[Federal Register Volume 76, Number 175 (Friday, September 9, 2011)]
[Proposed Rules]
[Pages 56009-56051]
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
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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]]
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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: http://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 http://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 http://www.regulations.gov or e-mail. The http://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 http://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 http://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 http://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 http://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 http://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
http://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 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 No.
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''.
------------------------------------------------------------------------
Southwest Gas Corporation by Terms in Subpart W. Yes.
Letter Dated January 31, Southwest Gas
2011. 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''.
-------------------------------------------
Errors in Yes.
Calculations.
Southwest Gas
Corporation
asserted that the
USEPA published
errors in equations
in 40 CFR 98.233,
namely equation W-
32.
------------------------------------------------------------------------
Interstate Natural Gas Best Available No. This is being
Association of America. Monitoring Methods. addressed in a
separate action (76
FR 37300).
------------------------------------------------------------------------
[[Page 56019]]
Technical Provisions Partially.
in Subpart W. INGAA
asserted that
``[n]umerous
technical elements
of Subpart W remain
unclear, confusing,
overly complicated
or conflicting''.
-------------------------------------------
INGAA petitioned EPA Yes.
to reconsider the
default 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.
-------------------------------------------
INGAA petitioned EPA Yes.
to reconsider minor
clarifications to
40 CFR 98.233(t),
(u), and (v) for
clarity.
-------------------------------------------
INGAA requested EPA Yes.
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.
-------------------------------------------
INGAA requested EPA Yes.
to reconsider the
provisions in the
rule related to
blowdown vent
stacks and
requested a
reconsideration of
those provisions.
-------------------------------------------
INGAA requested EPA Yes.
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.
-------------------------------------------
INGAA requested that Yes.
EPA to reconsider
provisions related
to flaring.
-------------------------------------------
INGAA requested that No.
EPA reconsider
provisions for
monitoring
emissions from
centrifugal and
reciprocating
compressors and to
consider including
clarifications to
rule text.
-------------------------------------------
INGAA requested EPA Yes.
to reconsider
provisions related
to monitoring and
QA/QC requirements
including
provisions for the
alternative work
practice.
-------------------------------------------
INGAA requested EPA No.
to reconsider
missing data
provisions and
broaden access.
-------------------------------------------
INGAA requested EPA Partially.
to reconsider
provisions as
stated in 40 CFR
98.236 and
requested several
clarifications to
final text.
------------------------------------------------------------------------
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 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 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
[[Page 56020]]
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.
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\
---------------------------------------------------------------------------
\1\ 74 FR 16448 (April 10, 2009) and 74 FR 56260 (October 30,
2009).
---------------------------------------------------------------------------
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.
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 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
[[Page 56021]]
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 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 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.
[[Page 56022]]
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
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 sub-basin 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
``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)
[[Page 56023]]
of 400 Pa (0.004 bar, or three mm Hg absolute) at 25 C.\3\
---------------------------------------------------------------------------
\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.)
---------------------------------------------------------------------------
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 Sec. 98.6 in Subpart A, the scope of Subpart I's
reporting 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\ (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).
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\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 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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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
[[Page 56024]]
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 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 mass-balances 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 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 non-HTF
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
[[Page 56025]]
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.
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 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
``field-level'' 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
[[Page 56026]]
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 sub-basin 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, 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 sub-basin
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 sub-basin 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(copyright) 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 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
[[Page 56027]]
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 well-pad. 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 well-
pad 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 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, 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) rate-regulated 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
[[Page 56028]]
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 ``meter-
regulating 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 `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 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 ``non-custody
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
[[Page 56029]]
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 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 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
[[Page 56030]]
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 (Sub-basin 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.
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 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
[[Page 56031]]
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 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 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
[[Page 56032]]
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 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
transmission-distribution 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 metering-
regulating 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-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 x 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 x 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
[[Page 56033]]
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 well-pad under the meters/piping category.
Therefore, owners or operators should use one count of meters/piping
per well-pad.
Further, consistent with proposed amendments described above, EPA
is proposing to amend 40 CFR 98.233(r)(6)(ii) by referring to
``metering-regulating 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 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 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
[[Page 56034]]
potential equipment threshold for non-compressor 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 combustion-
related 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 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.
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\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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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, through-valve
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), 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 ``non-custody 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
[[Page 56035]]
characteristics to characterize other emissions sources across
different sub-basins.''
Records that must be retained. EPA is proposing to add the
following recordkeeping requirement: ``The records required under Sec.
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 well-
pad. The association with a single well-pad 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 gas-liquid 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
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 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 ``metering-
regulation stations'' but the subset that require leak detection are
``transmission-distribution transfer stations.'' EPA was notified of
concerns from industry that defining a
[[Page 56036]]
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 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 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-for-profit 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
[[Page 56037]]
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 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 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.
[[Page 56038]]
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.
For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is proposed to be amended as follows:
PART 98--[AMENDED]
1. The authority citation for part 98 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart A--[Amended]
2. Section 98.1 is amended by adding paragraph (c) to read as
follows:
Sec. 98.1 Purpose and scope.
* * * * *
(c) For facilities required to report under onshore petroleum and
natural gas production under subpart W of this part, the terms Owner
and Operator used in subpart A have the same definition as Onshore
petroleum and natural gas production owner or operator, as defined in
Sec. 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:
Sec. 98.6 Definitions.
* * * * *
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 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]
5. Section 98.90 is amended by revising paragraph (a)(5) to read as
follows:
Sec. 98.90 Definition of the source category.
(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:
Sec. 98.92 GHGs to report.
(a) You must report emissions of fluorinated GHGs (as defined in
Sec. 98.6), N2O, and fluorinated heat transfer fluids (as
defined in Sec. 98.98). The fluorinated GHGs and fluorinated heat
transfer fluids that are emitted from electronics manufacturing
production processes include, but are not limited to, those listed in
Table I-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.
Sec. 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.
* * * * *
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:
Sec. 98.94 Monitoring and QA/QC requirements.
* * * * *
(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:
Sec. 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:
Sec. 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
------------------------------------------------------------------------
Fluorinated GHGs and fluorinated
Product type 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).
------------------------------------------------------------------------
[[Page 56039]]
Subpart W--[Amended]
12. Section 98.230 is amended by revising paragraphs (a)(2) through
(a)(4), and (a)(8) to read as follows:
Sec. 98.230 Definition of the source category.
(a) * * *
(2) Onshore petroleum and natural gas production. Onshore petroleum
and natural gas production means all equipment on a single well-pad or
associated with a single well-pad (including but not limited to
compressors, generators, dehydrators, storage vessels, and portable
non-self-propelled 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 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:
Sec. 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 Sec. 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 Sec. 98.238. Stationary or portable 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
transmission-distribution 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
metering-regulating 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
[[Page 56040]]
``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 ``[alpha]'' 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).
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''.
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
``[rho]i'' 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:
Sec. 98.233 Calculating GHG emissions.
(a) * * *
[GRAPHIC] [TIFF OMITTED] TP09SE11.000
* * * * *
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.
* * * * *
GHGi = For onshore petroleum and natural gas production
facilities, onshore natural gas transmission compression, and
underground natural gas storage, concentration of GHGi,
CH4, or CO2, in natural gas as defined in
paragraph (u)(2)(i) of this section.
* * * * *
T = Total number of hours in the operating year the devices were
operational.
* * * * *
(3) For all industry segments, determine the type of pneumatic
device using engineering estimates based on best available information.
* * * * *
(c) * * *
[GRAPHIC] [TIFF OMITTED] TP09SE11.001
* * * * *
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), 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 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
[[Page 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) * * *
[GRAPHIC] [TIFF OMITTED] TP09SE11.002
* * * * *
(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.
(1) Calculation Methodology 1. For one well of each unique well
tubing diameter grouping and pressure grouping in each sub-basin
category (see Sec. 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 Sec. 98.234(b). Calculate emissions from well venting for liquids
unloading using Equation W-7 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.
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.
* * * * *
(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 sub-basin category, an average
flow rate is calculated beginning in the first year of production.
(2) * * *
[GRAPHIC] [TIFF OMITTED] TP09SE11.003
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.
0.37x10-3 = {3.14 (pi)/4{time} /{14.7*144{time} (psia
converted to pounds per square feet).
CDP = Casing diameter for each well, p, in inches.
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.
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) * * *
[GRAPHIC] [TIFF OMITTED] TP09SE11.004
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.
0.37x10-3 = {3.14 (pi)/4{time} /{14.7*144{time} (psia
converted to pounds per square feet).
[[Page 56042]]
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.
* * * * *
(g) * * *
[GRAPHIC] [TIFF OMITTED] TP09SE11.005
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.
(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) 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 Sec. 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 Sec. 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:
[GRAPHIC] [TIFF OMITTED] TP09SE11.006
Where:
FR = Average flow rate in cubic feet per hour, under subsonic flow
conditions.
A = Cross sectional area of orifice (m2).
P1 = Upstream pressure (psia).
Tu = Upstream temperature (degrees Kelvin).
P2 = Downstream pressure (psia).
3430 = Constant with units of m2/(sec2 * K).
1.27*105 = Conversion from m3/second to ft3/
hour.
[GRAPHIC] [TIFF OMITTED] TP09SE11.007
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.
[GRAPHIC] [TIFF OMITTED] TP09SE11.008
[[Page 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.
[GRAPHIC] [TIFF OMITTED] TP09SE11.009
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 sub-basin and well
type combination.
W = Number of wells completed or worked over using hydraulic
fracturing in a sub-basin and well type formation.
(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 sub-basin 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 Sec. 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].
(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
Sec. 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:
* * * * *
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 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.
* * * * *
(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.
[GRAPHIC] [TIFF OMITTED] TP09SE11.010
Where:
* * * * *
Vv = Total volume of blowndown equipment chambers
(including pipelines, compressors and vessels) between isolation
valves in cubic feet.
* * * * *
[[Page 56044]]
[GRAPHIC] [TIFF OMITTED] TP09SE11.011
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 ([deg]F).
Ta = Temperature at actual conditions in the blowdown
equipment chamber ([deg]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.
* * * * *
(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 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 sub-basin
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
Sec. 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
Sec. 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 Sec. 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 Sec. 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 Sec. 98.233(k)(1) of this section to detect
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) * * *
[GRAPHIC] [TIFF OMITTED] TP09SE11.012
* * * * *
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 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 Sec. 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.
[[Page 56045]]
(o) * * *
(6) * * *
* * * * *
MTm = Flow Measurements from all centrifugal compressor
vents in each mode in (o)(1)(i) through (o)(1)(iii) of this section
in standard cubic feet per hour.
* * * * *
(p) * * *
(7) * * *
(i) * * *
* * * * *
MTm = Meter readings from all reciprocating compressor
vents in each and mode, m, in standard cubic feet per hour.
* * * * *
(q) * * *
* * * * *
[GRAPHIC] [TIFF OMITTED] TP09SE11.013
* * * * *
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 x
10-2 for CO2; for facilities listed in Sec.
98.230(a)(6) and (a)(7), GHGi equals 1 for CH4
and 0 for CO2; and for facilities listed in Sec.
98.230(a)(8), GHGi equals 1 for CH4 and 1.1 x
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.
* * * * *
(8) Natural gas distribution facilities for above grade
transmission-distribution 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 stations. Below grade transmission-distribution
transfer stations and metering-regulating stations that do not meet the
definition of transmission-distribution transfer stations are not
required to perform component leak detection under this section.
(r) * * *
* * * * *
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 Sec. 98.230(a)(4) and (a)(5), GHGi
equals 0.952 for CH4 and 1.0 x 10-2 for
CO2; for facilities listed in Sec. 98.230(a)(6) and
(a)(7), GHGi equals 1 for CH4 and 0 for
CO2; and for facilities listed in Sec. 98.230(a)(8),
GHGi equals 1 for CH4 and 1.1 x
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.
[GRAPHIC] [TIFF OMITTED] TP09SE11.014
Where:
EFi = Facility emission factor for a meter/regulator run
at above grade metering-regulating 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 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 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
[[Page 56046]]
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 Sec. 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 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.
[rho]i = Density of GHG i. Use 0.0520 kg/ft\3\ for
CO2 and N2O, and 0.0190 kg/ft\3\ for
CH4 at 68 [deg]F and 14.7 psia or 0.0530 kg/ft\3\ for
CO2 and N2O, and 0.0193 kg/ft\3\ for
CH4 at 60 [deg]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 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).
Sec. 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, Sec. 60.18 of the Alternative work practice for
monitoring equipment leaks, Sec. 60.18(i)(1)(i); Sec. 60.18(i)(2)(i)
except that the monitoring frequency shall be annual using the
detection
[[Page 56047]]
sensitivity level of 60 grams per hour as stated in 40 CFR part 60,
subpart A, Table 1: Detection Sensitivity Levels; Sec. 60.18(i)(2)(ii)
and (iii) except the gas chosen shall be methane, and Sec.
60.18(i)(2)(iv) and (v); Sec. 60.18(i)(3); Sec. 60.18(i)(4)(i) and
(v); including the requirements for daily instrument checks and
distances, and excluding requirements for video records. Any emissions
detected by the optical gas imaging instrument 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 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 Sec. 98.233(t). Estimate
CH4 and CO2 volumetric and mass emissions from
volumetric natural gas emissions using the calculations in Sec.
98.233(u) and (v).
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).
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:
Sec. 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.
[[Page 56048]]
(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
Sec. 98.233(d), annual average fraction of CO2 content in
the vent from the acid gas removal unit (refer to Sec. 98.233(d)(6)).
(iii) For Calculation Methodology 3 of Sec. 98.233(d), annual
average volume fraction of CO2 content of natural gas into
and out of the acid gas removal unit (refer to Sec. 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 Sec. 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.
(5) For well venting for liquids unloading (refer to Equations W-7,
W-8 and W-9 of Sec. 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 Sec.
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 Sec. 98.233):
* * * * *
(B) Average flow rate of the measured well completion venting in
cubic feet per hour (refer to Equation W-12 of Sec. 98.233).
* * * * *
(D) Average flow rate of the measured well workover venting in
cubic feet per hour (refer to Equation W-12 of Sec. 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.
(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 Sec. 98.233(j), report the following by sub-basin 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 Sec. 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 Sec. 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 Sec. 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 Sec.
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 Sec. 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 Sec.
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
[[Page 56049]]
Calculation Methodology 3 and 4 of Sec. 98.233(j).
(iii) For wellhead gas-liquid separators and wells with throughput
less than 10 barrels per day, using Calculation Methodology 5 of Sec.
98.233(j) Equation W-15 of Sec. 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 Sec. 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 Sec.
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 Sec. 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 Sec. 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 Sec. 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, 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 Sec. 98.233).
(vii) Report uncombusted CO2 emissions, in metric tons
CO2e (refer to Equation W-20 of Sec. 98.233).
(viii) Report combusted CO2 emissions, in metric tons
CO2e (refer to Equation W-21 of Sec. 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 Sec.
98.233).
(C) Annual CO2 and CH4 emissions, in metric
tons CO2e for each gas (refer to Equation W-30 of Sec.
98.233), by equipment type.
(ii) * * *
(A) For source categories Sec. 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 Sec. 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 Sec.
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 metering-regulating stations (this
count will include above grade T-D transfer stations).
(iv) Number of below grade metering-regulating stations (this count
will include below grade T-D transfer stations).
(v) [Reserved].
(vi) Above grade metering-regulating station leak factor (refer to
Equation W-32 of Sec. 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
metering-regulating 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 Sec. 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:
Sec. 98.237 Records that must be retained.
* * * * *
(e) The records required under Sec. 98.3(g)(2)(i) shall include an
explanation of how company records,
[[Page 56050]]
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:
Sec. 98.238 Definitions.
* * * * *
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 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 Sec. 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 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 meter-
regulating 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
[[Page 56051]]
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 Station\1\
Components, Gas Service
------------------------------------------------------------------------
* * * * * * *
------------------------------------------------------------------------
Population Emission Factors--Below Grade Metering-Regulating station\1\
Components, Gas Service\2\
------------------------------------------------------------------------
* * * * * * *
------------------------------------------------------------------------
Population Emission Factors--Distribution Mains, Gas Service\3\
------------------------------------------------------------------------
* * * * * * *
------------------------------------------------------------------------
Population Emission Factors--Distribution Services, Gas Service\4\
------------------------------------------------------------------------
* * * * * * *
------------------------------------------------------------------------
\1\ Excluding customer meters.
\2\ Emission Factor is in units of ``scf/hour/station.''
\3\ Emission Factor is in units of ``scf/hour/mile.''
\4\ Emission Factor is in units of ``scf/hour/number of services.''
[FR Doc. 2011-21725 Filed 9-8-11; 8:45 am]
BILLING CODE 6560-50-P