
same way.
Also in this action, we are proposing
to revise the numbering of Equation W–
14b and include an additional Equation,
W–14b that will take into account that
a chamber may not be blown down to
atmospheric pressure, and will allow
facilities the option of tracking
blowdowns by each occurrence by
blowdown volume. It has come to EPA’s
attention that some facilities may log
blowdowns at a facility by individual
blowdown occurrence. To enable
facilities to retain their current tracking
system, we are proposing to add an
option for calculating blowdown
emissions by equipment type. This
option for tracking blowdowns would
not impact data quality. Harmonizing
changes in 40 CFR 98.236(c)(7) are being
proposed to account for these
amendments.
Lastly, we are proposing to include a
default composition for the natural gas
transmission industry segment, and for
the LNG storage and underground
storage segments. EPA received
feedback from industry that a default
composition of 95 percent methane and
1 percent CO2 was a representative
breakdown of the gas composition at
these types of facilities while limiting
burden and should be acceptable. EPA
agrees that a default composition of 95
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percent methane and 1 percent CO2 is
appropriate because the composition of
natural gas is monitored by transmission
compression companies and regulated
by FERC.
Onshore Production Storage Tanks.
EPA is proposing to replace the term
‘‘field’’ in 40 CFR 98.233(j)(1)(vii)(B), 40
CFR 98.233(j)(1)(vii)(C), and 40 CFR
98.233(j)(3)(i) with ‘‘sub-basin category’’
consistent with the proposed
amendments described in Section II.C,
(Sub-basin Category for Onshore
Petroleum and Natural Gas Production),
of this preamble. We are also proposing
to clarify this level of reporting in the
data reporting requirements in 40 CFR
98.236(c)(8).
Also in the data reporting
requirements, we are proposing to
clarify the reporting requirement in 40
CFR 98.236(c)(8)(i), 98.236(c)(8)(ii) and
98.236(c)(8)(iii) that reporters must
report vented, flared, and recovered
emissions individually for Calculation
Methodology 1 and 2. This is consistent
with the calculation requirements.
Transmission Storage Tanks. We are
proposing to revise 40 CFR 98.233(k) to
include an additional provision such
that reporters would now have the
option of directly measuring the
transmission storage tanks while
bypassing an initial screening with the
optical gas imaging instrument. EPA
received feedback from industry that
some owners and operators would
prefer to simply measure the tank
annually without having to be required
to screen the tank vapors with a camera
first. We agree that allowing facilities to
directly measure the emissions, without
first requiring leak detection, does not
compromise data quality, but could
enable facilities to meet the
requirements of the rule with lower
burden. Therefore, in this action, EPA is
proposing to allow operators to either
screen their tanks first by using the
optical gas imaging instrument for 5
continuous minutes and if a leak is
detected, measure the leak according to
the provisions in 40 CFR 98.234
consistent with the 2010 final rule, or
measure the tank vent vapors for 5
minutes using either a flow meter,
calibrated bag, or high volume sampler
according to the provisions outlined in
40 CFR 98.234.
Finally, with respect to the data
reporting requirements in 40 CFR
98.236(c)(9), as described further above,
we are proposing to clarify the separate
reporting requirements for vented and
flared emissions.
Well Testing Venting and Flaring.
EPA is proposing In amendments to the
data reporting requirements in 40 CFR
98.236(c)(10). Specifically, we are
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proposing to add a reporting
requirement for the emissions of the
flaring gas collectively. This is
consistent with other proposed
clarifications to report flared emissions
separately.
EPA is considering, and has not
proposed, using the production rate to
estimate volume of emission from gas
wells that produce dry gas. EPA is
soliciting comments on this suggested
provision for gas wells.
EPA has received several requests to
exclude the well testing venting and
flaring emissions source from the rule.
Industry has informed EPA that this
source has very little, if any, emissions
because the well testing is almost
exclusively performed in a closed
system using a ‘‘test separator,’’ which
industry has stated would result in zero
emissions.
EPA has reviewed this request and in
general, EPA continues to believe that
well testing venting and flaring is a
relevant source in the onshore
petroleum and natural gas production
industry segment. In addition, EPA has
determined that during well testing,
some states allow companies to flare
sour gas for a maximum of 72 or 144
hours. EPA has concluded that this
approach would result in emissions
from this source that should be reported
under this rule. If, however, for some
reason reporters do not have any
emissions from this source (for e.g.,
states do not allow venting or flaring
from well testing), they would report
zero emissions.
Thus, EPA is retaining well testing
venting and flaring in the rule.
However, EPA is seeking comment on
how to reduce or eliminate burden in
cases where companies verify that zero
emissions are associated with this
potential source, such as when a closed
loop system is employed.
Associated Gas Venting and Flaring.
EPA is proposing to revise 40 CFR
98.233(m) to replace the term ‘‘field’’
with the term ‘‘sub-basin category’’ for
the same reasons outlined in Section
II.C. (Sub-basin Category for Onshore
Petroleum and Natural Gas Production)
of this preamble.
Flare Stack Emissions. We are
proposing two amendments in 40 CFR
98.233(n)(2) to clarify how to determine
gas compositions for hydrocarbon
streams going to flare. First, we are
proposing to amend 40 CFR
98.233(n)(2)(ii) to clarify that reporters
must use the GHG mole percent in feed
natural gas for all streams for onshore
natural gas processing plants that solely
fractionate a liquid stream. EPA is
proposing this amendment to address
lack of clarity in the final provisions
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which did not explicitly state how
natural gas processing plants which
only fractionate liquid streams would
determine their gas compositions. We
are also proposing to clarify in 40 CFR
98.233(n)(2)(iii) that methane, in
addition to ethane, propane, butane,
pentane-plus and mixed light
hydrocarbons, should be accounted for
when the stream going to the flare is a
hydrocarbon product stream. This
proposed technical correction, to add
methane, ensures that paragraph 40 CFR
98.233(n)(2)(iii) is consistent with the
equation.
In addition, we are proposing to
clarify the summation operator in W–21
to make it mathematically correct. We
are also clarifying that source types in
40 CFR 98.233 that send emissions to a
flare must determine volumetric flow
rate, parameter ‘‘Va’’, in Equation W–19
through W–20, at actual conditions.
We are also proposing to clarify that
the volume of gas sent to the flare
should be calculated in actual
conditions. This is consistent with other
proposed changes throughout this
revision that clarify the use of actual
versus standard conditions.
In addition, we are proposing to allow
facilities the option to use a continuous
emissions monitoring system (CEMS) to
estimate GHG emissions from flares.
EPA received questions as to why CEMS
were allowed for use for AGR vents, for
example, but not for flares. We did not
intend to unnecessarily limit the
measurement options for flares, and
therefore are proposing to add the
option to use CEMS.
The proposed text clarifies that the
use of CEMS is required if a CO2
concentration monitor and volumetric
flow rate monitor are installed and that
optionally a user may install a CO2
concentration monitor and volumetric
flow rate monitor to be eligible to use
the Tier 4 methodology. When CEMS
are used to calculate emissions for flare
stacks the use of equations W–19 to W–
21 would no longer apply. With the
relatively high quantity of unburned
methane in the emissions from flares,
EPA has identified that it is not
appropriate to use the CH4 calculation
methodology in subpart C as most flared
gases will not be fuels listed in Table C–
1 of subpart C. EPA is seeking comment
on what form an equation should take
that would calculate CH4 and N2O for
flares that are monitored by CEMS. One
option is to calculate the CH4 by
multiplying the concentration of CO2
measured by the CEMS by the fraction
of CH4 that was not combusted as
determined by flare efficiency.
In the data reporting requirements in
40 CFR 98.236(c)(12) we are proposing
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to add reporting requirements consistent
with the calculation requirements in
Equations W–19 through W–21.
Specifically, we are proposing to add
reporting of uncombusted CH4,
combusted and uncombusted CO2 and
combustion-related N2O emissions. The
proposed amendments ensure
consistency across the calculation,
monitoring and reporting requirements.
Centrifugal Compressor Venting.
Consistent with other clarifications
throughout this proposed rule, we are
proposing to clarify in the definition for
the term MTm in Equation W–24 that
flow measurements should be
determined in standard cubic feet per
hour.
Leak Detection and Leaker Emission
Factors.
We are proposing to revise 40 CFR
98.233(q)(8) to remove the term ‘‘city
gate stations at custody transfer’’ and
replace with ‘‘transmission-distribution
transfer stations’’ for the reasons
described earlier in Section II.C of this
preamble. We are also proposing to
remove the term ‘‘meters and
regulators’’ and replace with above
ground ‘‘metering-regulating stations’’.
The term ‘‘meter-regulating’’ is a term
that we are proposing to define in this
action, as described earlier in Section
II.C of this preamble.
The revisions to terminology for
natural gas distribution facilities have
been proposed to clearly identify who is
covered under the distribution segment
of subpart W, and the sources for which
leak detection and measurement are
required and those sources for which an
emission factor can be used. Based on
feedback received from industry, there
may be concerns that the emission
factors developed at the transmissiondistribution transfer stations are not
representative of emissions at other
above ground metering-regulating
stations. Although we are not proposing
changes to the approach for applying
emission factors to above ground
metering-regulating stations in this
action, we are seeking comment on
alternative approaches, or data that may
be used, for determining emissions
factors for above ground meteringregulating stations. Based on comments
received, EPA may consider future
amendments to the rule.
In a separate action, (76 FR 37300)
EPA is proposing to expand the final
BAMM provisions to cover all facilities
subject to subpart W, and allow
reporters the option to use best available
monitoring methods (BAMM) for all of
2011 without being required to submit
a request for approval to the
Administrator. For natural gas
distribution facilities at transmission-
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distribution transfer stations, this would
allow facilities to estimate the number
of equipment leaks and the equipment
sources themselves using BAMM as
provided in the rule, along with the
total time the component was found
leaking and operational, as outlined in
Equation W–30. This emission factor
could then be used for other above
ground metering-regulating stations
within the facility boundary.
EPA is proposing to clarify the
summation operator in W–30 to make it
mathematically correct. This
clarification includes amending x to be
the total number of each equipment leak
source and adding Tp, which is the total
time the component p was found
leaking and operational. We are
proposing to revise the parameter GHGi.
For industry segments listed in 98.230
(a)(4) and (a)(5), GHGi has been revised
to 0.974 for CH4 and 1.0 × 10–2 for CO2.
For industry segments listed in (a)(6)
and (a)(7), GHGi equals 1 for CH4 and 0
for CO2. For industry segments listed in
(a)(8), GHGi equals 1 for CH4 and 1.1 ×
10–2 CO2 (See Technical Support
Document Memo (TSD) in Docket ID
EPA–HQ–OAR–2011–0512 for further
details).
Next we are proposing two
amendments in 40 CFR 98.236(c)(15).
We are proposing to amend the
reporting requirements in 40 CFR
98.236(c)(15)(i)(C) to clarify that owners
or operators must report CH4 emissions
collectively by equipment type and CO2
emissions collectively by equipment
type. The calculation methodologies in
40 CFR 98.233(q), as finalized in the
rule, require reporters to calculate CH4
emissions and CO2 emissions separately
per source with equipment leaks. We
are proposing this amendment to clarify
that applicable reporters must report the
CH4 emissions collectively by
equipment type and CO2 emissions
collectively by equipment type. We are
also proposing to correct the reporting
requirement in 40 CFR
98.236(c)(15)(ii)(A) to not include
onshore natural gas processing. This
source category is not required to use
population emission factors. This
amendment is associated with the
amendment to Equation W–31 in 40
CFR 98.233(r) discussed in Calculating
Greenhouse Gas Emissions.
Population Count and Emission
Factors. We are proposing several
amendments in 40 CFR 98.233(r). First
we are proposing to amend the
population emission factor definition in
equation W–31 by replacing the term
‘‘non-custody transfer city-gate’’ with
above grade ‘‘metering-regulating
station’’ for the reason stated above in
this preamble. We are also clarifying
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that the count in equation W–31 applies
to the number of ‘‘meter/regulator runs’’
at all ‘‘metering-regulating stations’’
combined.
We are also proposing to amend the
term ‘‘count’’ in W–31 as follows to
elaborate and clarify how each industry
segment should count the total number
of equipment/components. In that same
equation, we are also proposing to
revise the definition for GHGi by
referring to 40 CFR 98.233(u) and
deleting the composition specified for
each industry segment.
Next, EPA is proposing to amend 40
CFR 98.233(r)(2)(i) to explicitly state
how meters and piping are to be
counted. Table 1–B of the 2010 final
rule was developed using activity data
from the 1996 EPA/Gas Research
Institute Study (1996 EPA/GRI Study),
Methane Emissions from the U.S.
Natural Gas Industry. For all major
equipment that are not specifically
listed, the 1996 EPA/GRI Study
categorized all components at a wellpad under the meters/piping category.
Therefore, owners or operators should
use one count of meters/piping per wellpad.
Further, consistent with proposed
amendments described above, EPA is
proposing to amend 40 CFR
98.233(r)(6)(ii) by referring to ‘‘meteringregulating stations’’ in place of ‘‘city
gate’’ and to clarify that the emission
factor for meter/regulator runs at all
metering-regulating stations in equation
W–32 is based on leak detection
performed at ‘‘transmission-distribution
transfer stations’’. EPA is also amending
40 CFR 98.233(r)(6)(i) to clarify that
below grade meters and regulators apply
to below grade ‘‘metering-regulation
stations’’.
Lastly, we are proposing revisions to
equation W–32 that include revisions to
the definitions for EF, Es,i, and ‘‘Count’’
again to clarify the terminology change
away from ‘‘custody transfer’’ to above
ground ‘‘metering-regulating’’ stations.
We are also proposing the inclusion of
a conversion factor to convert to hourly
emissions. Consequently, we are
proposing to amend the conversion in
Equation W–32 in 40 CFR 98.233(r) so
that the equation yields an EF in cubic
feet per meter per hour to be used in
Equation W–31 for above ground
metering-regulating stations. Finally, the
summation operator has been removed
in Equation W–32 because Es,i
represents annual volumetric GHGi
emissions at all T–D transfer stations,
making the summation operator
redundant.
In addition to the proposed
calculation amendments described
above, we are also proposing to replace
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the term ‘‘field’’ with ‘‘sub-basin
category’’ in the reporting for onshore
production, consistent with the
proposed change to sub-basin
calculation and reporting.
Volumetric Emissions. We are
proposing to amend 40 CFR 98.233(t) to
clarify that reporters should use actual
temperature and pressure and adjust to
standard conditions. The phrase ‘‘by
converting actual temperature and
pressure of natural gas emissions to
standard temperature and pressure of
natural gas’’ was deleted because it is
redundant.
GHG Volumetric Emissions. We are
proposing to amend 40 CFR 98.233(u) to
include 95 percent methane/1 percent
CO2 default gas composition for the
natural gas transmissions industry
segment, along with the LNG storage
and underground storage industry
segments. Again, as described above,
EPA agrees that a default composition of
95 percent methane and 1 percent CO2
is appropriate because the composition
of natural gas is monitored consistently
and regulated by FERC.
We are also proposing to strike the
reference to the term ‘‘field’’ in 40 CFR
98.233(u) and replace with ‘‘sub-basin
category’’ for the reasons outlined in
Section II.C. of this preamble (Sub-Basin
Category Reporting for Onshore
Petroleum and Natural Gas Production).
We are also proposing to clarify that
the GHG mole fraction that is
determined without using a continuous
gas analyzer may be determined using
an annual average instead of the most
recent gas composition based on
available analysis in a sub-basin entity.
GHG Mass Emissions. We are
proposing to clarify in the definitions to
equation W–36 that the equation applies
to N2O emissions as well. N2O
emissions are calculated from stationary
combustion and flares, and the
proposed edit is necessary to convert
the mass emissions of N2O to carbon
dioxide equivalents of gas. EOR
injection pump blowdown. We are
proposing to clarify in the equation that
only CO2 emissions are calculated. The
variables Massc,i has been changed to
Massc, CO2, and GHGi has been changed
to GHGCO2.
Onshore Production and Distribution
Combustion Emissions. In a previous
action, EPA proposed several revisions
to 40 CFR 98.233(z) including
corrections to Equations W–39 and 40.
In this action, we are proposing
additional amendments to clarify when
owners or operators of onshore
production and distribution facilities
must use the methods in 40 CFR subpart
C to calculate combustion-related
emissions and when they must use the
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methods in 40 CFR 98.233(z) to
calculate combustion-related emissions.
We are proposing to clarify that
facilities using subpart C to calculate
emissions are not limited to the use of
tier 1, but rather may use any tier.
Regardless of the tier used, the facility
must follow the corresponding
calculation, monitoring and reporting
requirements of that tier.
We are also proposing to amend the
requirements for units combusting field
gas or process vent gas. The 2010 final
rule required the use of a continuous
flow meter, if present. Use of a
continuous flow meter would have
necessitated calibration requirements
per 40 CFR 98.3(i). These calibration
requirements were disproportionately
burdensome for these relatively small
disperse units, particularly given that
facilities that currently do not have a
flow meter in place could use company
records. In this action, we are proposing
to amend the requirements to allow the
use of company records for this
equipment.
Onshore Production and Distribution
Equipment Threshold for Internal
Combustion Equipment. In letters dating
January 31, 2011 and March 5, 2011
from API and AGA, respectively, EPA
received petitions to reconsider an
exemption for internal combustion
engines similar to that which was in the
final subpart W rule (75 FR 74458,
November 30, 2010) for external
combustion engines. These requests
from the onshore petroleum and natural
gas production and natural gas
distribution reporters were to provide
respite for reporting of emissions from
internal combustion equipment that are
brought in temporarily for maintenance
and construction. Some reporters have
requested complete exemption such that
combustion equipment that fall below a
specific threshold would be exempt
from reporting.
EPA considered, but decided not to
propose an exemption for reporting for
internal combustion engines. EPA
decided not to propose amendments
because data currently are not available
to sufficiently characterize these
upstream emissions. For example, the
volume of fuel consumed, especially at
wellhead natural gas compressors, is not
being monitored and only limited data,
voluntarily reported, are available
through the Energy Information
Administration.
Although EPA has decided not to
propose a threshold due to lack of
availability of a comprehensive data
source from which to develop policy,
we acknowledge that there is potentially
small internal combustion equipment
outside of compressors. In considering a
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potential equipment threshold for noncompressor internal combustion
engines, EPA collected and reviewed
data on the size ranges of small, portable
internal combustion engines that may be
brought to a wellhead for periodic
maintenance and construction. Such
equipment would include, for example,
electric generators for arc welding,
electric generators powering portable
flood-lighting, and electrical generators
or gasoline engines powering air
compressors (for sand blasting or
pneumatic tools). For lighting, the
industrial generators were almost
exclusively below 12 horsepower (hp),
with the highest found being 13.9 hp.
For welding machines, we assumed that
they would use standard portable
generators, since specific information on
these types of machines was scarce.
Most portable industrial generators are
rated between 15–40 hp, with the largest
one found being 67 hp. EPA determined
that 130 horsepower (double the largest
size found) would exclude virtually all
small portable or stationary internal
combustion engines, but is much
smaller than the 5 mmBtu/hour
exclusion for external combustion
sources and equates to about 1 mmBtu/
hour. EPA is seeking comments on
whether a 1 mmBtu/hour equipment
threshold for internal combustion
engines that are not driven by natural
gas is reasonable. We also seek comment
on EPA’s position that combustionrelated emissions at compressors should
not be excluded from reporting,
regardless of size and where EPA can
find reliable estimates of natural gas
consumption.
EPA is proposing to clarify the
summation operator in Equation W–39
to make it mathematically correct. In
addition, EPA is proposing to clarify in
Equation W–40 that N2O mass
emissions are calculated by changing
the parameter N2O to Masss, N2O.
In specific, EPA is soliciting
comments as to why emissions from
specific internal combustion related
equipment should not be reported
including the size of the equipment that
should be excluded along with
supporting data.
Monitoring and QA/QC Requirements.
We are proposing several amendments
to the monitoring and QA/QC
requirements in 40 CFR 98.234.
First, we are proposing to amend the
language in 40 CFR 98.234(a)(1) by first
removing and reserving the text in 40
CFR 98.234(a)(4) and combining it with
40 CFR 98.234(a)(1), thus resulting in
one consolidated paragraph. We are also
proposing to state explicitly that video
recordings are not required under
subpart W. As noted in the Response to
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Comments to the 2010 final rule,5 EPA
did not intend to require retention of a
video recording of the leak detection
using optical gas imaging instruments
for reporting to EPA under subpart W of
the greenhouse gas reporting rule.
However, some of the references to the
Alternate Work Practice suggested that
EPA intended that facilities retain these
records onsite.
Next, we are proposing to amend the
language in 40 CFR 98.234(a)(2) to state
that Method 21 compliant instruments
may be used to monitor inaccessible
emissions sources. This amendment
increases flexibility in monitoring
requirements and reduces the burden on
the industry, without compromising
data quality.
Further, based on questions raised by
industry, we are proposing to amend 40
CFR 98.234(a)(5) by revising the
acoustic leak detection device
provisions to use a different model of
acoustic detector, one that does not have
a through-valve leakage correlation,
thereby allowing leakage to be measured
by other methods if a leak is found.
However, EPA is proposing to clarify
that not all types of acoustic detectors
are allowed. In particular the ‘‘gun’’
type instrument that is aimed at the
equipment from a distance to detect the
acoustic signal of leakage is not an
allowable instrument. This type cannot
distinguish between external leakage to
the atmosphere from internal, throughvalve leakage, which is the objective for
specifying this device. EPA is proposing
to further specify that the ‘‘stethoscope’’
type acoustic detector that senses
through valve leakage when put in
contact with the valve body, but does
not have the leakage estimating
correlations, may be used.
We are also proposing editorial
revisions in 40 CFR 98.234(c) for
calibrated bagging to specify that those
using the calibrated bag for sampling,
must ensure that the emissions must be
at a temperature below that which the
bag manufacturer specifies for safe
handling.
Data Reporting Requirements. We are
proposing several amendments and
clarifications throughout 40 CFR 98.236
in order to address questions received
about how data should be reported.
Many of the data reporting requirements
were lacking clarity with respect to the
level of reporting. Based on the
questions received, as well as EPA’s
experience gained in developing the
electronic GHG reporting tool (e-GGRT),
5 Response to Comments Document: Subpart W—
Petroleum and Natural Gas Systems, part 2, page 28.
Comment Number: EPA–HQ–OAR–2009–0923–
1039–23.
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which provided EPA a better
understanding of the clarity necessary
in the data reporting requirements, EPA
is proposing the following changes.
In cases where technical amendments
were already proposed for individual
emissions sources above, EPA has
described the corresponding proposed
amendments to the reporting
requirements along with the technical
amendments. This section outlines any
remaining proposed amendments to the
data reporting requirements not already
described above.
First we are proposing to clarify the
data reporting requirements for offshore
petroleum and natural gas production
facilities in 40 CFR 98.236(b).
Specifically, the 2010 final rule was not
clear in terms of which gases were
required to be reported and the data
elements for reporting. Consistent with
the calculation requirements, we are
proposing to clarify that facilities
containing the offshore petroleum and
natural gas production segment would
be required to report emissions of CH4,
CO2, and N2O as applicable to the
source type (in metric tons CO2e per
year at standard conditions)
individually for all the emissions source
types listed in the most recent BOEMRE
study.
Next, in the introductory paragraph
for 40 CFR 98.236(c) we are proposing
to clarify that vented emissions should
be reported separately from flared
emissions. We have specified which
source types require separate
calculation of flared emissions, but EPA
is taking comment on whether any
source types that have process gas
routed to flares were excluded from
having specific reporting requirements
established for flares.
We are proposing to make changes to
the data reporting requirements for local
distribution companies, consistent with
the proposed amendments to 40 CFR
98.230(a)(8). Specifically, we are
proposing to replace ‘‘custody transfer’’
with ‘‘transmission-distribution
transfer’’ station and replace ‘‘noncustody transfer’’ with ‘‘above ground
metering-regulating station.’’ In
addition, we are proposing to require
the reporting of counts and emissions of
both above grade and below grade
stations for each of metering-regulating
stations and ‘‘transmission-distribution
transfer stations.’’
Finally, EPA seeks some basic
information on average API gravity of
the hydrocarbon liquids produced, gas
to oil ratio, and low pressure separator
pressure per sub-basin entity. It is EPA’s
understanding that his information is
already known to reporters. EPA will
use these facility sub-basin
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characteristics to characterize other
emissions sources across different subbasins.’’
Records that must be retained. EPA is
proposing to add the following
recordkeeping requirement: ‘‘The
records required under § 98.3(g)(2)(i)
shall include an explanation of how
company records, engineering
estimation, or best available information
are used to calculate each applicable
parameter under this subpart.’’ While
EPA believes this requirement is already
included in 40 CFR 98.3(g)(2)(i) where
the records for ‘‘The GHG emissions
calculations and methods used’’
requirement is made, EPA believes that
adding this statement to the
recordkeeping requirements in subpart
W will provide facilities with further
clarity on the records they are required
to keep. This clarification is intended to
make clear that stating company
records, engineering estimation, or best
available information were used is not
enough to satisfy the requirement in 40
CFR 98.3(g)(2)(i). This requirement is
intended to parallel a similar
requirement for subpart C specified in
40 CFR 98.34(f) and referenced in 40
CFR 98.37.
Definitions. We are proposing to
amend, and in some cases, add
definitions to 40 CFR 98.238 to further
clarify rule requirements.
Associated With a Single Well-Pad.
We are proposing to add a definition for
‘‘associated with a single well-pad’’ to
clearly demarcate the boundary of
onshore production. EPA proposes that
the association be defined by the
hydrocarbon stream from a single wellpad. The association with a single wellpad ends where the stream from a single
well-pad is combined with streams from
one or more additional single well-pads,
where the point of combination is
located off that single well-pad. In
addition, we are stating that this
definition does not include storage and
condensate tanks that are located
downstream of the point of
combination. For gas contained in crude
oil or condensate flowing under
pressure off a single well-pad to a gasliquid separator or tank, or comingled
with flow from other well-pads, 40 CFR
98.233(j) requires reporting of the gas
content that may be released from the
oil or condensate in an atmospheric
pressure fixed roof storage tank. We
have determined that the conditions of
the pressurized oil or condensate (i.e.,
gravity, pressure, temperature, flow rate)
are commonly known by the well
owner/operator, and the amount of gas
that may be released from the oil or
condensate with a pressure reduction
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can be determined most appropriately
by the well owner/operator.
Distribution Pipeline. EPA is
proposing to include a definition for
distribution pipelines to add clarity on
its intent on coverage for the natural gas
distribution industry segment. We are
proposing to use a widely accepted
definition for distribution pipelines,
specifically, those designated as such by
the Pipeline and Hazardous Material
Safety Administration (PHMSA).
Facility With Respect to Natural Gas
Distribution. EPA is proposing to revise
the definition for natural gas
distribution by replacing the term
‘‘metering stations, and regulating;’’with
the term ‘‘metering-regulating.’’ EPA is
proposing to include a definition for the
term above ground ‘‘metering-regulating
station’’ to clarify where leak detection
and monitoring is required in the 2010
final rule.
Farm Taps. EPA is proposing to revise
the definition for farm taps in 40 CFR
98.238 by striking the unnecessary
phrase ‘‘The gas may or may not be
metered, but always does not pass
through a city gate station.’’
Flare. We are proposing to add a
definition of flare specific for subpart W
to address questions received during
implementation about what constitutes
a flare. The proposed definition clarifies
that a flare may be either at ground level
or elevated and uses an open or
enclosed flame to combust waste gases
without energy recovery. This definition
for subpart W is intended to be
inclusive of devices that combust waste
gases without energy recovery. This
broad, all-inclusive definition for
subpart W is necessitated by the wide
variety of waste gas combustion devices
that are or may be used in the different
segments of subpart W, all for the same
purpose and having the same effect of
combustion emissions of hydrocarbon
gases.
Forced Extraction of Natural Gas
Liquids. We are proposing to add a
definition for forced extraction to
restrict it to specific processes. EPA
determined that it was necessary to
develop this more precise definition
because many industry questions
pointed to the confusion between
processing plants, gas gathering stations
and wellheads, where similar
equipment and processes are conducted
as at some, but not all, processing plants
that EPA determined should be subject
to this rule. Those similar processes.
These processes in and of themselves do
not make a facility a ‘‘processing plant.’’
Furthermore, the Oil & Gas Journal
annual survey of gas processing plants
is primarily focused on those that
fractionate, leaving out known, large gas
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plants that separate NGLs or condition
gas, but do not fractionate, and are
clearly not gathering booster stations.
The key principle that EPA is
attempting to clarify through this
definition is the separation of heavier
hydrocarbons in the vapor phase of
natural gas delivered to a plant,
excluding the simple gravity separation
of liquids entrained in the gas. This
principle is ‘‘forced extraction,’’ as
defined here.
Horizontal Well. With the change
from field level reporting to sub-basin
category, EPA is proposing to add a
distinction for calculating emissions
from horizontal wells and vertical wells.
We are proposing to define horizontal
well to mean a well bore that has a
planned deviation from primarily
vertical to a primarily horizontal
inclination or declination tracking in
parallel with and through the target
formation.
Sub-Basin Category. With the change
from field level reporting to sub-basin
category, EPA is proposing to add a
definition for sub-basin category to
mean a subdivision of a basin into the
unique combination of wells with the
surface coordinates within the
boundaries of an individual county and
subsurface completion in one or more of
each of the following four formation
types: Conventional with > 0.1
millidarcy permeability, and
unconventional with ≤ 0.1 millidarcy
permeability shale, coal seam, and other
tight reservoir rock, all of which are
unconventional with ≤ 0.1 millidarcy
permeability. Unconventional wells
producing from formations categorized
in two or more types are considered
shale for a combination of ‘‘shale and
coal’’, ‘‘shale and other tight’’, or ‘‘shale,
coal and other tight’’; and are
considered as coal for combinations of
‘‘coal and other tight’’.
Transmission-Distribution (TD)
transfer station. EPA is proposing to add
a definition for Transmission
Distribution (TD) transfer station to
define what was previously termed
‘‘custody transfer’’ in the final rule. It
was not EPA’s intent for the term
‘‘custody transfer’’ to be defined in the
context of ownership of gas transfer.
EPA believes the new definition may be
universally applied to designate which
‘‘metering-regulating stations’’ are
classified as ‘‘transmission-distribution
transfer stations.’’ All covered stations
in the distribution segment will be
collectively referred to as ‘‘meteringregulation stations’’ but the subset that
require leak detection are
‘‘transmission-distribution transfer
stations.’’ EPA was notified of concerns
from industry that defining a
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transmission distribution transfer
station without a threshold would
include numerous small TD transfer
stations that would otherwise not have
been required to perform leak surveys.
EPA has not included any thresholds in
the proposal but we are taking comment
on what an appropriate threshold would
be to exclude these smaller transfer
stations. Such a threshold should
exempt stations with low throughputs
or low emissions. Any threshold should
be readily verifiable and be readily
applied to all stations. Potential options
for a threshold include using the inlet
pressure, the design or actual flow rate
of the station, or other parameters
directly related to the emissions from
the station. Any suggested changes
should include a discussion of how
many stations would be exempted from
leak detection and how many would
still require leak detection. Such an
exemption would not preclude a station
from reporting, it would only mean that
leak detection is not required at that
station. The stations that fall below the
select threshold would still be included
for evaluation against the 25,000mtCO2e
threshold through the application of an
emissions factor. Natural gas
distribution facilities that do not have
any TD transfer stations above the
threshold, would use a factor to
determine their emissions and compare
those emissions against the 25,000
mtCO2e threshold.
Transmission Pipeline. We are
proposing to add a definition for
transmission pipeline. Transmission
pipelines are clearly designated as such
by the Federal Energy Regulatory
Commission for interstate transmission
pipelines, individual States for
intrastate transmission pipelines, and
the Hinshaw exemption under the
Natural Gas Act for Hinshaw
transmission pipelines. We propose to
use this existing mechanism to clearly
demarcate transmission pipelines from
distribution and gathering pipelines.
Finally, we believe that equipment
located on designated transmission
pipelines that are subject to monitoring
under subpart W are easily identifiable
by facility owners or operators.
Tubing Systems. Based on a question
received in the early phases of
implementation, we are proposing to
clarify that the exclusion for piping
equal to or less than one half inch
diameter applies to the nominal pipe
size (NPS).
Vertical Well. With the change from
field level reporting to sub-basin
category, EPA is proposing to add a
distinction for calculating emissions
from horizontal wells and vertical wells.
EPA proposes that a vertical well means
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a well bore that is primarily vertical but
has some unintentional deviation or one
or more intentional deviations to enter
one or more subsurface targets that are
off-set horizontally from the surface
location, intercepting the targets either
vertically or at an angle.
Well Testing Venting and Flaring. We
are proposing to clarify that well testing
venting and flaring means venting and/
or flaring of natural gas at the time the
production rate of a well is determined
(i.e., the well testing) through a choke
(an orifice restriction). If well testing is
conducted immediately after well
completion or workover we are
proposing to clarify that it is considered
part of the well completion or workover.
III. Statutory and Executive Order
Review
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
This action is not a ‘‘significant
regulatory action’’ under the terms of
Executive Order 12866 (58 FR 51735,
October 4, 1993) and is therefore not
subject to review under Executive
Orders 12866 and 13563 (76 FR 3821,
January 21, 2011).
B. Paperwork Reduction Act
This action proposes to simplify the
existing reporting methodologies in
subpart W and clarify monitoring
methodologies and data reporting
requirements. In many cases, the
proposed amendments to the reporting
requirements could potentially reduce
the reporting burden by making the
reporting requirements conform more
closely to current industry practices. In
addition, while the proposed
modification to one of the monitoring
methodologies is not expected to
increase compliance cost, it would
require the reporting of information not
contained in the information collection
requirements to 40 CFR 98 subpart W.
Therefore, the proposed amendments to
the information collection requirements
have been submitted for approval to the
Office of Management and Budget
(OMB) under the Paperwork Reduction
Act, 44 U.S.C. 3501 et seq. The
Information Collection Request (ICR)
document has been assigned EPA ICR
number 2376.03.
The proposed amendments to subpart
I would carry out the Agency’s intent to
require reporting of emissions of all
fluorocarbons used as heat transfer
fluids in the electronics manufacturing
industry. This was the intent of the
subpart I reporting requirements for
HTFs finalized in December 2010 (75 FR
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74774), and this intent was reflected in
the Information Collection Request (ICR)
prepared during that rulemaking. Thus,
the proposed amendments will not
increase EPA or industry burden beyond
that estimated in the ICR.
The Office of Management and Budget
(OMB) has previously approved the
information collection requirements
contained in the existing regulations, 40
CFR 98 subpart W (75 FR 74458), and
40 CFR part 98 subpart I (75 FR 74774),
under the provisions of the Paperwork
Reduction Act, 44 U.S.C. 3501 et seq.
and has assigned OMB control number
2060–0651 and 2060–0650, respectively.
The OMB control numbers for EPA’s
regulations in 40 CFR are listed in 40
CFR part 9.
C. Regulatory Flexibility Act (RFA)
The Regulatory Flexibility Act (RFA)
generally requires an agency to prepare
a regulatory flexibility analysis of any
rule subject to notice and comment
rulemaking requirements under the
Administrative Procedure Act or any
other statute unless the agency certifies
that the rule will not have a significant
economic impact on a substantial
number of small entities. Small entities
include small businesses, small
organizations, and small governmental
jurisdictions.
For purposes of assessing the impacts
of this proposed rule on small entities,
small entity is defined as: (1) A small
business as defined by the Small
Business Administration’s (SBA)
regulations at 13 CFR 121.201; (2) a
small governmental jurisdiction that is a
government of a city, county, town,
school district or special district with a
population of less than 50,000; and (3)
a small organization that is any not-forprofit enterprise which is independently
owned and operated and is not
dominant in its field.
After considering the economic
impacts of today’s proposed rule on
small entities, I certify that this action
will not have a significant economic
impact on a substantial number of small
entities. In determining whether a rule
has a significant economic impact on a
substantial number of small entities, the
impact of concern is any significant
adverse economic impact on small
entities, since the primary purpose of
the regulatory flexibility analyses is to
identify and address regulatory
alternatives ‘‘which minimize any
significant economic impact of the rule
on small entities’’ 5 U.S.C. 603 and 604.
Thus, an agency may certify that a rule
will not have a significant economic
impact on a substantial number of small
entities if the rule relieves regulatory
burden, or otherwise has a positive
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economic effect on all of the small
entities subject to the rule.
This action includes proposed
amendments to provisions in those rules
that could result in reduced burden on
reporters. In some cases, EPA is
proposing to increase flexibility in the
selection of methods use for calculating
GHG’s, and is also proposing to revise
certain methods that may result in
greater conformance to current industry
practices. In addition, in this action,
EPA is proposing to revise specific
provisions to provide clarity on what is
to be reported. Further, in this action,
EPA is also proposing amendments to
clarify the Agency’s intent. These
proposed revisions could overall reduce
burden on reporters while maintaining
the data quality of the information being
reported to EPA. As part of the process
of finalization of the subpart W and
subpart I rules, EPA undertook specific
steps to evaluate the effect of those final
rules on small entities. Based on the
proposed amendments to the subpart W
and subpart I provisions, burden will
stay the same or decrease, therefore
EPA’s determination finding of no
significant economic impact on a
substantial number of small entities has
not changed.
D. Unfunded Mandates Reform Act
(UMRA)
The proposed rule amendments do
not contain a Federal mandate that may
result in expenditures of $100 million or
more for state, local, and tribal
governments, in the aggregate, or the
private sector in any one year. Thus, the
proposed rule amendments are not
subject to the requirements of section
202 and 205 of the UMRA. This rule is
also not subject to the requirements of
section 203 of UMRA because it
contains no regulatory requirements that
might significantly or uniquely affect
small governments.
This action is also not subject to the
requirements of section 203 of UMRA
because it contains no regulatory
requirements that might significantly or
uniquely affect small governments.
Further, the proposed amendments will
not impose any new requirements that
are not currently required for 40 CFR
part 98, and the rule amendments
would not unfairly apply to small
governments.
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
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levels of government, as specified in
Executive Order 13132.
Few, if any, State or local government
facilities would be affected by the
provisions in this proposed rule. This
regulation also does not limit the power
of States or localities to collect GHG
data and/or regulate GHG emissions.
Thus, Executive Order 13132 does not
apply to this action.
In the spirit of Executive Order 13132,
and consistent with EPA policy to
promote communications between EPA
and State and local governments, EPA
specifically solicits comment on this
proposed action from State and local
officials.
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
This action does not have tribal
implications, as specified in Executive
Order 13175 (65 FR 67249, November 9,
2000). During the finalization of subpart
W and subpart I, EPA undertook the
necessary steps to determine the impact
of those rules on tribal entities and
provided supporting documentation
demonstrating the results of the
Agency’s analyses. The proposed rule
amendments in this action do not
impose any significant changes to the
current reporting requirements
contained in 40 CFR part 98 subpart W
and 40 CFR part 98 subpart I. And in
several cases, the proposed amendments
to the reporting requirements would
potentially reduce the reporting burden.
Thus, Executive Order 13175 does not
apply to this action.
Although Executive Order 13175 does
not apply to this action, EPA consulted
tribal officials during the development
of the original actions. A summary of
the concerns raised during the
consultation and EPA’s response to
those concerns is provided in Sections
VIII.E and VIII.F of the preamble to the
2009 final rule and Section IV.F of the
preamble to the 2010 final rule for
subpart W (75 FR 74485). EPA
specifically solicits additional comment
on this proposed action from tribal
officials.
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
EPA interprets Executive Order 13045
(62 FR 19885, April 23, 1997) as
applying only to those regulatory
actions that concern health or safety
risks, such that the analysis required
under section 5–501 of the Executive
Order has the potential to influence the
regulation. This action is not subject to
Executive Order 13045 because it does
not establish an environmental standard
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intended to mitigate health or safety
risks.
H. Executive Order 13211: Actions That
Significantly Affect Energy Supply,
Distribution, or Use
This action is not subject to Executive
Order 13211 (66 FR 28355, May 22,
2001), because it is not a significant
regulatory action under Executive Order
12866.
I. National Technology Transfer and
Advancement Act
Section 12(d) of the National
Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law No.
104–113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus
standards in its regulatory activities
unless to do so would be inconsistent
with applicable law or otherwise
impractical. Voluntary consensus
standards are technical standards (e.g.,
materials specifications, test methods,
sampling procedures, and business
practices) that are developed or adopted
by voluntary consensus standards
bodies. NTTAA directs EPA to provide
Congress, through OMB, explanations
when the Agency decides not to use
available and applicable voluntary
consensus standards.
This proposed rulemaking does not
involve technical standards. Therefore,
EPA is not considering the use of any
voluntary consensus standards.
J. Executive Order 12898: Federal
Actions To Address Environmental
Justice in Minority Populations and
Low-Income Populations
Executive Order 12898 (59 FR 7629,
February 16, 1994) establishes federal
executive policy on environmental
justice. Its main provision directs
federal agencies, to the greatest extent
practicable and permitted by law, to
make environmental justice part of their
mission by identifying and addressing,
as appropriate, disproportionately high
and adverse human health or
environmental effects of their programs,
policies, and activities on minority
populations and low-income
populations in the United States.
EPA has determined that this
proposed rule will not have
disproportionately high and adverse
human health or environmental effects
on minority or low-income populations
because 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.
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List of Subjects in 40 CFR Part 98
Environmental protection,
Administrative practice and procedure,
Greenhouse gases, Incorporation by
reference, Suppliers, Reporting and
recordkeeping requirements.
Dated: August 19, 2011.
Lisa P. Jackson,
Administrator.
temperature. These are snap-acting or
throttling devices that discharge all or a
portion of the full volume of the
actuator intermittently when control
action is necessary, but do not bleed
continuously.
*
*
*
*
*
4. Section 98.7 is amended by
removing paragraph (q).
Subpart I—[Amended]
PART 98—[AMENDED]
§ 98.90
1. The authority citation for part 98
continues to read as follows:
(a) * * *
(5) Any electronics manufacturing
production process in which fluorinated
heat transfer fluids are used to cool
process equipment, to control
temperature during device testing, to
clean substrate surfaces and other parts,
and for soldering (e.g., vapor phase
reflow).
6. Section 98.92 is amended by
revising paragraph (a) introductory text
and paragraph (a)(5) to read as follows:
Subpart A—[Amended]
2. Section 98.1 is amended by adding
paragraph (c) to read as follows:
§ 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 subpart A have the same
definition as Onshore petroleum and
natural gas production owner or
operator, as defined in § 98.238 of this
part.
3. Section 98.6 is amended by revising
the definitions for ‘‘Continuous bleed’’
and ‘‘Intermittent bleed pneumatic
devices’’ to read as follows:
§ 98.6
Definitions.
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*
*
*
*
*
Continuous bleed means a continuous
flow of pneumatic supply gas to the
process control device (e.g., level
control, temperature control, pressure
control) where the supply gas pressure
is modulated by the process condition,
and then flows to the valve controller
where the signal is compared with the
process set-point to adjust gas pressure
in the valve actuator.
*
*
*
*
*
Intermittent bleed pneumatic devices
mean automated flow control devices
powered by pressurized natural gas and
used for automatically maintaining a
process condition such as liquid level,
pressure, delta-pressure, and
§ 98.94 Monitoring and QA/QC
requirements.
*
For the reasons stated in the
preamble, title 40, chapter I, of the Code
of Federal Regulations is proposed to be
amended as follows:
Authority: 42 U.S.C. 7401–7671q.
EHi = Emissions of fluorinated heat
transfer fluids i, (metric tons/year).
*
*
*
*
*
8. Section 98.94 is amended by
revising paragraph (h) introductory text
to read as follows:
5. Section 98.90 is amended by
revising paragraph (a)(5) to read as
follows:
§ 98.92
Definition of the source category.
GHGs to report.
(a) You must report emissions of
fluorinated GHGs (as defined in § 98.6),
N2O, and fluorinated heat transfer fluids
(as defined in § 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–2 to this subpart. You
must individually report, as
appropriate:
*
*
*
*
*
(5) Emissions of fluorinated heat
transfer fluids.
*
*
*
*
*
7. Section 98.93 is amended by
revising paragraph (h) introductory text
and the definition of ‘‘EHi’’ in Equation
I–16 to read as follows.
§ 98.93
Calculating GHG Emissions.
*
*
*
*
*
(h) If you use fluorinated heat transfer
fluids, you must report the annual
emissions of fluorinated heat transfer
fluids using the mass balance approach
described in Equation I–16 of this
subpart.
*
*
*
*
*
*
*
*
*
(h) You must adhere to the QA/QC
procedures of this paragraph (h) when
calculating annual gas consumption for
each fluorinated GHG and N2O used at
your facility and emissions from the use
of fluorinated heat transfer fluids.
*
*
*
*
*
9. Section 98.96 is amended by
revising paragraph (r) to read as follows:
§ 98.96
Data Reporting requirements.
*
*
*
*
*
(r) For heat transfer fluid emissions,
inputs to the heat transfer fluid mass
balance equation, Equation I–16 of this
subpart, for each fluorinated heat
transfer fluid used.
*
*
*
*
*
10. Section 98.98 by removing the
definition of ‘‘Heat transfer fluids’’ and
adding the definition of ‘‘Fluorinated
heat transfer fluids’’ in alphabetical
order to read as follows:
§ 98.98
Definitions.
*
*
*
*
*
Fluorinated heat transfer fluids means
fluorinated GHGs used for temperature
control, device testing, cleaning
substrate surfaces and other parts, and
soldering in certain types of electronics
manufacturing production processes.
For fluorinated heat transfer fluids
under this subpart I, the lower vapor
pressure limit of 1 mm of Hg in absolute
at 25 degrees C in the definition of
Fluorinated greenhouse gas in 40 CFR
98.6 shall not apply. Fluorinated heat
transfer fluids used in the electronics
manufacturing sector include, but are
not limited to, perfluoropolyethers,
perfluoroalkanes, perfluoroethers,
tertiary perfluoroamines, and
perfluorocyclic ethers.
*
*
*
*
*
11. Table I–2 to Subpart I is amended
by revising the title and the second
column heading to read as follows:
TABLE I–2 TO SUBPART I OF PART 98—EXAMPLES OF FLUORINATED GHGS AND FLUORINATED HEAT TRANSFER FLUIDS
USED BY THE ELECTRONICS INDUSTRY
Product type
Fluorinated GHGs and fluorinated heat transfer fluids used during manufacture
Electronics .......................................
CF4, C2F6, C3F8, c-C4F8, c-C4F8O, C4F6, C5F8, CHF3, CH2F2, NF3, SF6, and HTFs (CF3-(O-CF(CF3)-CF2)n(O-CF2)m-O-CF3, CnF2n∂2, CnF2n∂1(O)CmF2m∂1, CnF2nO, (CnF2n∂1)3N).
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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules
Subpart W—[Amended]
12. Section 98.230 is amended by
revising paragraphs (a)(2) through (a)(4),
and (a)(8) to read as follows:
mstockstill on DSK4VPTVN1PROD with PROPOSALS3
§ 98.230
Definition of the source category.
(a) * * *
(2) Onshore petroleum and natural
gas production. Onshore petroleum and
natural gas production means all
equipment on a single well-pad or
associated with a single well-pad
(including but not limited to
compressors, generators, dehydrators,
storage vessels, and portable non-selfpropelled equipment which includes
well drilling and completion
equipment, workover equipment,
gravity separation equipment, auxiliary
non-transportation-related equipment,
and leased, rented or contracted
equipment) used in the production,
extraction, recovery, lifting,
stabilization, separation or treating of
petroleum and/or natural gas (including
condensate). This equipment also
includes associated storage or
measurement vessels and all enhanced
oil recovery (EOR) operations using CO2
or natural gas injection, and all
petroleum and natural gas production
equipment located on islands, artificial
islands, or structures connected by a
causeway to land, an island, or an
artificial island.
(3) Onshore natural gas processing.
Natural gas processing means the
separation of natural gas liquids (NGLs)
or non-methane gases from produced
natural gas, or the separation of NGLs
into one or more component mixtures.
Separation includes one or more of the
following: Forced extraction of natural
gas liquids, sulfur and carbon dioxide
removal, fractionation of NGLs, or the
capture of CO2 separated from natural
gas streams. This segment also includes
all residue gas compression equipment
owned or operated by the natural gas
processing plant. This 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 MMscf per day or greater.
(4) Onshore natural gas transmission
compression. Onshore natural gas
transmission compression means any
stationary combination of compressors
that move natural gas from production
fields, natural gas processing plants, or
other transmission compressors through
transmission pipelines to natural gas
distribution pipelines, LNG storage
facilities, or into underground storage.
In addition, a transmission compressor
station includes equipment for liquids
separation, and tanks for the storage of
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water and hydrocarbon liquids. Residue
(sales) gas compression that is part of
onshore natural gas processing plants
are included in the onshore natural gas
processing segment and are excluded
from this segment.
*
*
*
*
*
(8) Natural gas distribution. Natural
gas distribution means the distribution
pipelines and metering and regulating
equipment at metering-regulating
stations that are operated by a Local
Distribution Company (LDC) within a
single state that is regulated as a
separate operating company by a public
utility commission or that is operated as
an independent municipally-owned
distribution system. This segment also
excludes customer meters and
regulators, infrastructure, and pipelines
(both interstate and intrastate)
delivering natural gas directly to major
industrial users and farm taps upstream
of the local distribution company inlet.
*
*
*
*
*
13. Section 98.232 is amended by:
a. Revising paragraph (c) introductory
text and paragraph (c)(22).
b. Revising paragraph (e) introductory
text.
c. Revising paragraph (f) introductory
text.
d. Revising paragraph (g) introductory
text.
e. Revising paragraph (h) introductory
text.
f. Revising paragraph (i) introductory
text and paragraph (i)(1).
g. Redesignating paragraphs (i)(2)
through (i)(6) as paragraphs (i)(3)
through (i)(7), respectively.
h. Revising newly designated
paragraphs (i)(3) and (i)(4).
i. Adding new paragraph (i)(2).
j. Removing and reserving paragraph
(j).
k. Revising paragraph (k).
The revisions read as follows:
§ 98.232
GHGs to report.
*
*
*
*
*
(c) For an onshore petroleum and
natural gas production facility, report
CO2, CH4, and N2O emissions from only
the following source types on a single
well-pad or associated with a single
well-pad:
*
*
*
*
*
(22) You must use the methods in
§ 98.233(z) and report under this
subpart the emissions of CO2, CH4, and
N2O from stationary or portable fuel
combustion equipment that cannot
move on roadways under its own power
and drive train, and that is located at an
onshore petroleum and natural gas
production facility as defined in
§ 98.238. Stationary or portable
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56039
equipment are the following equipment,
which are integral to the extraction,
processing, or movement of oil or
natural gas: well drilling and
completion equipment, workover
equipment, natural gas dehydrators,
natural gas compressors, electrical
generators, steam boilers, and process
heaters.
*
*
*
*
*
(e) For onshore natural gas
transmission compression, report CO2,
CH4, and N2O emissions from the
following sources:
*
*
*
*
*
(f) For underground natural gas
storage, report CO2, CH4, and N2O
emissions from the following sources:
*
*
*
*
*
(g) For LNG storage, report CO2, CH4,
and N2O emissions from the following
sources:
*
*
*
*
*
(h) LNG import and export
equipment, report CO2, CH4, and N2O
emissions from the following sources:
*
*
*
*
*
(i) For natural gas distribution, report
CO2, CH4, and N2O emissions from the
following sources:
(1) Meters, regulators, and associated
equipment at above grade transmissiondistribution transfer stations, including
equipment leaks from connectors, block
valves, control valves, pressure relief
valves, orifice meters, regulators, and
open ended lines.
(2) Equipment leaks from vaults at
below grade transmission-distribution
transfer stations.
(3) Meters, regulators, and associated
equipment at above grade meteringregulating station.
(4) Equipment leaks from vaults at
below grade metering-regulating
stations.
*
*
*
*
*
(j) [Reserved].
(k) Report under subpart C of this part
(General Stationary Fuel Combustion
Sources) the emissions of CO2, CH4, and
N2O from each stationary fuel
combustion unit by following the
requirements of subpart C except for
facilities under onshore petroleum and
natural gas production and natural gas
distribution. Onshore petroleum and
natural gas production facilities must
report stationary and portable
combustion emissions as specified in
paragraph (c) of this section. Natural gas
distribution facilities must report
stationary combustion emissions as
specified in paragraph (i) of this section.
14. Section 98.233 is amended by:
a. In paragraph (a), revising Equation
W–1 and the definitions of ‘‘Count’’ and
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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules
*
*
*
*
*
*
*
*
GHGi = For onshore petroleum and natural
gas production facilities, onshore natural
gas transmission compression, and
mstockstill on DSK4VPTVN1PROD with PROPOSALS3
*
*
*
*
*
GHGi = Concentration of GHGi, CH4, or CO2,
in produced natural gas as defined in
paragraph (u)(2)(i) of this section.
*
*
*
*
*
T = Total number of hours in the operating
year the pumps were operational.
*
*
*
*
*
(d) Acid gas removal (AGR) vents. For
AGR vent (including processes such as
amine, membrane, molecular sieve or
other absorbents and adsorbents),
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underground natural gas storage,
concentration of GHGi, CH4, or CO2, in
natural gas as defined in paragraph
(u)(2)(i) of this section.
*
Count = Total number of continuous high
bleed, continuous low bleed, or
intermittent bleed natural gas pneumatic
devices of each type as determined in
paragraph (a)(1) and (a)(2) of this section.
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*
*
*
*
*
T = Total number of hours in the
operating year the devices were
operational.
*
*
*
*
*
calculate emissions for CO2 only (not
CH4) vented directly to the atmosphere
or through a flare, 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
methodologies described in paragraph
(d) of this section, as applicable.
*
*
*
*
*
(1) Calculation Methodology 1. If you
operate and maintain a CEMS that has
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dd. Redesignating paragraph (n)(9) as
paragraph (n)(10) and adding new
paragraphs (n)(9) and (n)(11).
ee. In paragraph (o)(6), revising the
definition of ‘‘MTm’’ in Equation W–24.
ff. In paragraph (p)(7)(i), revising the
definition of ‘‘MTm’’ in Equation W–28.
gg. In paragraph (q), revising equation
W–30 and the definitions for ‘‘x’’, ‘‘EF’’,
‘‘GHGi’’, ‘‘Tp’’, and revising paragraph
(q)(8).
hh. In paragraph (r), revising the
definitions of ‘‘Counts’’, ‘‘EFs’’, and
‘‘GHGi’’ in Equation W–31.
ii. Revising paragraphs (r)(2)(i)(A),
(r)(6)(i), (r)(6)(ii) introductory text,
Equation W–32, and the definitions of
Equation W–32.
jj. Revising introductory texts for
paragraphs (t), (t)(1), and (t)(2).
kk. Revising paragraph (u)
introductory text and paragraph (u)(2).
ll. In paragraph (v), revising paragraph
(v) introductory text and the definitions
of ‘‘Masss,i’’, ‘‘Es,i’’, and ‘‘ri’’ in Equation
W–36.
mm. Revising introductory texts for
paragraphs (z), (z)(1), (z)(2), (z)(2)(i), and
(z)(2)(ii).
nn. Adding paragraphs (z)(1)(i) and
(z)(1)(ii).
The revisions read as follows:
§ 98.233
Calculating GHG emissions.
(a) * * *
(3) For all industry segments,
determine the type of pneumatic device
using engineering estimates based on
best available information.
*
*
*
*
*
(c) * * *
both a CO2 concentration monitor and
volumetric flow rate monitor, you must
calculate CO2 emissions under this
subpart by following the Tier 4
Calculation Methodology and all
associated calculation, quality
assurance, reporting, and recordkeeping
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources). If a CO2
concentration monitor and volumetric
flow rate monitor are not available, you
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EP09SE11.001
*
q. Removing paragraphs (g)(1)(i)(A)
through (g)(1)(i)(D).
r. In paragraph (g)(1)(ii), revising
paragraph (g)(1)(ii) introductory text;
redesignating Equation W–11 as
Equation W–11A and Equation W–12 as
Equation W–11B respectively; and
adding Equation W–11C.
s. Redesignating paragraphs
(g)(1)(ii)(A) through (g)(1)(ii)(B) as
paragraphs (g)(1)(iii) through (g)(1)(v)
and revising new paragraphs (g)(1)(iii)
through (g)(1)(v).
t. Removing paragraph (g)(1)(ii)(D).
u. Revising introductory texts for
paragraphs (g)(3) and (g)(5).
v. In paragraph (h), revising paragraph
(h) introductory text and the definitions
of ‘‘Nwo’’, ‘‘f’’, ‘‘Vp’’ and ‘‘Tp’’ in
Equation W–13.
w. Revising paragraph (i) introductory
text and paragraphs (i)(1) and (i)(2).
x. In paragraph (i)(3), revising
paragraph (i)(3) introductory text;
redesignating Equation W–14 as
Equation W–14A; revising the definition
of ‘‘N’’ in newly redesignated Equation
W–14A; and adding Equation W–14B.
y. Revising paragraph (i)(5).
z. Revising paragraph (j)(1)(vii)(B),
(j)(1)(vii)(C), and (j)(3)(i).
aa. Revising paragraphs (k)(1) and
(k)(2)(i).
bb. Revising paragraph (m)(1).
cc. Revising paragraph (n)(2)(ii) and
(n)(2)(iii), and in paragraph (n)(4),
revising equation W–21 and the
definition for ‘‘Yj’’.
EP09SE11.000
‘‘GHGi’’ in Equation W–1; and adding
the definition of ‘‘T’’ in Equation W–1.
b. Adding paragraph (a)(3).
c. In paragraph (c), revising Equation
W–2 and the definition of ‘‘GHGi’’; and
adding the definition of ‘‘T’’ in Equation
W–2.
d. Revising paragraphs (d)
introductory text and (d)(1).
e. In paragraph (d)(3), revising
Equation W–4 and removing the
definition of ‘‘a’’ in Equation W–4.
f. Revising paragraph (e)(1)(vii).
g. Revising the definition of ‘‘1000’’ in
Equation W–5 of paragraph (e)(2).
h. Revising paragraph (e)(6).
i. Revising paragraphs (f) introductory
text, (f)(1) introductory text, and the
definitions of Equation W–7 in
paragraph (f)(1).
j. Revising paragraphs (f)(1)(i)(A)
through (f)(1)(i)(C).
k. In paragraph (f)(2), revising
Equation W–8 and the definitions of
Equation W–8.
l. Removing paragraphs (f)(2)(i) and
(f)(2)(ii).
m. In paragraph (f)(3), revising
Equation W–9 and the definitions of
Equation W–9.
n. Removing paragraphs (f)(3)(i) and
(f)(3)(ii).
o. In paragraph (g), revising Equation
W–10 and the definitions of Equation
W–10.
p. Revising introductory texts for
paragraphs (g)(1) and (g)(1)(i).
Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules
56041
may elect to install a CO2 concentration
monitor and a volumetric flow rate
monitor that comply with all of the
requirements specified for the Tier 4
Calculation Methodology in subpart C of
this part (General Stationary Fuel
Combustion). The calculation and
reporting of CH4 and N2O emissions is
not required as part of the Tier 4
requirements for AGRs.
*
*
*
*
*
(3) * * *
*
(1) Calculation Methodology 1. For
one well of each unique well tubing
diameter grouping and pressure
grouping in each sub-basin category (see
§ 98.238 for the definitions of tubing
diameter grouping, pressure grouping,
and sub-basin category), where gas wells
are vented to the atmosphere to expel
liquids accumulated in the tubing, a
recording flow meter shall be installed
on the vent line used to vent gas from
the well (e.g., on the vent line off the
wellhead separator or atmospheric
storage tank) according to methods set
forth in § 98.234(b). Calculate emissions
from well venting for liquids unloading
using Equation W–7 of this section.
*
*
*
*
*
h = Total number of different tubing diameter
groupings.
p = Tubing diameter grouping 1 through h.
t = Total number of pressure groupings.
q = Pressure grouping 1 through t.
*
*
*
*
(e) * * *
(1) * * *
(vii) Use of stripping gas.
*
*
*
*
*
(2)
*
*
*
*
*
1000 = Conversion of EFi in thousand
standard cubic feet to cubic feet.
*
*
*
*
*
(6) For glycol dehydrators, both CH4
and CO2 mass emissions shall be
calculated from volumetric GHGi
emissions using calculations in
paragraph (v) of this section. For
dehydrators that use desiccant, both
CH4 and CO2 volumetric and mass
emissions shall be calculated from
volumetric natural gas emissions using
calculations in paragraphs (u) and (v) of
this section.
*
*
*
*
*
(f) Well venting for liquids
unloadings. Calculate CO2 and CH4
emissions from well venting for liquids
unloading using one of the calculation
methodologies described in paragraphs
(f)(1), (f)(2), or (f)(3) of this section.
Ea,n = Annual natural gas emissions for wells
of the same tubing diameter grouping
and pressure grouping at actual
conditions in cubic feet.
Th,t = Cumulative amount of time in hours of
venting from all wells of the same tubing
diameter grouping p and pressure
grouping q during the year.
FRh,t = Average flow rate in cubic feet per
hour of a measured well venting for the
duration of the liquids unloading, under
actual conditions as determined in
paragraph (f)(1)(i) of this section.
*
*
*
*
*
(i) * * *
(A) The average flow rate per hour of
venting is calculated for each unique
tubing diameter grouping and pressure
grouping in each sub-basin category by
dividing the recorded total flow by the
recorded time (in hours) for a single
liquid unloading with venting to the
atmosphere.
(B) This average flow rate per hour is
applied to all wells in the same pressure
grouping that have the same tubing
diameter grouping, for the number of
hours of venting these wells.
(C) A new average flow rate is
calculated every other calendar year for
each reporting sub-basin category
starting the first calendar year of data
collection. For a new producing subbasin category, an average flow rate is
calculated beginning in the first year of
production.
(2) * * *
HRQ,PW = Hours that each well,p, was left
open to the atmosphere during
unloading, q.
1.0 = Hours for average well to blowdown
casing volume at shut-in pressure.
ZQ,P = If HRQ,P is less than 1.0 then ZQ,P is
equal to 0. If HRQ,P is greater than or
equal to 1.0 then ZQ,P is equal to 1.
(3) * * *
Where:
Es,n = Annual natural gas emissions at
standard conditions, in cubic feet/year.
W = Total number of wells with well venting
for liquids unloading at the facility.
0.37×10¥3 = {3.14 (pi)/4}/{14.7*144} (psia
converted to pounds per square feet).
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WDP = Well depth from the lowest packer to
the bottom of the well, in feet.
SPP = Shut-in pressure for each well, p, in
pounds per square inch atmosphere
(psia).
VP = Number of vents per year per well, p.
SFRP = Average sales flow rate of gas well,
p, at standard conditions in cubic feet
per hour. Use Equation W–33 to
calculate the sales flow rate at standard
conditions.
EP09SE11.002
mstockstill on DSK4VPTVN1PROD with PROPOSALS3
Where:
Es,n = Annual natural gas emissions at
standard conditions, in cubic feet/year.
W = Total number of wells with well venting
for liquids unloading at the facility.
0.37×10¥3 = {3.14 (pi)/4}/{14.7*144} (psia
converted to pounds per square feet).
CDP = Casing diameter for each well, p, in
inches.
56042
Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules
TDP = Tubing diameter for each well, p,in
inches.
WDP = Tubing depth to plunger bumper for
each well, p, in feet.
SPP = Sales line pressure for each well, p, in
pounds per square inch atmospheric
(psia).
VP = Number of vents per year for each well,
p.
SFRP = Average sales flow rate of each gas
well, p, at standard conditions in cubic
feet per hour. Use Equation W–33 to
calculate the sales flow rate at standard
conditions.
HRQ,P = Hours that each well, p, was left
open to the atmosphere during each
unloading, q.
0.5 = Hours for average well to blowdown
tubing volume at sales line pressure.
ZQ,P = If HRQ,P is less than 0.5 then ZQ,P is
equal to 0. If HRQ,P is greater than or
equal to 0.5 then ZQ,P is equal to 1.
Where:
Es,n = Annual volumetric total gas emissions
in cubic feet at standard conditions from
gas well venting during completions or
workovers following hydraulic fracturing
for each sub-basin and well type
combination.
Tp = Cumulative amount of time in hours of
each well (p) completion or workover
venting in a sub-basin and well type
combination during the reporting year.
FRM = Venting to 30-day production ratio
from Equation W–12.
PRp = First 30-day average production flow
rate in standard cubic feet per hour of
each well (p), under actual conditions,
converted to standard conditions, as
required in paragraph (g)(1) of this
section.
EnFp = Volume of CO2 or N2 injected gas in
cubic feet at standard conditions that
was injected into the reservoir during an
energized fracture job for each well (p).
If the fracture process did not inject gas
into the reservoir, then EnF is 0. If
injected gas is CO2, then EnF is 0.
SGp = Volume of natural gas in cubic feet at
standard conditions that was recovered
into a sales pipeline for well p as per
paragraph (g)(3) of this section. If no gas
was recovered for sales, SG is 0.
W = Total number of wells completed or
worked over using hydraulic fracturing
in a sub-basin and well type
combination.
combination, a recording flow meter
(digital or analog) shall be installed on
the vent line, ahead of a flare if used,
to measure the backflow venting
according to methods set forth in
§ 98.234(b).
(ii) Calculation Methodology 2. For
one horizontal well completion and one
vertical well completion in each gas
producing sub-basin category and for
one well horizontal workover and one
vertical well workover in each gas
producing sub-basin category, record
the well flowing pressure upstream (and
downstream in subsonic flow) of a well
choke according to methods set forth in
§ 98.234(b) to calculate the intermittent
well flow rate of gas during venting to
the atmosphere or a flare. Calculate
emissions using Equation W–11A of this
section for subsonic flow or Equation
W–11B of this section for sonic flow.
Use Equation W–11C of this section to
determine whether flow is sonic or
subsonic. If the value of R in Equation
W–11C is greater than or equal to 2,
then flow is sonic; otherwise, flow is
subsonic:
*
*
*
*
3430 = Constant with units of m2/(sec2 * K).
1.27*105 = Conversion from m3/second to
ft3/hour.
Where:
FR = Average flow rate in cubic feet per hour,
under sonic flow conditions.
A = Cross sectional area of orifice (m2).
Tu = Upstream temperature (degrees Kelvin).
187.08 = Constant with units of m2/(sec2 * K).
1.27*105 = Conversion from m3/second to
ft3/hour.
EP09SE11.006
A = Cross sectional area of orifice (m2).
P1 = Upstream pressure (psia).
Tu = Upstream temperature (degrees Kelvin).
P2 = Downstream pressure (psia).
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Where:
FR = Average flow rate in cubic feet per hour,
under subsonic flow conditions.
EP09SE11.008
(g) * * *
EP09SE11.007
(1) The average flow rate for gas well
venting to the atmosphere or to a flare
during well completions and workovers
from hydraulic fracturing shall be
determined using measurement(s) from
either of the calculation methodologies
described in this paragraph (g)(1) of this
section. The number of measurements
shall be determined as follows: One
measurement for less than or equal to 25
completions/workovers; two
measurements for 26 to 50 completions/
workovers; three measurements for 51 to
100 completions/workovers; four
measurements for 101 to 250
completions/workovers; and five
measurements for greater than 250
completions/workovers.
(i) Calculation Methodology 1. For
well completion(s) in each gas
producing sub-basin category and well
type (horizontal or vertical) combination
and for one well workover(s) in each gas
producing sub-basin category and well
type (horizontal or vertical)
*
Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules
56043
Where:
R = Pressure ratio
P1 = Pressure upstream of the restriction
orifice in pounds per square inch
absolute.
P2 = Pressure downstream of the restriction
orifice in pounds per square inch
absolute.
(iii) The emissions to 30-day production
ratio is calculated using Equation W–12 of
this section.
Where:
FRM = Emissions to 30-day production ratio.
FRp = Measured flow rate from Calculation
Methodology 1 or estimated flow rate
from Calculation Methodology 2 in
standard cubic feet per hour for well(s)
p for each sub-basin and well type
(horizontal or vertical) combination.
PRp = First 30-day production rate in
standard cubic feet per hour for each
well p that was measured in the subbasin and well type combination.
W = Number of wells completed or worked
over using hydraulic fracturing in a subbasin and well type formation.
(3) The volume of recovered
completion or workover gas sent to a
sales line will be measured using
existing company records. If data does
not exist on sales gas, then an
appropriate meter as described in
§ 98.234(b) may be used.
*
*
*
*
*
(5) Determine if the well completion
or workover from hydraulic fracturing
recovered gas with purpose designed
equipment that separates saleable gas
from the backflow, and sent this gas to
a sales line (e.g., reduced emissions
completions or workovers).
*
*
*
*
*
(h) Gas well venting during
completions and workovers without
hydraulic fracturing. Calculate CH4, CO2
and N2O (when flared) emissions from
each gas well venting during well
completions and workovers not
involving hydraulic fracturing using
Equation W–13 of this section:
*
*
*
*
*
the current and following calendar years
shall be used.
Tp = Time each well completion without
hydraulic fracturing, p, was venting in
hours during the year.
*
*
*
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*
Vv = Total volume of blowndown equipment
chambers (including pipelines,
*
17:00 Sep 08, 2011
compressors and vessels) between
isolation valves in cubic feet.
*
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Where:
Nwo = Number of workovers per sub-basin
not involving hydraulic fracturing in the
reporting year.
f = Total number of well completions without
hydraulic fracturing in a sub-basin
category.
Vp = Average daily gas production rate in
cubic feet per hour for each well
completion without hydraulic fracturing,
p. This is the total annual gas production
volume divided by total number of hours
the wells produced to the sales line. For
completed wells that have not
established a production rate, you may
use the average flow rate from the first
30 days of production. In the event that
the well is completed less than 30 days
from the end of the calendar year, the
first 30 days of the production straddling
*
*
*
*
(i) Blowdown vent stacks. Calculate
CO2 and CH4 blowdown vent stack
emissions from depressurizing
equipment to reduce system pressure for
planned or emergency shutdowns or to
take equipment out of service for
maintenance (excluding depressurizing
to a flare, over-pressure relief, operating
pressure control venting and blowdown
of non-GHG gases; desiccant dehydrator
blowdown venting before reloading is
covered in paragraph (e)(5) of this
section) as follows:
(1) Calculate the total physical
volume (including pipelines,
compressor case or cylinders,
manifolds, suction bottles, discharge
bottles, and vessels) between isolation
valves determined by engineering
estimates based on best available data.
(2) If the total physical volume
between isolation valves is greater than
or equal to 50 cubic feet, retain logs of
the number of blowdowns for each
unique physical volume type (including
but not limited to compressors, vessels,
pipelines, headers, fractionators, and
tanks). Physical volumes smaller than
50 standard cubic feet are exempt from
reporting under paragraph (i) of this
section.
(3) Calculate the total annual venting
emissions for each equipment type
using either Equation W–14A or W–14B
of this section.
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(iv) The flow rates for horizontal and
vertical wells are applied to all
horizontal and vertical well completions
in the gas producing sub-basin and well
type combination and to all horizontal
and vertical well workovers,
respectively, in the gas producing subbasin and well type combination for the
total number of hours of venting of each
of these wells.
(v) New flow rates for horizontal and
vertical gas well completions and
horizontal and vertical gas well
workovers in each sub-basin category
shall be calculated once every two years
starting in the first calendar year of data
collection.
(2) The volume of CO2 or N2 injected
into the well reservoir during energized
hydraulic fractures will be measured
using an appropriate meter as described
in § 98.234(b) or using receipts of gas
purchases that are used for the
energized fracture job.
(i) Calculate gas volume at standard
conditions using calculations in
paragraph (t) of this section.
(ii) [Reserved].
*
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(5) Calculate total annual venting
emissions for all blowdown vent stacks
by adding all standard volumetric and
mass emissions determined using
Equations W–14A or W–14B and
paragraph (i)(4) of this section.
(j) * * *
(1) * * *
(vii) * * *
(B) If separator oil 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.
(C) Analyze a representative sample of
separator oil in each sub-basin category
*
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*
*
*
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Yj = Mole fraction of gas hydrocarbon
constituents j (such as methane, ethane,
propane, butane, and pentanes-plus)
*
*
*
*
*
(9) If you operate and maintain a
CEMS that has both a CO2 concentration
monitor and volumetric flow rate
monitor, you must calculate CO2
emissions for the flare by following the
Tier 4 Calculation Methodology and all
associated calculation, quality
assurance, reporting, and recordkeeping
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continuous leakage, this serves as the
measurement.
(m) * * *
(1) Determine the GOR of the
hydrocarbon production from each well
whose associated natural gas is vented
or flared. If GOR from each well is not
available, the GOR from a cluster of
wells in the same sub-basin category
shall be used.
*
*
*
*
*
(n) * * *
(2) * * *
(ii) For onshore natural gas
processing, when the stream going to
flare is natural gas, use the GHG mole
percent in feed natural gas for all
streams upstream of the de-methanizer
or dew point control, and GHG mole
percent 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.
(iii) For any applicable industry
segment, when the stream going to the
flare is a hydrocarbon product stream,
such as methane, ethane, propane,
butane, pentane-plus and mixed light
hydrocarbons, then you may use a
representative composition from the
source for the stream determined by
engineering calculation based on
process knowledge and best available
data.
*
*
*
*
*
(n) * * *
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources). If a CEMS is used
to calculate flare stack emissions, the
requirements specified in paragraphs
(n)(1) through (n)(7) are not required. If
a CO2 concentration monitor and
volumetric flow rate monitor are not
available, you may elect to install a CO2
concentration monitor and a volumetric
flow rate monitor that comply with all
of the requirements specified for the
Tier 4 Calculation Methodology in
subpart C of this part (General
Stationary Fuel Combustion).
(10) The flare emissions determined
under paragraph (n) of this section must
be corrected for flare emissions
calculated and reported under other
paragraphs of this section to avoid
double counting of these emissions.
(11) If source types in § 98.233 use
Equations W–19 through W–21 of this
section, use estimate of emissions under
actual conditions for the parameter, Va,
in these equations.
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*
for oil composition and Reid vapor
pressure using an appropriate standard
method published by a consensus-based
standards organization.
*
*
*
*
*
(3) * * *
(i) If well production oil and gas
compositions are available through your
previous analysis, select the latest
available analysis that is representative
of produced oil and gas from the subbasin category and assume all of the CH4
and CO2 in both oil and gas are emitted
from the tank.
*
*
*
*
*
(k) * * *
(1) Monitor the tank vapor vent stack
annually for emissions using an optical
gas imaging instrument according to
methods set forth in § 98.234(a)(1) or by
directly measuring the tank vent using
a flow meter, calibrated bag, or high
volume sampler according to methods
in § 98.234(b) through (d) for a duration
of 5 minutes. Or you may annually
monitor leakage through compressor
scrubber dump valve(s) into the tank
using an acoustic leak detection device
according to methods set forth in
§ 98.234(a)(5).
(2) * * *
(i) Use a meter, such as a turbine
meter, calibrated bag, or high flow
sampler to estimate tank vapor volumes
according to methods set forth in
§ 98.234(b) through (d). If you do not
have a continuous flow measurement
device, you may install a flow
measuring device on the tank vapor vent
stack. If the vent is directly measured
for five minutes under paragraph
§ 98.233(k)(1) of this section to detect
EP09SE11.011
Where:
Es,n = Annual natural gas venting emissions
at standard conditions from blowdowns
in cubic feet.
N = Number of repetitive blowdowns for
each unique volume in calendar year.
Vv = Total volume of blowdown equipment
chamber (including pipelines,
compressors and vessels) between
isolation valves in cubic feet for each
blowdown ‘‘i.’’
C = Purge factor that is 1 if the equipment
is not purged or zero if the equipment is
purged using non-GHG gases.
Ts = Temperature at standard conditions (°F).
Ta = Temperature at actual conditions in the
blowdown equipment chamber (°F) for
each blowdown ‘‘i’’.
Ps = Absolute pressure at standard conditions
(psia).
Pa,s,p = Absolute pressure at actual conditions
in the blowdown equipment chamber
(psia) at the start of the blowdown ‘‘p’’.
Pa,e,p = Absolute pressure at actual conditions
in the blowdown equipment chamber
(psia) at the end of the blowdown ‘‘p’’;
0 if blowdown volume is purged using
non-GHG gases.
Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules
*
*
*
*
*
*
*
*
*
*
*
*
x = Total number of each equipment leak
source.
*
*
*
*
*
GHGi = For onshore natural gas processing
facilities, concentration of GHGi, CH4 or
CO2, in the total hydrocarbon of the feed
natural gas; 98.230(a)(4) and (a)(5), GHGi
equals 0.974 for CH4 and 1.0 × 10¥2 for
CO2; for facilities listed in § 98.230(a)(6)
and (a)(7), GHGi equals 1 for CH4 and 0
for CO2; and for facilities listed in
§ 98.230(a)(8), GHGi equals 1 for CH4 and
1.1 × 10¥2 CO2.
Tp = The total time the component, p, was
found leaking and operational, in hours.
If one leak detection survey is
conducted, assume the component was
leaking for the entire calendar year. If
multiple leak detection surveys are
conducted, assume that the component
found to be leaking has been leaking
since the previous survey or the
beginning of the calendar year. For the
last leak detection survey in the calendar
year, assume that all leaking components
continue to leak until the end of the
calendar year.
*
*
*
*
*
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(8) Natural gas distribution facilities
for above grade transmissiondistribution transfer stations, shall use
the appropriate default leaker emission
factors listed in Table W–7 of this
subpart for equipment leak detected
from connectors, block valves, control
valves, pressure relief valves, orifice
meters, regulators, and open ended
lines. Leak detection at natural gas
distribution facilities is only required at
above grade stations that qualify as
transmission-distribution transfer
Where:
EFi = Facility emission factor for a meter/
regulator run at above grade meteringregulating for GHGi in cubic feet per
meter/regulator run per hour.
Es,i = Annual volumetric GHG i emissions,
CO2 or CH4 at standard condition from
all equipment leak sources at all above
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*
*
*
(p) * * *
(7) * * *
(i) * * *
MTm = Flow Measurements from all
centrifugal compressor vents in each
*
*
*
*
*
*
Counts = Total number of this type of
emission source at the facility. For
onshore petroleum and natural gas
production, average component counts
are provided by major equipment piece
in Tables W–1B and Table W–1C of this
subpart. Use average component counts
as appropriate for operations in Eastern
and Western U.S., according to Table W–
1D of this subpart. Underground natural
gas storage shall count the components
listed for population emission factors in
Table W–4. LNG Storage shall count the
number of vapor recovery compressors.
LNG import and export shall count the
number of vapor recovery compressors.
Natural gas distribution shall count the
respective component for each emission
factor as described in paragraph (r)(6) of
this section.
EFs = Population emission factor for the
specific source, as listed in Table W–1A
and Tables W–3 through Table W–7 of
this subpart. Use appropriate population
emission factor for operations in Eastern
and Western U.S., according to Table W–
1D of this subpart. EF for meter/regulator
runs at above grade metering-regulating
stations is determined in Equation W–32
of this section.
GHGi = For onshore petroleum and natural
gas production facilities, concentration of
GHGi, CH4 or CO2, in produced natural gas;
for other facilities listed in § 98.230(a)(4) and
(a)(5), GHGi equals 0.952 for CH4 and 1.0 ×
grade TD transfer stations, from
paragraph (q) of this section.
Count = Total number of meter/regulator
runs at all TD transfer stations.
8760 = Conversion to hourly emissions
*
*
*
*
(t) Volumetric emissions. Calculate
volumetric emissions at standard
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*
*
*
*
*
*
*
(q) * * *
stations. Below grade transmissiondistribution transfer stations and
metering-regulating stations that do not
meet the definition of transmissiondistribution transfer stations are not
required to perform component leak
detection under this section.
(r) * * *
*
*
*
*
*
*
MTm = Meter readings from all reciprocating
compressor vents in each and mode, m,
in standard cubic feet per hour.
Frm 00037
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*
10¥2 for CO2; for facilities listed in
§ 98.230(a)(6) and (a)(7), GHGi equals 1 for
CH4 and 0 for CO2; and for facilities listed in
§ 98.230(a)(8), GHGi equals 1 for CH4 and 1.1
× 10¥2 CO2.
*
*
*
*
*
(2) * * *
(i) * * *
(A) Count all major equipment listed
in Table W–1B and Table W–1C of this
subpart. For meters/piping, use one
meters/piping per well-pad.
*
*
*
*
*
(6) * * *
(i) Below grade metering-regulating
stations (including below grade T–D
transfer stations); distribution mains;
and distribution services, shall use the
appropriate default population emission
factors listed in Table W–7 of this
subpart.
(ii) Emissions from all above grade
metering-regulating stations (including
above grade TD transfer stations) shall
be calculated by applying the emission
factor calculated in Equation W–32 and
the total count of meter/regulator runs at
all above grade metering-regulating
stations (inclusive of TD transfer
stations) to Equation W–31. The facility
wide emission factor in Equation W–32
will be calculated by using the total
volumetric GHG emissions at standard
conditions for all equipment leak
sources calculated in paragraph (q)(8) of
this section and the count of meter/
regulator runs located at above grade
transmission-distribution transfer
stations.
conditions as specified in paragraphs
(t)(1) or (2) of this section, with actual
pressure and temperature determined by
engineering estimates based on best
available data unless otherwise
specified.
(1) Calculate natural gas volumetric
emissions at standard conditions using
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*
mode in (o)(1)(i) through (o)(1)(iii) of this
section in standard cubic feet per hour.
EP09SE11.013
(o) * * *
(6) * * *
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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules
actual natural gas emission temperature
and pressure, and Equation W–33 of this
section.
*
*
*
*
*
(2) Calculate GHG volumetric
emissions at standard conditions using
actual GHG emissions temperature and
pressure, and Equation W–34 of this
section.
*
*
*
*
*
(u) GHG volumetric emissions.
Calculate GHG volumetric emissions at
standard conditions as specified in
paragraphs (u)(1) and (2) of this section,
with mole fraction of GHGs in the
natural gas determined by engineering
estimate based on best available data
unless otherwise specified.
*
*
*
*
*
(2) For Equation W–35 of this section,
the mole fraction, Mi, shall be the
annual average mole fraction for each
sub-basin category or facility, as
specified in paragraphs (u)(2)(i) through
(vii) of this section.
(i) GHG mole fraction in produced
natural gas for onshore petroleum and
natural gas production facilities. If you
have a continuous gas composition
analyzer for produced natural gas, you
must use an annual average of these
values for determining the mole
fraction. If you do not have a continuous
gas composition analyzer, then you
must use an annual average gas
composition based on available analyses
in each of the sub-basin categories.
(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 § 98.234(b).
(iii) GHG mole fraction in
transmission pipeline natural gas that
passes through the facility for onshore
natural gas transmission compression
facilities. You may use a default 95
percent methane and 1 percent carbon
dioxide fraction for GHG mole fraction
in natural gas.
(iv) GHG mole fraction in natural gas
stored in underground natural gas
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storage facilities. You may use a default
95 percent methane and 1 percent
carbon dioxide fraction for GHG mole
fraction in natural gas.
(v) GHG mole fraction in natural gas
stored in LNG storage facilities. You
may use a default 95 percent methane
and 1 percent carbon dioxide fraction
for GHG mole fraction in natural gas.
(vi) GHG mole fraction in natural gas
stored in LNG import and export
facilities. For export facilities that
receive gas from transmission pipelines,
you may use a default 95 percent
methane and 1 percent carbon dioxide
fraction for GHG mole fraction in
natural gas.
(vii) GHG mole fraction in local
distribution pipeline natural gas that
passes through the facility for natural
gas distribution facilities. You may use
a default 95 percent methane and 1
percent carbon dioxide fraction for GHG
mole fraction in natural gas.
(v) GHG mass emissions. Calculate
GHG mass emissions in carbon dioxide
equivalent at standard conditions by
converting the GHG volumetric
emissions at standard conditions into
mass emissions using Equation W–36 of
this section.
*
*
*
*
*
Masss,i = GHG i (either CH4, CO2, or N2O)
mass emissions at standard conditions in
metric tons CO2e.
Es,i = GHG i (either CH4, CO2, or N2O)
volumetric emissions at standard
conditions, in cubic feet.
ri = Density of GHG i. Use 0.0520 kg/ft3 for
CO2 and N2O, and 0.0190 kg/ft3 for CH4
at 68 °F and 14.7 psia or 0.0530 kg/ft3
for CO2 and N2O, and 0.0193 kg/ft3 for
CH4 at 60 °F and 14.7 psia.
*
*
*
*
*
(z) Onshore petroleum and natural
gas production and natural gas
distribution combustion emissions.
Calculate CO2, CH4, and N2O
combustion-related emissions from
stationary or portable equipment, except
as specified in paragraph (z)(3) of this
section, as follows:
(1) If a fuel combusted in the
stationary or portable equipment is
listed in Table C–1 of subpart C of this
part, or is a blend containing one or
more fuels listed in Table C–1, calculate
emissions according to (z)(1)(i). If the
fuel is natural gas and is of pipeline
quality specification and has a
minimum high heat value of 950 Btu per
standard cubic foot, use the calculation
methodology described in (z)(1)(i) and
you may use the emission factor
provided for natural gas as listed in
Table C–1. If the fuel is natural gas, and
is not pipeline quality or has a high heat
value of less than 950 But per standard
cubic feet, calculate emissions
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according to (z)(2). If the fuel is field
gas, process vent gas, or a blend
containing field gas or process vent gas,
calculate emissions according to (z)(2).
(i) For fuels listed in Table C–1 or a
blend containing one more fuels listed
in Table C–1, calculate CO2, CH4, and
N2O emissions according to any Tier
listed in subpart C of this part. You
must follow all applicable calculation
requirements for that tier listed in 98.33,
any monitoring or QA/QC requirements
listed for that tier in 98.34, any missing
data procedures specified in 98.35, and
any recordkeeping requirements
specified in 98.37.
(ii) Emissions from fuel combusted in
stationary or portable equipment at
onshore natural gas and petroleum
production facilities and at natural gas
distribution facilities will be reported
according to the requirements specified
in 98.236(c)(19) and not according to the
reporting requirements specified in
subpart C of this part.
(2) For fuel combustion units that
combust field gas, process vent gas, a
blend containing field gas or process
vent gas, or natural gas that is not of
pipeline quality or that has a high heat
value of less than 950 Btu per standard
cubic feet, calculate combustion
emissions as follows:
(i) You may use company records to
determine the volume of fuel combusted
in the unit during the reporting year.
(ii) If you have a continuous gas
composition analyzer on fuel to the
combustion unit, you must use these
compositions for determining the
concentration of gas hydrocarbon
constituent in the flow of gas to the unit.
If you do not have a continuous gas
composition analyzer on gas to the
combustion unit, you must use the
appropriate gas compositions for each
stream of hydrocarbons going to the
combustion unit as specified in
paragraph (u)(2)(i) of this section.
15. Section 98.234 is amended by:
a. Revising paragraphs (a)(1), (a)(2),
and (a)(5).
b. Removing and reserving paragraph
(a)(4).
c. Revising paragraph (c) introductory
text and paragraph (d)(3).
§ 98.234 Monitoring and QA/QC
requirements.
(a) * * *
(1) Optical gas imaging instrument.
Use an optical gas imaging instrument
for equipment leak detection in
accordance with 40 CFR part 60, subpart
A, § 60.18 of the Alternative work
practice for monitoring equipment
leaks, § 60.18(i)(1)(i); § 60.18(i)(2)(i)
except that the monitoring frequency
shall be annual using the detection
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sensitivity level of 60 grams per hour as
stated in 40 CFR part 60, subpart A,
Table 1: Detection Sensitivity Levels;
§ 60.18(i)(2)(ii) and (iii) except the gas
chosen shall be methane, and
§ 60.18(i)(2)(iv) and (v); § 60.18(i)(3);
§ 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 is a leak unless
screened with Method 21 (40 CFR part
60, appendix A–7) monitoring, in which
case 10,000 ppm or greater is designated
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. An optical gas imaging
instrument must be used for all source
types that are inaccessible and cannot
be monitored without elevating the
monitoring personnel more than 2
meters above a support surface.
(2) Method 21. Use the equipment
leak detection methods in 40 CFR part
60, appendix A–7, Method 21. If using
Method 21 monitoring, if an instrument
reading of 10,000 ppm or greater is
measured, a leak is detected.
Inaccessible emissions sources, as
defined in 40 CFR part 60, are not
exempt from this subpart. Owners or
operators must use alternative leak
detection devices as described in
paragraph (a)(1) or (a)(2) of this section
to monitor inaccessible equipment leaks
or vented emissions.
*
*
*
*
*
(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 non-leakers with
subsequent measurement required to
calculate the rate if through-valve
leakage is identified. Leaks are reported
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if a leak rate of 3.1 scf per hour or
greater is measured.
*
*
*
*
*
(c) Use calibrated bags (also known as
vent bags) only where the emissions are
at near-atmospheric pressures and
below the maximum temperature
specified by the vent bag manufacturer
such that the bag is safe to handle. The
bag must be of sufficient size that the
entire emissions volume can be
encompassed for measurement.
*
*
*
*
*
(d) * * *
(3) Estimate natural gas volumetric
emissions at standard conditions using
calculations in § 98.233(t). Estimate CH4
and CO2 volumetric and mass emissions
from volumetric natural gas emissions
using the calculations in § 98.233(u) and
(v).
16. Section 98.236 is amended by:
a. Revising paragraphs (a)
introductory text and (a)(8).
b. Revising paragraph (b).
c. Revising paragraphs (c)
introductory text, (c)(1)(iv), (c)(2)(ii),
and (c)(3)(ii) through (c)(3)(v); and
adding paragraphs (c)(3)(vi) and (vii).
d. Revising paragraphs (c)(4)(i)(H) and
(C)(4)(i)(J); and adding paragraphs
(c)(4)(i)(K) and (c)(4)(i)(L).
e. Revising paragraphs (c)(4)(ii)(B) and
(c)(4)(ii)(C); and adding paragraph
(c)(4)(ii)(D).
f. Revising paragraph (c)(4)(iii)(B).
g. Revising paragraphs (c)(5)
introductory text, (c)(5)(iii), and
(c)(5)(vi); and adding paragraph
(c)(5)(vii).
h. Revising paragraphs (c)(6)
introductory text, (c)(6)(i) introductory
text, (c)(6)(i)(B), (c)(6)(i)(D), (c)(6)(i)(G),
and (c)(6)(i)(H); and adding paragraph
(c)(6)(ii)(I).
i. Revising paragraphs (c)(6)(ii)(B) and
(c)(6)(ii)(D); and adding paragraph
(c)(6)(ii)(E).
j. Revising paragraphs (c)(7)(i) and
(c)(7)(ii); and adding paragraph
(c)(7)(iii).
k. Revising paragraphs (c)(8)(i)
introductory text and (c)(8)(i)(J); and
adding paragraphs (c)(8)(i)(K) through
(c)(8)(i)(M).
l. Revising paragraphs (c)(8)(ii)
introductory text, (c)(8)(ii)(D), and
(c)(8)(ii)(G); and adding paragraphs
(c)(8)(ii)(H) and (c)(8)(ii)(I).
m. Revising paragraphs (c)(8)(iii)
introductory text and (c)(8)(iii)(F); and
adding paragraphs (c)(8)(iii)(G) and
(c)(8)(iii)(H).
n. Adding paragraph (c)(8)(iv)(B).
o. Revising paragraphs (c)(9)(i) and
(c)(9)(ii); and adding paragraph
(c)(9)(iii).
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56047
p. Revising paragraphs (c)(10)
introductory text and (c)(10)(iv); and
adding paragraph (c)(10)(v).
q. Revising paragraph (c)(11)
introductory text and (c)(11)(iii); and
adding paragraph (c)(11)(iv).
r. Revising paragraph (c)(12)(vi) and
adding paragraphs (c)(12)(vii) through
(c)(12)(xi).
s. Revising paragraphs (c)(15)(i)(B)
and (c)(15)(i)(C).
t. Revising paragraphs (c)(15)(ii)(A)
through (c)(15)(ii)(C).
u. Revising paragraphs (c)(16)(i)
through (c)(16)(iv), (c)(16)(vi), and
(c)(16)(xv).
v. Removing and reserving paragraph
(c)(16)(v).
w. Adding paragraphs (c)(16)(xvi)
through (c)(16)(xx).
x. Revising paragraph (c)(17)(v) and
adding paragraph (c)(17)(vi).
y. Revising paragraph (c)(18)
introductory text and paragraph
(c)(18)(iii).
z. Revising paragraph (c)(19)(iii) and
(c)(19)(vi).
aa. Adding paragraph (e).
The revisions read as follows:
§ 98.236
Data Reporting Requirements.
*
*
*
*
*
(a) Report annual emissions
separately for each of the industry
segments listed in paragraphs (a)(1)
through (8) of this section.
*
*
*
*
*
(8) Natural gas distribution.
(b) For offshore petroleum and natural
gas production, report emissions of CH4,
CO2, and N2O as applicable to the
source type (in metric tons CO2e per
year at standard conditions)
individually for all the emissions source
types listed in the most recent BOEMRE
study.
(c) Report the information listed in
this paragraph for each applicable
source type. If a facility operates under
more than one industry segment, each
piece of equipment should be reported
under its respective majority use
segment. When a source type listed
under this paragraph routes gas to flare,
separately report the emissions that
were vented directly to the atmosphere
without flaring, and the emissions that
resulted from flaring the gas. Both the
vented and flared emissions will be
reported under the respective source
type and not under the flare source type.
(1) * * *
(iv) Report annual CO2 and CH4
emissions at the facility level, expressed
in metric tons CO2e for each gas, for
each of the following pieces of
equipment: high bleed pneumatic
devices; intermittent bleed pneumatic
devices; low bleed pneumatic devices.
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(2) * * *
(ii) Report annual CO2 and CH4
emissions at the facility level, expressed
in metric tons CO2e for each gas, for all
natural gas driven pneumatic pumps
combined.
(3) * * *
(ii) For Calculation Methodology 1
and Calculation Methodology 2 of
§ 98.233(d), annual average fraction of
CO2 content in the vent from the acid
gas removal unit (refer to § 98.233(d)(6)).
(iii) For Calculation Methodology 3 of
§ 98.233(d), annual average volume
fraction of CO2 content of natural gas
into and out of the acid gas removal unit
(refer to § 98.233(d)(7) and (d)(8)).
(iv) Report the annual quantity of
CO2, expressed in metric tons CO2e, that
was recovered from the AGR unit and
transferred outside the facility.
(v) Report annual CO2 emissions for
the AGR unit, expressed in metric tons
CO2e.
(vi) A unique name or ID number for
the AGR unit.
(vii) An indication of which
calculation methodology was used for
the AGR.
(4) * * *
(i) * * *
(H) Concentration of CH4 and CO2 in
wet natural gas.
*
*
*
*
*
(J) For each glycol dehydrator, report
annual CO2 and CH4 emissions that
resulted from venting gas directly to the
atmosphere, expressed in metric tons
CO2e for each gas.
(K) For each glycol dehydrator, report
annual CO2, CH4, and N2O emissions
that resulted from flaring process gas
from the dehydrator, expressed in
metric tons CO2e for each gas.
(L) A unique name or ID number for
the glycol dehydrator.
(ii) * * *
(B) Which vent gas controls are used
(refer to § 98.233(e)(3) and (e)(4)).
(C) Report annual CO2 and CH4
emissions at the facility level that
resulted from venting gas directly to the
atmosphere, expressed in metric tons
CO2e for each gas, combined for all
glycol dehydrators with a throughput of
less than 0.4 MMscfd.
(D) Report annual CO2, CH4, and N2O
emissions at the facility level that
resulted from the flaring of process gas,
expressed in metric tons CO2e for each
gas, combined for all glycol dehydrators
with a throughput of less than 0.4
MMscfd.
(iii) * * *
(B) Report annual CO2 and CH4
emissions at the facility level, expressed
in metric tons CO2e for each gas, for all
absorbent desiccant dehydrators
combined.
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(5) For well venting for liquids
unloading (refer to Equations W–7, W–
8 and W–9 of § 98.233), report the
following by each well tubing diameter
grouping and pressure grouping within
each sub-basin category:
*
*
*
*
*
(iii) Cumulative number of unloadings
vented to the atmosphere.
*
*
*
*
*
(vi) Report annual CO2 and CH4
emissions, expressed in metric tons
CO2e for each gas, for each tubing
diameter and pressure grouping within
each sub-basin category.
(vii) When using Calculation
Methodology 1, casing diameter, depth
and pressure of each well selected to
represent emissions in that tubing size
and pressure combination (refer to
Equation W–7 of § 98.233).
(6) For well completions and
workovers, report the following for each
sub-basin category:
(i) For gas well completions and
workovers with hydraulic fracturing by
sub-basin and well type (horizontal or
vertical) combination (refer to Equation
W–10 of § 98.233):
*
*
*
*
*
(B) Average flow rate of the measured
well completion venting in cubic feet
per hour (refer to Equation W–12 of
§ 98.233).
*
*
*
*
*
(D) Average flow rate of the measured
well workover venting in cubic feet per
hour (refer to Equation W–12 of
§ 98.233).
*
*
*
*
*
(G) Report number of completions and
number of workovers employing
reduced emissions completions and
engineering estimate based on best
available data of the amount of gas
recovered to sales.
(H) Annual CO2 and CH4 emissions
that resulted from venting gas directly to
the atmosphere, expressed in metric
tons CO2e for each gas.
(I) Annual CO2, CH4, and N2O
emissions that resulted from flares,
expressed in metric tons CO2e for each
gas.
*
*
*
*
*
(B) Total count of workovers in
calendar year that flare gas or vent gas
to the atmosphere.
*
*
*
*
*
(D) Annual CO2 and CH4 emissions
that resulted from venting gas directly to
the atmosphere, expressed in metric
tons CO2e for each gas.
(E) Annual CO2, CH4, and N2O
emissions that resulted from flares,
expressed in metric tons CO2e for each
gas.
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(7) * * *
(i) Total number of blowdowns per
unique volume type in calendar year.
(ii) Annual CO2 and CH4 emissions,
expressed in metric tons CO2e for each
gas, for each unique volume type, at
each blowdown stack.
(iii) A unique name or ID number for
the blowdown vent stack.
(8) * * *
(i) For wellhead gas-liquid separator
with oil throughput greater than or
equal to 10 barrels per day, using
Calculation Methodology 1 and 2 of
§ 98.233(j), report the following by subbasin category, unless otherwise
specified:
*
*
*
*
*
(J) Annual CO2 and CH4 emissions
that resulted from venting gas to the
atmosphere, expressed in metric tons
CO2e for each gas, for each wellhead
gas-liquid separator or storage tank
using Calculation Methodology 1 or 2 of
§ 98.233(j).
(K) Annual CO2 and CH4 gas
quantities that were recovered,
expressed in metric tons CO2e for each
gas, for each wellhead gas-liquid
separator or storage tank using
Calculation Methodology 1 or 2 of
§ 98.233(j).
(L) Annual CO2, CH4, and N2O
emissions that resulted from flaring gas,
expressed in metric tons CO2e for each
gas, for each wellhead gas-liquid
separator or storage tank using
Calculation Methodology 1 or 2 of
§ 98.233(j).
(M) A unique name or ID number for
each wellhead gas liquid separator or
storage tank.
(ii) For wells with oil production
greater than or equal to 10 barrels per
day, using Calculation Methodology 3
and 4 of § 98.233(j), report the following
by sub-basin category:
*
*
*
*
*
(D) Sales oil API gravity range for
wells in (c)(8)(ii)(B) and (c)(8)(ii)(C) of
this section, in degrees.
*
*
*
*
*
(G) Annual CO2 and CH4 emissions
that resulted from venting gas to the
atmosphere, expressed in metric tons
CO2e for each gas, at the sub-basin level
for Calculation Methodology 3 or 4 of
§ 98.233(j).
(H) Annual CO2 and CH4 gas
quantities that were recovered,
expressed in metric tons CO2e for each
gas, at the sub-basin level for
Calculation Methodology 3 or 4 of
§ 98.233(j).
(I) Annual CO2, CH4, and N2O
emissions that resulted from flaring gas,
expressed in metric tons CO2e for each
gas, at the sub-basin level for
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Calculation Methodology 3 and 4 of
§ 98.233(j).
(iii) For wellhead gas-liquid
separators and wells with throughput
less than 10 barrels per day, using
Calculation Methodology 5 of § 98.233(j)
Equation W–15 of § 98.233, report the
following:
*
*
*
*
*
(F) Annual CO2 and CH4 emissions
that resulted from venting gas to the
atmosphere, expressed in metric tons
CO2e for each gas, at the sub-basin level
for Calculation Methodology 5 of
§ 98.233(j).
(G) Annual CO2 and CH4 gas
quantities that were recovered,
expressed in metric tons CO2e for each
gas, at the sub-basin level for
Calculation Methodology 5 of
§ 98.233(j).
(H) Annual CO2, CH4, and N2O
emissions that resulted from flaring gas,
expressed in metric tons CO2e for each
gas, at the sub-basin level for
Calculation Methodology 5 of
§ 98.233(j).
(iv) * * *
(B) Annual CO2 and CH4 emissions
that resulted from venting gas to the
atmosphere, expressed in metric tons
CO2e for each gas, at the sub-basin level
for improperly functioning dump
valves.
(9) * * *
(i) For each transmission storage tank,
report annual CO2 and CH4 emissions
that resulted from venting gas directly to
the atmosphere, expressed in metric
tons CO2e for each gas.
(ii) For each transmission storage
tank, report annual CO2, CH4, and N2O
emissions that resulted from flaring
process gas from the transmission
storage tank, expressed in metric tons
CO2e for each gas.
(iii) A unique name or ID number for
the transmission storage tank.
(10) For well testing venting and
flaring (refer to Equation W–17 of
§ 98.233), report the following:
*
*
*
*
*
(iv) Report annual CO2 and CH4
emissions at the facility level, expressed
in metric tons CO2e for each gas,
emissions from well testing venting.
(v) Report annual CO2, CH4, and N2O
emissions at the facility level, expressed
in metric tons CO2e for each gas,
emissions from well testing flaring.
(11) For associated natural gas venting
and flaring (refer to Equation W–18 of
§ 98.233), report the following for each
basin:
*
*
*
*
*
(iii) Report annual CO2 and CH4
emissions at the facility level, expressed
in metric tons CO2e for each gas,
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emissions from associated natural gas
venting.
(iv) Report annual CO2, CH4, and N2O
emissions at the facility level, expressed
in metric tons CO2e for each gas,
emissions from associated natural gas
flaring.
(12) * * *
(vi) Report uncombusted CH4
emissions, in metric tons CO2e (refer to
Equation W–19 of § 98.233).
(vii) Report uncombusted CO2
emissions, in metric tons CO2e (refer to
Equation W–20 of § 98.233).
(viii) Report combusted CO2
emissions, in metric tons CO2e (refer to
Equation W–21 of § 98.233).
(ix) Report N2O emissions, in metric
tons CO2e.
(x) A unique name or ID number for
the flare stack.
(xi) In the case that a CEMS is used
to measure CO2 emissions for the flare
stack, indicate that a CEMS was used in
the annual report and report the
combusted CO2 and uncombusted CO2
as a combined number.
(15) * * *
(i) * * *
(B) For onshore natural gas
processing, range of concentrations of
CH4 and CO2 (refer to Equation W–30 of
§ 98.233).
(C) Annual CO2 and CH4 emissions, in
metric tons CO2e for each gas (refer to
Equation W–30 of § 98.233), by
equipment type.
(ii) * * *
(A) For source categories
§ 98.230(a)(4), (a)(5), (a)(6), (a)(7), and
(a)(8), total count for each type of leak
source in Tables W–2, W–3, W–4, W–5,
and W–6 of this subpart for which there
is a population emission factor, listed by
major heading and component type.
(B) For onshore production (refer to
§ 98.230 paragraph (a)(2)), total count
for each type of major equipment in
Table W–1B and Table W–1C of this
subpart, by sub-basin category.
(C) Annual CO2 and CH4 emissions, in
metric tons CO2e for each gas (refer to
Equation W–31 of § 98.233), by
equipment type.
(16) * * *
(i) Number of above grade T–D
transfer stations.
(ii) Number of below grade T–D
transfer stations.
(iii) Number of above grade meteringregulating stations (this count will
include above grade T–D transfer
stations).
(iv) Number of below grade meteringregulating stations (this count will
include below grade T–D transfer
stations).
(v) [Reserved].
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56049
(vi) Above grade metering-regulating
station leak factor (refer to Equation W–
32 of § 98.233).
*
*
*
*
*
(xv) Annual CO2 and CH4 emissions,
in metric tons CO2e for each gas, from
all above grade T–D transfer stations
combined.
(xvi) Annual CO2 and CH4 emissions,
in metric tons CO2e for each gas, from
all below grade T–D transfer stations
combined.
(xvii) Annual CO2 and CH4 emissions,
in metric tons CO2e for each gas, from
all above grade metering-regulating
stations (including T–D transfer
stations) combined.
(xviii) Annual CO2 and CH4
emissions, in metric tons CO2e for each
gas, from all below grade meteringregulating stations (including T–D
transfer stations) combined.
(xix) Annual CO2 and CH4 emissions,
in metric tons CO2e for each gas, from
all distribution mains combined.
(xx) Annual CO2 and CH4 emissions,
in metric tons CO2e for each gas, from
all distribution services combined.
(17) * * *
(v) For each EOR pump, report annual
CO2 and CH4 emissions, expressed in
metric tons CO2e for each gas.
(vi) A unique name or ID for the EOR
pump.
(18) For EOR hydrocarbon liquids
dissolved CO2 for each sub-basin
category (refer to Equation W–38 of
§ 98.233), report the following:
*
*
*
*
*
(iii) Report annual CO2 emissions at
the sub-basin level, expressed in metric
tons CO2e.
(19) * * *
(iii) Report annual CO2, CH4, and N2O
emissions from external fuel
combustion units with a rated heat
capacity larger than 5 mmBtu/hr,
expressed in metric tons CO2e for each
gas, by type of unit.
*
*
*
*
*
(vi) Report annual CO2, CH4, and N2O
emissions from internal combustion
units, expressed in metric tons CO2e for
each gas, by type of unit.
*
*
*
*
*
(e) For onshore petroleum and natural
gas production, report the average API
gravity, average gas to oil ratio, and
average low pressure separator pressure
for each sub-basin category.
17. Section 98.237 is amended by
adding paragraph (e) to read as follows:
§ 98.237
Records that must be retained.
*
*
*
*
*
(e) The records required under
§ 98.3(g)(2)(i) shall include an
explanation of how company records,
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engineering estimation, or best available
information are used to calculate each
applicable parameter under this subpart.
18. Section 98.238 is amended by:
a. Revising the definitions of ‘‘Facility
with respect to natural gas distribution
for purposes of this subpart and subpart
A’’, ‘‘Facility with respect to onshore
petroleum and natural gas production
for purposes of this subpart and for
subpart A’’, ‘‘Farm Taps’’, and
‘‘Transmission pipeline’’.
b. Adding definitions of ‘‘Associated
with a single well-pad’’, ‘‘Distribution
pipeline’’, ‘‘Flare’’, ‘‘Forced extraction’’,
‘‘Horizontal well’’, ‘‘Natural gas’’,
‘‘Metering-regulating station’’, ‘‘Pressure
groupings’’, ‘‘Sub-basin category’’,
‘‘Transmission-distribution transfer
station’’, ‘‘Tubing diameter groupings’’,
‘‘Tubing systems’’, ‘‘Vertical well’’, and
‘‘Well testing venting and flaring’’.
c. Removing the definition of ‘‘Field’’.
The revisions read as follows:
§ 98.238
Definitions.
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*
*
*
*
*
Associated with a single well-pad
means associated with the hydrocarbon
stream as produced from one or more
wells located on that single well-pad.
The association ends where the stream
from a single well-pad is combined with
streams from one or more additional
single well-pads, where the point of
combination is located off that single
well-pad. This does not include storage
and condensate tanks that are located
downstream of the point of
combination.
*
*
*
*
*
Distribution pipeline means a pipeline
that is designated as such by the
Pipeline and Hazardous Material Safety
Administration (PHMSA) 49 CFR 192.3.
*
*
*
*
*
Facility with respect to natural gas
distribution for purposes of reporting
under this subpart and for the
corresponding subpart A requirements
means the collection of all distribution
pipelines and metering-regulating
stations that are operated by a Local
Distribution Company (LDC) within a
single state that is regulated as a
separate operating company by a public
utility commission or that are operated
as an independent municipally-owned
distribution system.
Facility with respect to onshore
petroleum and natural gas production
for purposes of reporting under this
subpart and for the corresponding
subpart A requirements means all
petroleum or natural gas equipment on
a well-pad or associated with a well-pad
and CO2 EOR operations that are under
common ownership or common control
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including leased, rented, or contracted
activities by an onshore petroleum and
natural gas production owner or
operator and that are located in a single
hydrocarbon basin as defined in
§ 98.238. Where a person or entity owns
or operates more than one well in a
basin, then all onshore petroleum and
natural gas production equipment
associated with all wells that the person
or entity owns or operates in the basin
would be considered one facility.
Farm Taps are pressure regulation
stations that deliver gas directly from
transmission pipelines to generally rural
customers. In some cases a nearby LDC
may handle the billing of the gas to the
customer(s).
*
*
*
*
*
Flare, for the purposes of subpart W,
means a combustion device, whether at
ground level or elevated, that uses an
open or closed flame to combust waste
gases without energy recovery.
*
*
*
*
*
Forced extraction of natural gas
liquids means removal of ethane or
higher carbon number hydrocarbons
existing in the vapor phase in natural
gas, by removing ethane or heavier
hydrocarbons derived from natural gas
into natural gas liquids by means of a
forced extraction process. Forced
extraction processes include but are not
limited to refrigeration, absorption (lean
oil), cryogenic expander, and
combinations of these processes. Forced
extraction does not include in and of
itself; natural gas dehydration, or the
collection or gravity separation of water
or hydrocarbon liquids from natural gas
at ambient temperature or heated above
ambient temperatures, or the
condensation of water or hydrocarbon
liquids through passive reduction in
pressure or temperature, or portable
dewpoint suppression skids.
*
*
*
*
*
Horizontal well means a well bore that
has a planned deviation from primarily
vertical to a primarily horizontal
inclination or declination tracking in
parallel with and through the target
formation.
*
*
*
*
*
Natural gas means a naturally
occurring mixture or process derivative
of hydrocarbon and non-hydrocarbon
gases found in geologic formations
beneath the earth’s surface, of which its
constituents include, but are not limited
to, methane, heavier hydrocarbons and
carbon dioxide. Natural gas may be field
quality, pipeline quality, or process gas.
Metering-regulating station means a
station that meters the flowrate,
regulates the pressure, or both, of
natural gas in a natural gas distribution
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facility. This does not include customer
meters, customer regulators, or farm
taps.
*
*
*
*
*
Pressure groupings are defined as
follows: less than or equal to 25 psig;
greater than 25 psig and less than or
equal to 60 psig; greater than 60 psig
and less than or equal to 110 psig;
greater than 110 psig and less than or
equal to 200 psig; and greater than 200
psig.
*
*
*
*
*
Sub-basin category, for onshore
natural gas production, means a
subdivision of a basin into the unique
combination of wells with the surface
coordinates within the boundaries of an
individual county and subsurface
completion in one or more of each of the
following four formation types as
designated by 18 CFR 270.305:
conventional with >0.1 millidarcy
permeability, and unconventional with
≤0.1 millidarcy permeability.
Unconventional formation types are
either shale, coal seam, or other tight
reservoir rock. Wells producing from
more than one unconventional
formation type shall be classified into
only one type based on the formation
with the most contribution to
production as determined by
engineering knowledge. Unconventional
wells producing in two or more
formation types of ‘‘shale and coal
seam’’, ‘‘shale and other tight’’, or
‘‘shale, coal seam, and other tight’’; are
considered shale. In addition,
unconventional wells producing in
‘‘coal seam and other tight’’ formations
are considered coal.
Transmission-distribution (TD)
transfer station means a meterregulating station where a local
distribution company takes part or all of
the natural gas from a transmission
pipeline and puts it into a distribution
pipeline.
Transmission pipeline means a
Federal Energy Regulatory Commission
rate-regulated Interstate pipeline, a state
rate-regulated Intrastate pipeline, or a
pipeline that falls under the ‘‘Hinshaw
Exemption’’ as referenced in section 1(c)
of the Natural Gas Act, 15 U.S.C. 717–
717(w)(1994).
Tubing diameter groupings are
defined as follows: less than or equal to
1 inch; greater than 1 inch and less than
2 inch; and greater than or equal to 2
inch.
Tubing systems means piping equal to
or less than one half inch diameter as
per nominal pipe size.
*
*
*
*
*
Vertical well means a well bore that
is primarily vertical but has some
E:\FR\FM\09SEP2.SGM
09SEP2
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Federal Register / Vol. 76, No. 175 / Friday, September 9, 2011 / Proposed Rules
unintentional deviation or one or more
intentional deviations to enter one or
more subsurface targets that are off-set
horizontally from the surface location,
intercepting the targets either vertically
or at an angle.
Well testing venting and flaring means
venting and/or flaring of natural gas at
the time the production rate of a well is
determined (i.e., the well testing)
*
*
through a choke (an orifice restriction).
If well testing is conducted immediately
after well completion or workover, then
it is considered part of well completion
or workover.
19. Table W–7 to subpart W is
amended by:
a. Revising the entries for ‘‘Leaker
Emission Factors—Above Grade M&R at
City Gate 1 Stations Components, Gas
Service,’’ ‘‘Population Emission
*
*
Factors—Below Grade M&R 2
Components, Gas Service 3,’’
‘‘Population Emission Factors—
Distribution Mains, Gas Service 4,’’ and
‘‘Population Emission Factors—
Distribution Services, Gas Service 5.’’
b. Removing Footnote 1.
c. Redesignating Footnotes 2, 3, 4, and
5 as Footnotes 1, 2, 3, and 4.
The revisions read as follows:
*
*
*
*
*
Leaker Emission Factors—Transmission-distribution Transfer Station1 Components, Gas Service
*
*
*
*
*
Population Emission Factors—Below Grade Metering-Regulating station1 Components, Gas Service2
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
Population Emission Factors—Distribution Mains, Gas Service3
*
*
*
Population Emission Factors—Distribution Services, Gas Service4
*
*
*
1 Excluding
customer meters.
Factor is in units of ‘‘scf/hour/station.’’
Factor is in units of ‘‘scf/hour/mile.’’
4 Emission Factor is in units of ‘‘scf/hour/number of services.’’
2 Emission
3 Emission
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Agencies
[Federal Register Volume 76, Number 175 (Friday, September 9, 2011)]
[Proposed Rules]
[Pages 56010-56051]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-21725]
[[Page 56009]]
Vol. 76
Friday,
No. 175
September 9, 2011
Part II
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Part 98
Mandatory Reporting of Greenhouse Gases: Technical Revisions to the
Electronics Manufacturing and the Petroleum and Natural Gas Systems
Categories of the Greenhouse Gas Reporting Rule; Proposed Rule
Federal Register / Vol. 76 , No. 175 / Friday, September 9, 2011 /
Proposed Rules
[[Page 56010]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 98
[EPA-HQ-OAR-2011-0512; FRL-9456-4]
RIN 2060-AR09
Mandatory Reporting of Greenhouse Gases: Technical Revisions to
the Electronics Manufacturing and the Petroleum and Natural Gas Systems
Categories of the Greenhouse Gas Reporting Rule
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
-----------------------------------------------------------------------
SUMMARY: This action proposes technical revisions to the electronics
manufacturing and the petroleum and natural gas systems source
categories of the greenhouse gas reporting rule. Proposed changes
include providing clarification on existing requirements, increasing
flexibility for certain calculation methods, amending data reporting
requirements clarifying terms and definitions, and technical
corrections. In addition, the Environmental Protection Agency is
proposing to amend the definition of heat transfer fluids in subpart I
to include more fluorocarbons used as heat transfer fluids in the
electronics manufacturing industry.
DATES: Comments. Comments must be received on or before October 11,
2011, unless a public hearing is held, in which case comments must be
received on or before October 24, 2011.
Public Hearing. A public hearing will be held if requested. To
request a hearing, please contact the person listed in the following
FOR FURTHER INFORMATION CONTACT section by September 16, 2011. If
requested, the hearing will be conducted on September 26, 2011, in the
Washington, DC area. EPA will publish further information about the
hearing in the Federal Register if a hearing is requested.
ADDRESSES: You may submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2011-0512 by any of the following methods:
Federal eRulemaking Portal: https://www.regulations.gov.
Follow the online instructions for submitting comments.
E-mail: GHG_Reporting_Rule_Oil_And_Natural_Gas@epa.gov.
Include Docket ID No. EPA-HQ-OAR-2011-0512 in the subject line of the
message.
Fax: (202) 566-9744.
Mail: Environmental Protection Agency, EPA Docket Center
(EPA/DC), Mail Code 28221T, Attention Docket ID No. EPA-HQ-OAR-2011-
0512, 1200 Pennsylvania Avenue, NW., Washington, DC 20460.
Hand/Courier Delivery: EPA Docket Center, Public Reading
Room, EPA West Building, Room 3334, Attention Docket ID No. EPA-HQ-OAR-
2011-0512, 1301 Constitution Avenue, NW., Washington, DC 20004. Such
deliveries are only accepted during the docket's normal hours of
operation, and special arrangements should be made for deliveries of
boxed information.
Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2011-0512, Mandatory Reporting of Greenhouse Gases: Petroleum and
Natural Gas Systems. EPA's policy is that all comments received will be
included in the public docket without change and may be made available
online at https://www.regulations.gov, including any personal
information provided, unless the comment includes information claimed
to be confidential business information (CBI) or other information
whose disclosure is restricted by statute. Do not submit information
that you consider to be CBI or otherwise protected through https://www.regulations.gov or e-mail. The https://www.regulations.gov Web site
is an ``anonymous access'' system, which means EPA will not know your
identity or contact information unless you provide it in the body of
your comment. If you send an e-mail comment directly to EPA without
going through https://www.regulations.gov your e-mail address will be
automatically captured and included as part of the comment that is
placed in the public docket and made available on the Internet. If you
submit an electronic comment, EPA recommends that you include your name
and other contact information in the body of your comment and with any
disk or CD-ROM you submit. If EPA cannot read your comment due to
technical difficulties and cannot contact you for clarification, EPA
may not be able to consider your comment. Electronic files should avoid
the use of special characters, any form of encryption, and be free of
any defects or viruses.
Docket: All documents in the docket are listed in the https://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available for viewing at the
EPA Docket Center. Publicly available docket materials are available
either electronically in https://www.regulations.gov or in hard copy at
the EPA Docket Center, EPA/DC, EPA West Building, Room 3334, 1301
Constitution Ave., NW., Washington, DC. This Docket Facility is open
from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal
holidays. The telephone number for the Public Reading Room is (202)
566-1744, and the telephone number for the Air Docket is (202) 566-
1742.
FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division,
Office of Atmospheric Programs (MC-6207J), Environmental Protection
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone
number: (202) 343-9263; fax number: (202) 343-2342; e-mail address:
GHGReportingRule@epa.gov. For technical questions, please see the
Greenhouse Gas Reporting Program Web site https://www.epa.gov/climatechange/emissions/ghgrulemaking.html. To submit a question,
select Rule Help Center, followed by Contact Us. To obtain information
about the public hearing or to register to speak at the public hearing,
please go to https://www.epa.gov/climatechange/emissions/ghgrulemaking.html. Alternatively, you may contact Carole Cook at 202-
343-9263.
SUPPLEMENTARY INFORMATION:
Worldwide Web (WWW). In addition to being available in the docket,
an electronic copy of today's proposal will also be available through
the WWW. Following the Administrator's signature, a copy of this action
will be posted on EPA's greenhouse gas reporting rule Web site at
https://www.epa.gov/climatechange/emissions/ghgrulemaking.html.
Additional information on submitting comments. To expedite review
of your comments by Agency staff, you are encouraged to send a separate
copy of your comments, in addition to the copy you submit to the
official docket, to Carole Cook, U.S. EPA, Office of Atmospheric
Programs, Climate Change Division, Mail Code 6207-J, Washington, DC
20460, telephone (202) 343-9263, e-mail address:
GHGReportingRule@epa.gov.
Regulated Entities. The Administrator determined that this action
is subject to the provisions of Clean Air Act (CAA) section 307(d). If
finalized, these amended regulations could affect owners or operators
of petroleum and natural gas systems and certain electronic
manufacturers. Regulated categories and entities may include those
listed in Table 1 of this preamble:
[[Page 56011]]
Table 1--Examples of Affected Entities by Category
----------------------------------------------------------------------------------------------------------------
Source category NAICS Examples of affected facilities
----------------------------------------------------------------------------------------------------------------
Petroleum and Natural Gas Systems............. 486210 Pipeline transportation of natural gas.
221210 Natural gas distribution facilities.
211 Extractors of crude petroleum and natural gas.
211112 Natural gas liquid extraction facilities.
Electronics Manufacturing..................... 334111 Microcomputers manufacturing facilities.
334413 Semiconductor, photovoltaic (solid-state) device
manufacturing facilities.
334419 Liquid Crystal Display (LCD) unit screens
manufacturing facilities.
334419 Micro-electro-mechanical systems (MEMS)
manufacturing facilities.
----------------------------------------------------------------------------------------------------------------
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 action. Although Table 1 of this preamble lists the
types of facilities of which EPA is aware that could be potentially
affected by this action, other types of facilities not listed in the
table could also be affected. To determine whether you are affected by
this action, you should carefully examine the applicability criteria
found in 40 CFR part 98 subpart A, 40 CFR part 98 subpart I and 40 CFR
part 98 subpart W. If you have questions regarding the applicability of
this action to a particular facility, consult the person listed in the
preceding FOR FURTHER INFORMATION CONTACT section.
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
AGA American Gas Association
API American Petroleum Institute
AXPC American Exploration and Production Council
BAMM Best Available Monitoring Methods
BOEMRE Bureau of Ocean Energy Management, Regulation and Enforcement
CAA Clean Air Act
CBI confidential business information
CEC Chesapeake Energy Corporation
CEMS continuous emission monitoring systems
cfd cubic feet per day
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e CO2-equivalent
COR certificate of representation
e-GGRT electronic greenhouse gas reporting tool
EIA Economic Impact Analysis
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
FCML Field Code Master List
FERC Federal Energy Regulatory Commission
FR Federal Register
GHG greenhouse gas
GPA Gas Processors Association
GOR gas to oil ratio
GRI Gas Research Institute
Hp horsepower
GWP global warming potential
HHV high heat value
HTF heat transfer fluid
IBR incorporation by reference
ICR information collection request
LDC Local Distribution Company
ISO International Organization for Standardization
kg kilograms
LDCs local natural gas distribution companies
LNG liquefied natural gas
M&R meters and regulators
mmBtu million British thermal units
mmHg millimeters of Mercury
MMscfd million standard cubic feet per day
mTCO2e million metric tons carbon dioxide equivalent
MRR mandatory GHG reporting rule
N2O nitrous oxide
NAICS North American Industry Classification System
NF3 nitrogen trifluoride
NGLs natural gas liquids
NPS nominal pipe size
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality, Planning and Standards
OMB Office of Management and Budget
PHMSA Pipeline and Hazardous Material Safety Administration
QA/QC quality assurance/quality control
RFA Regulatory Flexibility Act
SBA Small Business Administration
SBREFA Small Business Regulatory Enforcement and Fairness Act
SF6 sulfur hexafluoride
T-D Transmission Distribution
TSD technical support document
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
USC United States Code
Table of Contents
I. Background
A. How is this preamble organized?
B. Background on the Proposed Action
C. Legal Authority
D. How would these amendments apply to 2012 reports?
II. Technical Corrections and Other Amendments
A. Subpart A--General Provisions
B. Subpart I--Electronics Manufacturing
C. Subpart W--Petroleum and Natural Gas Systems
III. 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
I. Background
A. How is this preamble organized?
The first section of this preamble contains the basic background
information about the origin of these proposed rule amendments and
request for public comment. This section also discusses EPA's use of
legal authority under the CAA to collect data on GHGs.
The second section of this preamble describes in detail the changes
that are being proposed to correct technical errors or to address
implementation issues identified by EPA and others. This section also
presents EPA's rationale for the proposed changes and identifies issues
on which EPA is particularly interested in receiving public comments.
Finally, the last (third) section discusses the various statutory
and executive order requirements applicable to this proposed
rulemaking.
B. Background on the Proposed Action
EPA published subpart I: Electronics Manufacturing of the
Greenhouse Gas Reporting Program (GHGRP) on December 1, 2010 (75 FR
74774) subpart I of the GHGRP requires monitoring and reporting of GHG
emissions from electronics manufacturing. Electronics manufacturing
facilities covered by subpart I are those that have emissions equal to
or greater than 25,000 mtCO2e.
Following the publication of subpart I in the Federal Register, 3M
Company
[[Page 56012]]
(3M) sought reconsideration of the final rule requirements for
reporting fluorinated heat transfer fluids (HTFs). In this action EPA,
is proposing amendments to the provisions in subpart I related to
calculating and reporting fluorinated HTFs to reflect the Agency's
intent to cover all fluorocarbons (except for ozone depleting
substances regulated under EPA's Stratospheric Protection Regulations
at 40 CFR part 82) that can enter the atmosphere under the conditions
in which HTFs are used in the electronics manufacturing industry.
EPA published Subpart W: Petroleum and Natural Gas Systems of the
Greenhouse Gas Reporting Rule on November 30, 2010(75 FR 74458).
Subpart W of the GHGRP, which applies to facilities in specific
segments of the petroleum and natural gas industry that emit GHGs
greater than or equal to 25,000 mtCO2e per year, covers
approximately 85 percent of GHG emissions--including vented, equipment
leak, and combustion emissions--from facilities in specific segments of
the petroleum and natural gas industry.
Following the publication of subpart W in the Federal Register,
several industry groups requested reconsideration of several provisions
in the final rule. Part of the proposed amendments in this action are
in response to those requests for reconsideration. Today we are
granting reconsideration of, and requesting comment on, those issues
raised in the petitions listed in Table 2 where indicated in such Table
that the issue is addressed in this action. While we do not necessarily
agree that each of those identified issues meet the criteria for
reconsideration, we nonetheless believe that they do raise important
implementation issues and are thus granting reconsideration of those
issues and proposing concomitant revisions to the rule. At this time we
are not granting reconsideration of other issues raised in those
petitions where indicated in the following table that they are not
being addressed in this action but will consider those issues at a
later time.
Table 2--Petitions for Reconsideration
------------------------------------------------------------------------
Is this issue
Petitioner and date of Issue raised for addressed in this
letter reconsideration action?
------------------------------------------------------------------------
American Gas Association by Non custody transfer Yes.
letter dated March 2, 2011. city gate station
terminology. AGA
asserted that
``[s]everal
provisions in the
Subpart W rule and
preamble seem to
imply that a `non-
custody-transfer
city gate station'
will always have a
meter''.
-------------------------------------------
Custody transfer Yes.
city gate station
terminology. AGA
asserted that the
term ``custody
transfer city gate
station'' in
subpart W was
unclear and needed
clarification.
-------------------------------------------
Use of GTI emission Partially.
factors. AGA
requested
reconsideration of
the emissions
factors for Local
Distribution
Companies in the
final rule.
-------------------------------------------
New emission factor Yes.
formulas are
confusing or
contain math errors
that vastly inflate
emission estimates.
AGA asserted that
the ``[t]he new
emissions factor
equations W-30, W-
31 and W-32 in the
final rule are
confusing. Since
these formulas were
not included in the
proposed rule, AGA
did not have an
opportunity to
comment on them''.
-------------------------------------------
New electronic No. This is being
reporting form is addressed in a
not yet available separate package.
for comment or
testing. AGA
asserted that
``[s]takeholders
should be given the
opportunity to
comment and to have
access to the
reporting software
to perform trial
runs.
-------------------------------------------
EPA should exclude Yes.
small internal
combustion sources,
not just external
combustion. AGA
asserted that ``EPA
should revise the
final rule to
provide a de
minimis exemption
for small internal
and external
combustion sources
at underground
storage
facilities.'' Also
``AGA request
reconsideration of
this new exclusion
for small
combustion sources
and revision to
include both small
internal and
external combustion
sources * * *''.
-------------------------------------------
AGA asserted that No.
``[t]he rule
contains
conflicting
provisions
regarding whether
emissions from
dehydrator units at
underground storage
facilities should
or should not be
reported''.
-------------------------------------------
[[Page 56013]]
AGA asserted that Yes.
``EPA did not
provide rational
explanation for
using outdated
inaccurate emission
factors rather than
modern updated
emission factors''.
-------------------------------------------
AGA asserted that No.
``[d]efinition of
`facility' is
overbroad and
confusing.'' The
facility definition
referred to here is
found in 40 CFR
98.238.
-------------------------------------------
AGA asserted that No.
``It was arbitrary
and capricious for
EPA to create a
subpart W reporting
regulation for a
null set--LNG
storage facilities
will not exceed the
25,000 ton per year
threshold''.
-------------------------------------------
AGA asserted that No.
``It was arbitrary
and capricious for
EPA to create a
subpart W reporting
regulation for LNG
import and export
facilities--which
have only minimal
methane leaks''.
------------------------------------------------------------------------
Chesapeake Energy/American Measurement of No.
Exploration and Production Emissions. CEC/AXPC
Council by Letter Dated asserted that ``EPA
January 31, 2011. proposed to require
costly measurement
and reporting of
emissions from
hundreds of
thousands of
sources. Commenters
asked EPA to adopt
a reasonable
threshold for
measurement, so
that emissions
could still be
accounted for, but
in a cost-effective
way. Commenters
recommended using
the API Compendium
for that purpose''.
-------------------------------------------
De minimis emissions Yes.
from portable
equipment. CEC/AXPC
asserted that
``[t]he final rule
likewise fails to
adequately support
requiring the
reporting of de
minimis emissions
from portable
equipment as EPA
proposedEPA asserts
a truism that all
emissions
contribute to
sector emissions
overall''.
-------------------------------------------
Designated Yes.
Representative. CEC/
AXPC requested
reconsideration of
the designated
representative
provisions in the
final rule.
-------------------------------------------
Dump Valves. CEC/ No.
AXPC asserts that
``[t]he requirement
to measure and
report emissions
from dump valves
associated with
onshore production
storage tanks * * *
is a new and
unreasonable
ongoing monitoring
and record keeping
burden * * *''.
-------------------------------------------
Best Available No. This is being
Monitoring Methods. addressed in a
separate action (76
FR 37300).
-------------------------------------------
Emissions Manifolded No.
to Common Vents.
CEC/AXPC asserted
that the final
provisions for
centrifugal
compressor
monitoring ``[n]ot
only expands the
rule to cover
equipment that was
not identified in
the proposed rule,
but it is also
inconsistent and
creates ambiguity
for covered sources
regarding what is
required''.
-------------------------------------------
Compressor No.
Monitoring. CEC/
AXPC asserts that
``[t]he final rule
imposes a new
obligation to
monitor and report
that would require
major piping
modifications and
that would unduly
threaten worker
safety''.
-------------------------------------------
[[Page 56014]]
Excluding Boosting Yes.
Stations. CEC/AXPC
asserted that
``[t]he final rule
fails to
distinguish between
a boosting station,
which is exempt,
and an `onshore
natural gas
transmission
compression
facility' which
must report under
the rule''.
-------------------------------------------
Onshore Natural Gas Yes.
Transmission
Compression
Industry Segment
Definition. CEC/
AXPC asserted that
``[a]s presently
drafted, the
unclear and
inconsistent final
provisions render
the rule arbitrary
and capricious and
contrary to law.''
And ``The term
`onshore natural
gas transmission
compression' means
a stationary
combination of
compressors that
move natural gas at
elevated pressure
from production
fields or natural
gas processing
facilities in
transmission
pipelines or into
storage. 40 CFR
Sec.
98.230(a)(4). A
transmission
compressor station
can include
equipment to
separate liquids or
dehydrate natural
gas Id. However,
according to the
final rule this
source category
does not include
gathering lines and
boosting stations''.
-------------------------------------------
Onshore Natural Gas Yes.
Processing Industry
Segment Definition.
CEC/AXPC asserted
that ``[a]s
presently drafted,
the unclear and
inconsistent final
provisions render
the rule arbitrary
and capricious and
contrary to law.''
CEC/AXPC further
stated concerns
with the definition
for onshore natural
gas processing
industry segment
definition and
where the segment
differs from
onshore natural gas
transmission
industry segment,
and from gathering
lines and boosting
stations.
-------------------------------------------
Gathering Lines and Yes.
Boosting Stations.
CEC/AXPC asserted
that ``EPA noted
that the `final
rule does not
require reporting
of emissions from
[the] gathering and
boosting segment of
the industry.'
Thisis not helpful
and gives industry
no clarity
regarding which
compressor stations
are required to
report''.
-------------------------------------------
Mapping Wells to Yes.
Fields. CEC/AXPC
asserted that ``EPA
has not clarified
how reporting
entities are
supposed to map
wells to a
particular `field.'
'' Also, CEC/AXPC
asserted that
``[w]ithout
sufficient clarity
regarding what
wells are in a
particular field,
it is difficult for
covered sources to
know with certainty
what gas
composition is
considered
representative for
each well''.
-------------------------------------------
Definition of No.
Facility for
Onshore Petroleum
and Natural Gas
Production. CEC/
AXPC asserted that
the ``EPA has not
provided a reasoned
explanation for why
a term other than
`facility' cannot
be adopted for
Subpart w (such as
`Reporting Area')
in order to avoid
unintended
confusion and
inaccuracies in
reporting''.
-------------------------------------------
Pipeline Quality Yes.
Natural Gas. CEC/
AXPC asserted that
``[t]here is not a
clear and
unambiguous
definition in the
final rule for
`pipeline quality'
natural gas''.
-------------------------------------------
[[Page 56015]]
Producing Horizon/ Yes.
formation
definition. CEC/
AXPC asserted that
``[t]here is not a
clear and
unambiguous
definition provided
in the final rule
for the term
`producing horizon/
formation' ''.
-------------------------------------------
Well testing venting Yes.
and flaring
clarification. CEC/
AXPC asserted that
``[t]he final rule
is unclear
regarding the
requirement to
report emissions
from well testing
venting and
flaring''.
-------------------------------------------
Associated Gas No.
Venting and
Flaring. CEC/AXPC
asserted that ``40
CFR 98.233(m)
imposes a
requirement to
report emissions
from associated gas
venting and flaring
not in conjunction
with well testing.
While this
regulation
references 40 CFR
98.233(l), that
definition is
unclear. Therefore
industry is left
without clarity
regarding what
emissions are
included in
`associated gas
venting and flaring
not in conjunction
with well testing'
''.
-------------------------------------------
Pneumatic Devices. Yes.
CEC/AXPC asserted
that ``EPA has not
given sufficient
consideration to
the burden imposed
by requiring that
the bleed rate of
each device be
determined in order
to count and
classify the
devices''.
-------------------------------------------
Blowdown Vent Yes.
Stacks. CEC/AXPC
asserted that
``[t]he sources
that are required
to report emissions
from blowdown vent
stacks are not
clear''.
------------------------------------------------------------------------
American Petroleum Institute Best Available No. This is being
by Letter Dated January 31, Monitoring Methods. addressed in a
2011. separate action (76
FR 37300).
-------------------------------------------
Exclusion for Yes.
`small' internal
combustion sources
is needed. API
asserted that ``EPA
should extend the
exclusion for small
external combustion
sources to small
internal combustion
sources''.
-------------------------------------------
Stuck dump valves to No.
separators/tanks in
onshore production
operations. API
asserted that
``[t]he new
requirement to
report emissions
from stuck dump
valves requires
reporters to check
all dump valves on
a well site * * *
These requirements
represent an
administrative
burden for reports
that was not
contemplated in the
proposed rule''.
-------------------------------------------
Reporting No.
requirements for
centrifugal and
reciprocating
compressor venting
at onshore natural
gas processing
facilities. API
requested EPA to
reconsider an
asserted expansion
of reporting
requirements for
centrifugal and
reciprocating
compressor venting
at onshore natural
gas processing
facilities.
-------------------------------------------
[[Page 56016]]
Requirements for Yes.
flare stack
emission associated
with onshore oil
and gas production.
API asserted that
``[e]missions from
flare stacks
associated with
onshore oil and gas
production were not
included in the
Petroleum and
Natural Gas
production industry
segment in the
proposed rule * * *
the inclusion of
emissions from
flare stacks
associated with
onshore oil and gas
production is
duplicative,
burdensome, and a
potential source of
reporting
inaccuracies''.
-------------------------------------------
Reporting No.
requirements for
all venting and
flaring activities
in the production
source category.
API asserts that
``EPA's expansion
of the reporting
obligations in
98.233(m) to
include upset or
maintenance gas
from producing
wells imposes
additional and
extensive burdens
on regulated
parties which was
not included in the
proposal''.
-------------------------------------------
Use of gas Yes.
composition based
on available sample
analysis for
reporters without
continuous gas
composition
analyzer. API
asserts that ``EPA
should resolve the
ambiguity created
by the current
language''.
-------------------------------------------
Portable combustion Yes.
equipment that
cannot move on
roadways under its
own power and drive
train that is
stationed at a
wellhead for less
than 30 days in a
reporting year. API
asserts that
``[t]he final rule
requires reporters
to account for this
equipment, despite
the fact that it is
on site for an
extremely short
period of time * *
* it is unrealistic
to expect reporters
to measure
emissions from
every piece of
portable combustion
equipment that is
only onsite for a
matter of days''.
-------------------------------------------
Separate Yes.
calculations for
subsonic and
supersonic flow
when both happen
during a single
completion. API
asserted that
``[t]he proposed
rule did not
include a
requirement that
well completions
have separate
calculations for
subsonic and
supersonic flow
when both occur
during a single
completion. The
final rule adds
this requirement,
which is not
technically
possible''.
-------------------------------------------
Flow meter Yes.
requirements. API
asserts that
``[t]he final rule
adds a requirement
at 40 CFR 98.234(b)
that all flow
meters, composition
analyzers and
pressure gauges be
operated and
calibrated
according to the
procedures in
Section 98.3(i) of
the MRR * * * API
is concerned about
the potential
unintended
consequence
following the
addition of
stationary source
combustion
equipment at a well
pad at new 40 CFR
98.232(C)(22),
which required
compliance with 40
CFR
98.233(z)(2)(1)''.
-------------------------------------------
[[Page 56017]]
Emission factors for Yes.
continuous high-
bleed, continuous
low-bleed, and
intermittent bleed
pneumatic devices.
API asserted that
``[a]lthough EPA
has provided
emission factors in
Table W-1A that
apply to continuous
high-bleed,
continuous low-
bleed, and
intermittent bleed
pneumatic devices,
EPA has not
provided guidance
on how to classify
pneumatic devices
according to these
three categories''.
-------------------------------------------
Definitions to Yes.
Industry
Categories. API
asserted that the
``[a]ltered final
rule creates
ambiguity as to
whether certain
facilities are
included in the
production
category, excluded
as gathering or
booster stations,
or included under
the gas processing
category''.
-------------------------------------------
Number of plunger Yes.
lifts and average
casing diameter in
inches. API
asserted that
``[t]he final rule
adds 40 CFR
98.236(c)(5)
requirements to
report the number
of plunger lifts
and average casing
diameter in inches
by field. The
difficulty with
these additions is
not with the
requirement for
counting plunger
lifts and noting
casing diameter,
but that reporting
must take place at
the field level''.
-------------------------------------------
Floating Production No.
Storage and
Offloading
Equipment. API
asserted that
``[t]he proposed
rule did not
include floating
production storage
and offloading
equipment in the
definition of
offshore petroleum
and natural gas
production. API
questions the need
for this addition
at 40 CFR
98.230(a)(1)''.
-------------------------------------------
Basin level Yes.
reporting for
onshore petroleum
and natural gas
production. API
asserted that
``[t]his broad
definition of
onshore production
facility is
impractical.
Subpart W imposes
reporting
requirements on
over 22,000
entities operating
hundreds of
thousands of wells
and millions of
pieces of equipment
scattered over
hundreds of
thousands of square
miles''.
-------------------------------------------
Field level Yes.
reporting for
onshore petroleum
and natural gas
production. API
asserts that
``[t]his level of
reporting is
problematic when
applied to new
requirements of the
final rule. For the
same reasons, it
remains problematic
when applied to
those requirements
in the proposed
rule that remain in
the final rule''.
-------------------------------------------
Designated Yes.
Representative of
Subpart W Facility.
API asserted that
``[t]he new basin-
level facility
definition for
onshore petroleum
and natural gas
production systems
adopted in Subpart
W adds unreasonable
complexity to
several of the
existing
administrative
requirements for
the designated
representative set
forth in 40 CFR
98.4''.
-------------------------------------------
[[Page 56018]]
Reporting of GHG Partially.
emissions from
leased, rented, or
contracted
activities. API
asserts that
``[t]hese
requirements create
significant
complications. A
single well pad may
be owned by one
entity, operated by
another entity,
lease portable
equipment from a
third entity, and
have that portable
equipment operated
by yet another
entity. The rule
places the burden
of reporting
entirely on the
owner of the well
or the holders of
the operating
permit and makes
the designated
representatives
legally responsible
for the accuracy of
the emissions data
provided by third
parties''.
-------------------------------------------
Threshold for No.
``small'' size
units that are
exempt from
consideration. API
asserts that
``[t]he final
rule's threshold of
0.4 MMscf per day
for dehydrator
calculations using
software and
individual
reporting is too
low''.
------------------------------------------------------------------------
Gas Processors Association Best Available No. This is being
by Letter Dates February Monitoring Methods. addressed in a
11, 2011. GPA asserted that separate action (76
``[s]ubpart W's FR 37300).
best available
monitoring method
provisions do not
provide reporting
entities with
adequate time to
ensure compliance
with the final
rule''.
Compressor venting No.
monitoring
requirements. GPA
asserted that
``[c]urrent
compressor venting
monitoring
requirements are
overly burdensome
and present
significant safety
and operational
process concerns to
reporting
entities''.
-------------------------------------------
Use of the terms Yes.
``gathering lines''
and ``booster
stations'' not
being defined in
final rule. GPA
asserted