[Federal Register Volume 75, Number 69 (Monday, April 12, 2010)]
[Proposed Rules]
[Pages 18608-18650]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-6767]
[[Page 18607]]
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Part III
Environmental Protection Agency
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40 CFR Part 98
Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas
Systems; Proposed Rule
Federal Register / Vol. 75 , No. 69 / Monday, April 12, 2010 /
Proposed Rules
[[Page 18608]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 98
[EPA-HQ-OAR-2009-0923; FRL-9131-1]
RIN 2060-AP99
Mandatory Reporting of Greenhouse Gases: Petroleum and Natural
Gas Systems
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: EPA is proposing a supplemental rule to require reporting of
greenhouse gas (GHG) emissions from petroleum and natural gas systems.
Specifically, the proposed supplemental rulemaking would require
emissions reporting from the following industry segments: Onshore
petroleum and natural gas production, offshore petroleum and natural
gas production, natural gas processing, natural gas transmission
compressor stations, underground natural gas storage, liquefied natural
gas (LNG) storage, LNG import and export terminals, and distribution.
The proposed supplemental rulemaking does not require control of GHGs,
rather it requires only that sources above certain threshold levels
monitor and report emissions.
DATES: Comments must be received on or before June 11, 2010. There will
be one public hearing. The hearing will be on April 19, 2010 in
Arlington, VA and will begin at 8 a.m. local time and end at 5 p.m.
local time.
ADDRESSES: You may submit your comments, identified by docket EPA-HQ-
OAR-2009-0923 and/or RIN number 2060-AP99 by any of the following
methods:
Federal eRulemaking Portal: http://www.regulations.gov.
Follow the online instructions for submitting comments.
E-mail: [email protected]. Include EPA-HQ-OAR-2009-0923 and/or RIN number 2060-AP99
in the subject line of the message.
Fax: (202) 566-1741.
Phone: (202) 566-1744.
Mail: Environmental Protection Agency, EPA Docket Center
(EPA/DC), Attention Docket EPA-HQ-OAR-2009-0923, Mail Code 2822T, 1200
Pennsylvania Avenue, NW., Washington, DC 20460.
Hand/Courier Delivery: EPA Docket Center Public Reading
Room, Room 3334, EPA West Building, Attention Docket EPA-HQ-OAR-2009-
0923, 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-
2009-0923. 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 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 only in hard copy.
Publicly available docket materials are available either electronically
in http://www.regulations.gov or in hard copy at the Air Docket, EPA's
Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301
Constitution Ave., NW., Washington, DC 20004. 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 GENERAL 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: [email protected]. For technical information contact the
Greenhouse Gas Reporting Rule Hotline at telephone number: (877) 444-
1188; or e-mail: [email protected]. To obtain information about the public
hearings or to register to speak at the hearings, please go to http://www.epa.gov/climatechange/emissions/ghgrulemaking.html. Alternatively,
contact Carole Cook at 202-343-9263.
SUPPLEMENTARY INFORMATION: EPA first proposed Mandatory GHG Reporting
requirements for petroleum and natural gas systems (under 40 CFR, part
98, subpart W) in April 2009. EPA received a substantial number of
comments on this initial proposal for petroleum and natural gas
systems. For this reason, EPA decided not to finalize the rule for
petroleum and natural gas systems, and instead to propose a
supplemental rule.
EPA reviewed and considered comments submitted on the previous
proposal in drafting this proposed supplemental rulemaking. However, as
this is a new proposal, EPA is not here responding to comments on the
earlier version of this rule. Any comments must be submitted as
provided herein, to be considered. A more detailed background
concerning the subpart W rulemaking and proposed changes can be found
in section II-A.
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, 1200 Pennsylvania
Ave., NW., Washington, DC 20460, telephone (202) 343-9263, e-mail:
[email protected].
Although as indicated above, EPA previously proposed a version of
this rule, that proposal never became final. This is a newly proposed
rule and comments which were submitted on the earlier version of the
rule are not being considered in the context of this rule. Any parties
interested in commenting must do so at this time.
Regulated Entities. The Administrator determined that this action
is subject to the provisions of Clean Air Act (CAA) section 307(d). See
CAA section
[[Page 18609]]
307(d)(1)(V) (the provisions of section 307(d) apply to ``such other
actions as the Administrator may determine.''). This is a proposed
regulation. If finalized, these regulations would affect owners or
operators of petroleum and natural gas systems. Regulated categories
and entities include those listed in Table 1 of this preamble:
Table 1--Examples of Affected Entities by Category
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Source Category NAICS Examples of affected facilities
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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.
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Table 1 of this preamble is not intended to be exhaustive, but
rather provides a guide for readers regarding facilities likely to be
affected by this action. Table 1 of this preamble lists the types of
facilities that EPA is now aware could be potentially affected by the
reporting requirements. Other types of facilities listed in the table
could also be subject to reporting requirements. To determine whether
you are affected by this action, you should carefully examine the
applicability criteria found in proposed 40 CFR part 98, subpart A or
the relevant criteria in the sections related to petroleum and natural
gas systems. If you have questions regarding the applicability of this
action to a particular facility, consult the person listed in the
preceding FOR FURTHER INFORMATION CONTACT section.
Many facilities that are affected by the proposed supplemental rule
have GHG emissions from multiple source categories listed in Table 1 of
this preamble. Table 2 of this preamble has been developed as a guide
to help potential reporters in the petroleum and natural gas industry
subject to the proposed rule identify the source categories (by
subpart) that they may need to (1) consider in their facility
applicability determination, and/or (2) include in their reporting. The
table should only be seen as a guide. Additional subparts in 40 CFR
part 98 may be relevant for a given reporter. Similarly, not all listed
subparts are relevant for all reporters.
Table 2--Source Categories and Relevant Subparts
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Source category Other Subparts recommended for review to determine applicability
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Petroleum and Natural Gas 40 CFR part 98, subpart C.
Systems.
40 CFR part 98, subpart Y.
40 CFR part 98, subpart MM.
40 CFR part 98, subpart NN.
40 CFR part 98, subpart PP.
40 CFR part 98, subpart RR (proposed).
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Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
ASTM American Society for Testing and Materials
CAA Clean Air Act
CBI confidential business information
cf cubic feet
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e CO2-equivalent
EO Executive Order
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
GHG greenhouse gas
GWP global warming potential
ICR information collection request
IPCC Intergovernmental Panel on Climate Change
kg kilograms
LDCs local natural gas distribution companies
LNG liquefied natural gas
LPG liquefied petroleum gas
MRR mandatory GHG reporting rule
MMTCO2e million metric tons carbon dioxide equivalent
N2O nitrous oxide
NAICS North American Industry Classification System
NGLs natural gas liquids
OMB Office of Management and Budget
QA quality assurance
QA/QC quality assurance/quality control
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
SSM startup, shutdown, and malfunction
TCR The Climate Registry
TSD technical support document
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
VOC volatile organic compound(s)
WCI Western Climate Initiative
Table of Contents
I. Background
A. Organization of this Preamble
B. Background on the Proposed Rule
C. Legal Authority
D. Relationship to Other Federal, State and Regional Programs
II. Rationale for the Reporting, Recordkeeping and Verification
Requirements
A. Overview of Proposal
B. Summary of the Major Changes Since Initial Proposal
C. Definition of the Source Category
D. Selection of Reporting Threshold
E. Selection of Proposed Monitoring Methods
F. Selection of Procedures for Estimating Missing Data
G. Selection of Data Reporting Requirements
H. Selection of Records That Must Be Retained
III. Economic Impacts of the Proposed Rule
A. How were compliance costs estimated?
B. What are the costs of the proposed rule?
C. What are the economic impacts of the proposed rule?
D. What are the impacts of the proposed rule on small
businesses?
E. What are the benefits of the proposed rule for society?
IV. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and 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
[[Page 18610]]
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. Organization of This Preamble
This preamble is broken into several large sections, as detailed
above in the Table of Contents. The paragraphs below describe the
layout of the preamble and provide a brief summary of each section.
The first section of this preamble contains the basic background
information about the origin of this proposed supplemental rulemaking,
including a discussion of the initial proposed rule for petroleum and
natural gas systems. This section also discusses EPA's use of our legal
authority under the Clean Air Act to collect the proposed data, and the
benefits of collecting the data. The relationship between the mandatory
GHG reporting program and other mandatory and voluntary reporting
programs at the national, regional and State level also is discussed.
The second section of this preamble summarizes the general
provisions of this proposed supplemental rulemaking for petroleum and
natural gas systems. It also highlights the major changes between the
initial proposed rule and the supplemental rule that we are proposing
today, including changes in the scope of the proposed rule and the
monitoring methods proposed. This section then provides a brief summary
of, and rationale for, selection of key design elements. Specifically,
this section describes EPA's rationale for (i) the definition of the
source category (ii) selection of reporting thresholds (iii) selection
of monitoring methods, (iv) missing data procedures (v) proposed data
reporting requirements, and (vi) recordkeeping requirements. Thus, for
example, there is a specific discussion regarding appropriate
thresholds, monitoring methodologies and reporting and recordkeeping
requirements for each segment of the petroleum and natural gas industry
proposed for inclusion in the rule: onshore petroleum and natural gas
production, offshore petroleum and natural gas production, natural gas
processing, natural gas transmission compressor stations, natural gas
underground storage, LNG storage, LNG import and export terminals, and
distribution. EPA describes the proposed options for each design
element, as well as the other options considered. Throughout this
discussion, EPA highlights specific issues on which we solicit comment.
Please refer to the specific source category of interest for more
details.
The third section provides the summary of the cost impacts,
economic impacts, and benefits of this proposed rule from the Economic
Analysis. Finally, the last section discusses the various statutory and
executive order requirements applicable to this proposed rulemaking.
B. Background on the Proposed Rule
The Final Mandatory GHG Reporting Rule (``Final MRR''), (40 CFR
part 98) was signed by EPA Administrator Lisa Jackson on September 22,
2009 and published in the Federal Register on October 30, 2009 (74 FR
209 (October 30, 2009) pp. 56260-56519). The Final MRR which is
effective on December 29, 2009 included reporting of GHGs from
facilities and suppliers that EPA determined met the criteria in the
2008 Consolidated Appropriations Act.\1\ These source categories
capture approximately 85 percent of U.S. GHG emissions through
reporting by direct emitters as well as suppliers of fossil fuels and
industrial gases. There are, however, many additional types of data and
reporting that the Agency deems important and necessary to address an
issue as large and complex as climate change (e.g. indirect emissions
from electricity use). In that sense, one could view the Final MRR (40
CFR part 98) as focused on certain sources of emissions and upstream
suppliers. For information on existing programs at the Federal,
Regional and State levels that also collect valuable information to
inform and implement policies necessary to address climate change,
relationship of the Final MRR to EPA and U.S. government climate change
efforts and to other State and Regional Programs, see the Preamble to
the Final MRR.
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\1\ Consolidated Appropriations Act, 2008, Public Law 110-161,
121 Stat. 1844, 2128.
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In the April 2009 proposed mandatory GHG reporting rule the
petroleum and natural gas systems subcategory was included as Subpart
W. EPA received a number of lengthy, detailed comments regarding this
subpart W proposal. Some comments were focused on the significant cost
burden that the April 2009 proposed rule would impose on petroleum and
natural gas systems, whereas others focused on whether certain sources,
such as onshore production and distribution, that were not included in
the initial proposal, should be included. EPA recognized the concerns
raised by stakeholders, and decided not to finalize subpart W with the
Final MRR, but instead to propose a new supplemental rule for petroleum
and natural gas systems. This proposed supplemental rule incorporates a
number of changes including, but not limited to, different
methodologies that provide improved emissions coverage at a lower cost
burden to facilities than would have been covered under the initial
proposed rule; the inclusion of onshore production and distribution
facilities; and separate definitions for ``vented'' and ``fugitive''
emissions. As noted earlier, stakeholders should submit comments in the
context of this new proposed supplemental rule.
This proposed supplemental rule 40 CFR part 98, subpart W requires
annual reporting of fugitive and vented carbon dioxide (CO2)
and methane (CH4) emissions from petroleum and natural gas
systems facilities, as well as combustion-related CO2,
CH4, and nitrous oxide (N2O) emissions from
flares at those facilities, following the methods outlined in the
proposal. This proposed rule would also establish appropriate
thresholds and frequency for reporting, as well as provisions to ensure
the accuracy of emissions through monitoring, reporting and
recordkeeping requirements.
This proposed rule applies to facilities in specific segments of
the petroleum and natural gas industry that emit GHGs greater than or
equal to 25,000 metric tons of CO2 equivalent per year.
Reporting would be at the facility level.
C. Legal Authority
EPA is proposing this rule under its existing CAA authority,
specifically authorities provided in section 114 of the CAA. As
discussed further below and in ``Mandatory Greenhouse Gas Reporting
Rule: EPA's Response to Public Comments, Legal Issues'' (EPA-HQ-OAR-
2008-0508-2264), EPA is not citing the FY 2008 Consolidated
Appropriations Act as the statutory basis for this action. While that
law required that EPA spend no less than $3.5 million on a rule
requiring the mandatory reporting of GHG emissions, it is the CAA, not
the Appropriations Act, that EPA is citing as the authority to gather
the information proposed by this rule.
As stated in the Final MRR, 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 initial
proposed rule (74 FR 16448, April 10, 2009), section 114(a)(1) of the
CAA authorizes the Administrator to require emissions sources, persons
[[Page 18611]]
subject to the CAA, manufacturers of control 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.
EPA notes that comments were submitted on the initial rule proposal
questioning EPA's authority under the Clean Air Act to collect
emissions information from certain offshore petroleum and natural gas
platforms. Some commenters argued that EPA does not have the authority
to collect emissions information from offshore platforms located in
areas of the Western Gulf because they are under the jurisdiction of
the Department of the Interior. They cited, among other things, the
Outer Continental Shelf Act, 43 U.S.C. 1334. Without opining on the
accuracy of the commenter's summary of OCSLA or other law, we note that
even the commenter describes these authorities as relating to the
regulation of air emissions. Today's proposal does not regulate GHG
emissions; rather it gathers information to inform EPA's evaluation of
various CAA provisions. Moreover, EPA's authority under CAA Section 114
is broad, and extends to any person ``who the Administrator believes
may have information necessary for the purposes'' of carrying out the
CAA, even if that person is not subject to the CAA. Indeed, by
specifically authorizing EPA to collect information from both persons
subject to any requirement of the CAA, as well as any person who the
Administrator believes may have necessary information, Congress clearly
intended that EPA could gather information from a person not otherwise
subject to CAA requirements. EPA is comprehensively considering how to
address climate change under the CAA, including both regulatory and
non-regulatory options. The information from these and other offshore
platforms will inform our analyses, including options applicable to
emissions of any offshore platforms that EPA is authorized to regulate
under the CAA.
EPA is proposing to amend 40 CFR 98.2(a) so that the final MRR
applies to facilities located in the United States and on or under the
Outer Continental Shelf. These revisions are necessary to ensure that
any petroleum or natural gas platforms located on our under the Outer
Continental Shelf of the United States would be required to report
under this rule. In addition, EPA is proposing revisions to the
definition of United States to clarify that the United States includes
the territorial seas. Other facilities located offshore of the United
States covered by the mandatory reporting program at 40 CFR part 98
would also be affected by this change in the definition of United
States. Revising the definition of United States will also ensure that
facilities located offshore of the United States that are injecting
CO2 into sub-seabed for long-term containment will also be
required to report data regarding greenhouse gases. EPA is proposing a
separate rule on geologic sequestration and any comments specific to
that issue should be directed to the Agency on that rulemaking not this
one. Finally, in addition to the change to the definition of United
States, EPA is adding a definition of ``Outer Continental Shelf.'' This
definition is drawn from the definition in the U.S. Code. Together,
these changes make clear that the Mandatory GHG Reporting Rule applies
to facilities on land, in the territorial seas, or on or under the
Outer Continental Shelf, of the United States, and that otherwise meet
the applicability criteria of the rule.
For further information about EPA's legal authority, see the
proposed and final MRR.
D. Relationship to Other Federal, State and Regional Programs
In developing the initial proposal for mandatory reporting from
petroleum and natural gas systems that was released in April 2009, as
well as this supplemental proposed rulemaking, EPA reviewed monitoring
methods included in international guidance (e.g., Intergovernmental
Panel on Climate Change), as well as Federal voluntary programs (e.g.,
EPA Natural Gas STAR Program and the U.S. Department of Energy
Voluntary Reporting of Greenhouse Gases Program (1605(b)), corporate
protocols (e.g., World Resources Institute and World Business Council
for Sustainable Development GHG Protocol) and industry guidance (e.g.,
methodological guidance from the American Petroleum Institute, the
Interstate Natural Gas Association of America, and the American Gas
Association).
EPA also reviewed State reporting programs (e.g., California and
New Mexico) and Regional partnerships (e.g., The Climate Registry, the
Western Regional Air Partnership). These are important programs that
not only led the way in reporting of GHG emissions before the Federal
government acted but also assist in quantifying the GHG reductions
achieved by various policies. Many of these programs collect different
or additional data as compared to this proposed rule. For example,
State programs may establish lower thresholds for reporting, request
information on areas not addressed in EPA's reporting rule, or include
different data elements to support other programs (e.g., offsets). For
further discussion on the relationship of this proposed rule to other
programs, refer to the preamble to the Final MRR.
II. Rationale for the Reporting, Recordkeeping and Verification
Requirements
A. Overview of Proposal
The U.S. petroleum and natural gas industry encompasses hundreds of
thousands of wells, hundreds of processing facilities, and over a
million miles of transmission and distribution pipelines. This proposed
rule would apply to the calculation and reporting of vented, fugitive,
and flare combustion emissions from selected equipment at the following
facilities that emit equal to or greater than 25,000 metric tons of
CO2 equivalent per year from source categories covered by
the mandatory GHG reporting rule: offshore petroleum and natural gas
production facilities, onshore petroleum and natural gas production
facilities (including enhanced oil recovery (EOR)), onshore natural gas
processing facilities, onshore natural gas transmission compression
facilities, onshore natural gas storage facilities, LNG storage
facilities, LNG import and export facilities and natural gas
distribution facilities owned or operated by local distribution
companies (LDCs). This proposal does not address the production of gas
from landfills or manure management systems. Methods and reporting
procedures for stationary combustion emissions other than flares at
petroleum and natural gas industry facilities are covered under Subpart
C of the Final MRR.
This proposed supplemental rule incorporates a number of different
methodologies to provide improved emissions coverage at a lower cost
burden to affected facilities, as compared to the initial proposed
rule. In this supplemental proposal, EPA is requiring the use of direct
measurement of emissions for only the most significant emissions
sources where other options are not available, and proposing the use of
engineering estimates, emissions modeling software, and leak detection
and publicly available emission factors for most other vented and
fugitive sources. For smaller fugitive and inaccessible to plain view
sources, component count and population emissions factors are proposed.
In the case of offshore platforms, EPA is recommending that
[[Page 18612]]
emissions sources identified under the Minerals Management Services
(MMS) GOADS (Gulfwide Offshore Activities Data System) be used for
reporting, and the GOADS process be extended to platforms in other
Federal regions (i.e., California and Alaska) and in State waters. The
alternative methodologies proposed in this rule will provide similar or
better estimation of vented and fugitive CH4 and
CO2 emissions in the petroleum and gas industry, while
significantly reducing industry burden.
Under this supplemental proposal, facilities not already reporting
but required to report under subpart W would begin data collection in
2011 following the methods outlined in the proposed rule, and submit
data to EPA by March 31, 2012.
EPA would require reporting of calendar year 2011 emissions in 2012
because the data are crucial to the timely development of future GHG
policy and regulatory programs. In the Appropriation Act, Congress
requested EPA to develop this reporting program on an expedited
schedule, and Congressional inquiries along with public comments
reinforce that data collection for calendar year 2011 is a priority.
Delaying data collection until calendar year 2012 would mean the data
would not be received until 2013, which would likely be too late for
many ongoing GHG policy and program development needs.
EPA considered, but decided not to propose, the use of best
available monitoring methods for part (e.g., the first three months) or
all of the first year of data collection. EPA concluded that the time
period that would be allowed under this schedule is sufficient to allow
facilities to implement the monitoring methods that would be required
by the proposed rule. In general, the proposed monitors are widely
available and are not time consuming to install. Further, some of the
monitoring methods (e.g., use of emission factors) may not require the
installation of any monitoring equipment. Finally, the emissions
assessment may be done at any time during the year, and measurements do
not necessarily need to be undertaken during the first quarter.
EPA seeks comment on the proposal not to allow use of best
available monitoring methods for part or all of the first year of data
collection. Further, if commenters recommend that EPA allow the use of
best available monitoring methods for a designated time period (e.g.,
three months), EPA seeks comments on whether requests for use of best
available monitoring methods should only be approved for parameters
subject to direct measurement, or also in cases where engineering
calculations and/or emission factors are used.
Amendments to the General Provisions. In a separate rulemaking
package that was recently published (March 16, 2010), EPA issued minor
harmonizing changes to the general provisions for the GHG reporting
rule (40 CFR part 98, subpart A) to accommodate the addition of source
categories not included in the 2009 final rule (e.g., subparts proposed
in April 2009 but not finalized in 2009, any new subparts that may be
proposed in the future). The changes update 98.2(a) on rule
applicability and 98.3 regarding the reporting schedule to accommodate
any additional subparts and the schedule for their reporting
obligations (e.g., source categories finalized in 2010 would not begin
data collection until 2011 and reporting in 2012).
In particular, we restructured 40 CFR 98.2(a) to move the lists of
source categories from the text into tables. A table format improves
clarity and facilitates the addition of source categories that were not
included in calendar year 2010 reporting and would begin reporting in
future years. A table, versus list, approach allows other sections of
the rule to be updated automatically when the table is updated; a list
approach requires separate updates to the various list references each
time the list is changed. In addition to reformatting the 98.2(a)(1)-
(2) lists into tables, other sections of subpart A were reworded to
refer to the source category tables because the tables make it clear
which source categories are to be considered for determining the
applicability threshold and reporting requirements for calendar years
2010, 2011, and future years.
Because facilities with petroleum and natural gas systems (as
defined in proposed 40 CFR part 98, subpart W) would be subject to the
rule if facility emissions exceed 25,000 metric tons CO2e
per year, in today's rule we are proposing to add this source category
to those threshold categories referenced from 40 CFR 98.2(a)(2) whether
the reference is to a list or a table.\2\
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\2\ Since we are proposing to change the list of covered
subcategories to tables, we are not providing regulatory text in
this proposal because the preamble is clear.
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In today's proposal, we also propose to amend 40 CFR 98.6 to add
definitions for several terms used in proposed 40 CFR part 98, subpart
W and to clarify the meaning of certain terms for purposes of subpart
W. We also propose to amend 40 CFR 98.7 (incorporation by reference) to
include standard methods used in proposed subpart W. In particular, we
propose to incorporate by reference the AAPG-CSD Geologic Code
Provinces Code Map available from The American Association of Petroleum
Geologists Bulletin, Volume 75, No. 10 (October 1991) pages 1644-1651.
It would be used to define the geographic boundaries for reporting of
onshore oil and gas production systems. We also proposed to incorporate
by reference models, including Glycalc and E&P Tanks that would be used
to calculate emissions and were not developed by the Federal
government.
B. Summary of the Major Changes Since Initial Proposal
Mandatory GHG reporting requirements were proposed for Petroleum
and Natural Gas Systems under Subpart W in April 2009 along with a
number of other sectors of the economy. As noted in the Preamble to the
Final MRR, EPA received a number of lengthy, detailed comments
regarding Petroleum and Natural Gas Systems. In total, EPA received
comments from over 80 organizations and over 1,200 pages of formal
comments on the Petroleum and Gas Systems Initial Proposed Rule. Some
comments proposed simplified alternatives to the proposed reporting
requirements based on the potential that the proposed requirements
would entail significant burden and cost. Other comments addressed
whether to include onshore production and the distribution segment,
which were excluded from the initial proposal as EPA sought comments on
approaches for the level of reporting of fugitive and vented GHG
emissions from these segments (e.g., facility or corporate).
EPA has reviewed the comments and issues and suggestions raised by
stakeholders within and outside the petroleum and natural gas industry
related to emissions coverage and the level of cost burden in this
sector. In response, EPA is proposing a new supplemental rule for
Petroleum and Natural Gas Systems. This proposed supplemental rule now
incorporates all segments of the petroleum and gas industry, adding
onshore production and distribution.
Total fugitive, vented and combustion emissions estimated to be
covered in this supplemental proposed rulemaking amount to 351
MMTCO2e; 272 MMTCO2e from fugitive and vented
emissions and 79 MMTCO2e from combustion emissions.\3\
Fugitive and
[[Page 18613]]
vented emissions estimates included in the supplemental proposed
rulemaking are significantly higher than the 131 MMTCO2e
reported in the 2008 U.S. Inventory of Greenhouse Gases, due to the
inclusion of items believed to be under-reported in the inventory
(discussed further below).
---------------------------------------------------------------------------
\3\ Some petroleum and natural gas facilities will already be
required to report emissions from stationary combustion under the
MRR that was signed in September 2009. This proposed petroleum and
natural gas subpart will require additional facilities to report to
the MRR that are not currently required to report. These facilities
will have to report combustion, fugitive and vented emissions. These
incremental combustion emissions are estimated at 79
MMTCO2e.
---------------------------------------------------------------------------
Table W-1 summarizes the estimated fugitive, vented and combustion
emissions for the segments included in the initial proposal and the
added segments of onshore production and distribution. Additional
details can be found in the Economic Impact Analysis for the Mandatory
Reporting of Greenhouse Gas Emissions under Subpart W Supplemental Rule
(EPA-HQ-OAR-2009-0923).
Table W-1--Fugitive/Vented and Combustion Emissions From Petroleum and Natural Gas Systems, MMTCO2e
----------------------------------------------------------------------------------------------------------------
Fugitive and
Fugitive and vented Combustion
vented emissions: emissions:
Segment emissions: Supplemental Supplemental
Initial proposed proposed
proposed rule rulemaking rulemaking
----------------------------------------------------------------------------------------------------------------
Initial Proposed Rule Six Segments.............................. 85 94.3 9.8
Onshore Production.............................................. NA 154.9 69.3
Natural Gas Distribution........................................ NA 22.7 NA
-----------------------------------------------
Total Emissions............................................. 85 271.9 \1\ 79.1
----------------------------------------------------------------------------------------------------------------
\1\ This estimate reflects only incremental combustion emissions (i.e., only those combustion emissions from
facilities above and beyond what will already be required to be reported under the Final MRR). For example,
combustion-related emissions ftrom many natural gas processing plants are already required to be reported
under subpart C and are therefore not included here. The combustion estimate also includes combustion
emissions from flares.
Inclusion of onshore production and distribution results in
estimated fugitive and vented emissions that are more than triple the
estimated emissions in the initial rule proposal for petroleum and
natural gas systems.
In addition to expanding emissions coverage under the proposed
supplemental rule, EPA has assessed a number of alternative
methodologies that were either recommended by commenters or are known
to provide effective quantification of emissions at a significantly
lower cost burden. The changes include the use of:
Limited use of fugitive leak detection.
Leaker factors to quantify detected fugitive emissions.
Population factors and component count for fugitive
emissions that are widely scattered or inaccessible to plain view.
Use of existing MMS GOADS methods and calculated emissions
for offshore production facilities.
Modeling software to quantify glycol dehydrator and tank
emissions.
Engineering estimation for well venting from liquids
unloading.
Engineering estimation for well venting from completions
and workovers.
Engineering estimation for well testing and flaring.
Engineering estimation for flaring emissions.
Limited sampling to determine gas composition.
Another significant change in the proposed supplemental rule is the
use of the term ``fugitives''. The initial rule proposal from April
2009 included both vented and fugitive emissions sources, and
collectively defined both sources as ``fugitive''. EPA received a large
number of comments from industry stakeholders and others indicating
that this definition created confusion. Hence EPA is defining vented
emissions separately from fugitives in the supplemental proposed
rulemaking. For this supplemental rulemaking, emissions from the
petroleum and natural gas industry are defined as (1) vented emissions,
which include intentional or designed releases of CH4 and/or
CO2 containing natural gas or hydrocarbon gas (not including
stationary combustion flue gas) from emissions sources including, but
not limited to, process designed flow to the atmosphere through seals
or vent pipes, equipment blowdown for maintenance, and direct venting
of gas used to power equipment (such as pneumatic devices). In
addition, this supplemental rule includes (2) fugitive emissions, or
unintentional emissions, which are defined to include those emissions
which could not reasonably pass through a stack, chimney, vent, or
other functionally-equivalent opening. This supplemental rule also
includes (3) flare combustion emissions, which include CH4,
CO2 and N2O emissions resulting from combustion
of gas in flares. EPA seeks comment on the use of the term ``equipment
leak'' versus ``fugitive'' and ``vented'' as defined in the proposed
supplemental rule.
C. Definition of the Source Category
EPA discusses here the general approach used in identifying the key
segments of the petroleum and natural gas industry that would be
required to report under the proposal. This general discussion is
followed by a specific discussion for each industry segment.
One factor EPA considered in assessing the applicability of certain
petroleum and natural gas industry emissions in the proposed rule is
the definition of a facility. In other words, what physically
constitutes a facility? This definition is important to determine the
reporting entity, to ensure that delineation is clear, and to minimize
double counting or omissions of emissions. For some segments of the
industry (e.g., onshore natural gas processing facilities, natural gas
transmission compression facilities, and offshore petroleum and natural
gas facilities), identifying the facility is clear since there are
physical boundaries and ownership structures that lend themselves to
identifying scope of reporting and responsible reporting entities. In
other segments of the industry (e.g., the pipelines between compressor
stations and onshore petroleum and natural gas production) such
distinctions are not as
[[Page 18614]]
straightforward. In defining a facility, EPA reviewed current
definitions used in the Clean Air Act (CAA), ISO definitions, comments
provided under the initial proposed rule, and current regulations
relevant to the industry. A complete description of our assessment can
be found in Greenhouse Gas Emissions from the Petroleum and Natural Gas
Industry: Background Technical Support Document (TSD) (EPA-HQ-OAR-2009-
0923).
At the same time, EPA also decided that it was impractical to
include each of the over 160 different sources of vented and fugitive
CH4 and CO2 emissions in the petroleum and
natural gas industry. In response to comments received on the initial
proposed rule, EPA undertook a systematic review of each emissions
source included in the 2008 U.S. GHG Inventory in order to propose
reporting of only the most significant emissions sources (e.g.
emissions that account for the majority of oil and gas fugitive and
vented emissions). In determining the most relevant vented and fugitive
emissions sources for inclusion in this supplemental proposed
rulemaking, EPA considered the following criteria: The coverage of
emissions for the source category as a whole; the coverage of emissions
per unit of the source category; the feasibility of a viable monitoring
method, including direct measurement and engineering estimations; and
the number of facilities that would be required to report. Sources that
contribute significantly large emissions were considered for inclusion
in this supplemental proposed rulemaking, since they increase the
coverage of emissions reporting. Typically, at petroleum and gas
facilities, 80 percent or more of a facility's emissions come from
approximately 10 percent of the emissions sources. EPA used this
benchmark to reduce the number of emissions sources required for
reporting while keeping the reporting burden to a minimum. Sources in
each segment of the petroleum and natural gas industry were sorted into
two main categories: (1) The largest sources contributing to
approximately 80 percent of the emissions from the segment, and (2) the
sources contributing to the remaining 20 percent of the emissions from
that particular segment. EPA assigned sources into these two groups by
determining the emissions contribution of each emissions source to its
relevant segment of the petroleum and gas industry, listing the
emissions sources in a descending order, and identifying all the
sources at the top that contribute to approximately 80 percent of the
emissions. Generally, those sources that fell into approximately the
top 80 percent were considered for inclusion. Details of the analysis
can be found in Greenhouse Gas Emissions from the Petroleum and Natural
Gas Industry: Background TSD (EPA-HQ-OAR-2009-0923).
The following is a brief discussion of the proposed emission
sources to be included and excluded based on our analysis. Additional
information can be found in Greenhouse Gas Emissions from the Petroleum
and Natural Gas Industry: Background TSD (EPA-HQ-OAR-2009-0923. Note
that this subpart of the GHG reporting rule addresses only vented,
fugitive and flare combustion emissions. As mentioned previously,
stationary combustion emissions are included in Subpart C of the Final
MRR Preamble.
Onshore Petroleum and Natural Gas Production
The onshore petroleum and natural gas production segment uses wells
to extract raw natural gas, condensate, crude oil, and associated gas
from underground formations and inject CO2 for EOR.
Extraction includes several types of processes: Reservoir management,
primary recovery, secondary recovery such as down-hole pumps, water
flood or natural gas/nitrogen/immiscible CO2 injection, and
tertiary recovery such as using critical phase miscible CO2
injection. The largest sources of CH4 and CO2
emissions include, but are not limited to, natural gas driven pneumatic
devices and pumps, field crude oil and condensate storage tanks, glycol
dehydration units, releases and flaring during well completions, well
workovers, and well blowdowns for liquids unloading, releases and
flaring of associated gas, and blowdowns of compressors and EOR pumps.
EPA is proposing to include the onshore petroleum and natural gas
production segment due to the fact that these operations represent a
significant emissions source, representing approximately 66 percent of
fugitive, vented and incremental\4\ combustion emissions from the
petroleum and natural gas segments covered by the proposed rule.
---------------------------------------------------------------------------
\4\ The denominator includes total fugitive and vented
emissions, as well as any additional combustion related emissions
that will be required to be reported by the petroleum and natural
gas industry and that wasn't already covered in the final MRR.
---------------------------------------------------------------------------
EPA considered a range of possible options for reporting emissions
from onshore petroleum and natural gas facilities. Although several
options for defining the facility were considered and described below,
EPA has determined that only two of the options are feasible: Basin-
level reporting and field-level reporting. For this supplemental
proposed rulemaking, EPA proposes that emissions from onshore petroleum
and natural gas production be reported at the basin level. The
reporting entity for onshore petroleum and natural gas production would
be the operating entity listed on the state well drilling permit, or a
state operating permit for wells where no drilling permit is issued by
the state, who operates onshore petroleum and natural gas production
wells and controls by means of ownership (including leased and rented)
and operation (including contracted) stationary and portable (as
defined in this Subpart) equipment located on all well pads within a
single hydrocarbon basin as defined by the American Association of
Petroleum Geologists (AAPG) three-digit Geological Province Code. The
equipment referenced above includes all structures associated with
wells used in the production, extraction, recovery, lifting,
stabilization, separation or treating of petroleum and/or natural gas
(including condensate) including equipment that is leased, rented or
contracted. This includes equipment such as compressors, generators or
storage facilities, piping (such as flowlines or intra-facility
gathering lines), and portable non-self-propelled equipment (such as
well drilling and completion equipment, workover equipment, gravity
separation equipment, auxiliary non-transportation-related equipment).
This also includes associated storage or measurement equipment and all
equipment engaged in gathering produced gas from multiple wells, EOR
operations using CO2, and all petroleum and natural gas
production operations located on islands, artificial islands or
structures connected by a causeway to land, an island, or artificial
island.
Where more than one entity may hold the state well drilling permit,
or well operating permit where no drilling permit is issued by the
state, the permitted entities for the facility would be required to
designate one entity to report all emissions from the jointly
controlled facility. Where an operating entity holds more than one
permit to operate wells in a basin, then all onshore petroleum and
natural gas production well permits in their name in the basin,
including all equipment on the well pads, would be considered one
onshore petroleum and natural gas
[[Page 18615]]
production facility for purposes of reporting.
There are at least two industry recognized definitions available
that identify hydrocarbon basins; one from the United State Geological
Survey (USGS) and the other from the AAPG. The AAPG geologic definition
is referenced to county boundaries and hence likely to be familiar to
the industry, i.e. if the owner or operator knows in which county their
well is located, then they know to which basin they belong. Basins are
mapped to county boundaries only to give a surface manifestation to the
underground geologic structures, thus making it easier to relate
surface facilities to basin underground geologic boundaries. On the
other hand, the USGS definition is based purely on the geology of the
hydrocarbon basin without consideration of state and county boundaries.
Hence using the USGS definition may make it more difficult to map
surface operations to a particular basin. Therefore, EPA is proposing
to use the AAPG definition of a basin. EPA seeks comments on the
availability of other appropriate standard basin level definitions that
could be applied for the purposes of this rule and their merits over
the AAPG definition.
EPA is proposing a basin level approach, because the boundaries for
reporting are clearly defined and the approach covers approximately 81
percent of emissions from onshore petroleum and natural gas production.
EPA evaluated and is taking comment on one alternative option for
reporting from onshore petroleum and natural gas production; field
level. Field level reporting would require aggregation of emissions
from all covered equipment at onshore petroleum and natural gas
production facilities at the field level, as opposed to the basin level
as described above. A typical field level definition is available from
the Energy Information Administration Oil and Gas Field Code Master. As
outlined in the Economic Impact Analysis for this proposed rule, the
field level option would result in a significantly lower coverage in
emissions, estimated at 55 percent in comparison to the basin level
coverage of 81 percent. In essence the two reporting options are not
different from a methodological point of view because both definitions
rely on geographical boundaries. Therefore, EPA has proposed the use of
a basin level definition to increase coverage. EPA seeks comments on
our decision to propose the basin level approach, and whether there
would be advantages to requiring reporting at the field level instead.
In addition to basin and field level reporting, EPA considered one
other alternative approach for defining a facility for onshore
petroleum and natural gas production; individual well pads. This well
pad approach included all stationary and portable equipment operating
in conjunction with that well, including drilling rigs with their
ancillary equipment, gas/liquid separators, compressors, gas
dehydrators, crude oil heater-treaters, gas powered pneumatic
instruments and pumps, electrical generators, steam boilers and crude
oil and gas liquids stock tanks. This definition was analyzed with
available data including four cases to represent the full range of
petroleum and natural gas well pad operations ranging from
unconventional well drilling and operation starting in the beginning of
the year with higher emitting practices, to production at an associated
gas and oil well (no drilling) with minimal equipment and a vapor
recovery unit.
EPA analyzed the average emissions associated with each of the four
well pad facility cases and determined that average emissions at these
operations were low (from about 370 metric tons of CO2e per
year to slightly less than 5,000 metric tons of CO2e per
year). This analysis shows that the threshold would have to be set at
less than 400 metric tons CO2e per year to capture the
largest possible amount of onshore production emissions (only 33
percent) which would result in close to 170,000 reporters. Additional
information can be found in Greenhouse Gas Emissions from the Petroleum
and Natural Gas Industry: Background TSD (EPA-HQ-OAR-2009-0923). If the
threshold was set at approximately 5,000 metric tons, EPA estimates
that the number of reporters would decrease significantly to
approximate 3,300 but the emission coverage would be only 6 percent.
Based on the results above, EPA did not consider the well pad
definition further in the Economic Impact Analysis.
Offshore Petroleum and Natural Gas Production
Offshore petroleum and natural gas production is any platform
structure, affixed temporarily or permanently to offshore submerged
lands, that houses equipment to extract hydrocarbons from the ocean or
lake floor and that transfers such hydrocarbons to storage, transport
vessels, or onshore. In addition, offshore production includes
secondary platform structures and storage tanks associated with the
platform structure. GHG emissions result from sources housed on the
platforms.
In 2006, offshore petroleum and natural gas production
CO2 and CH4 emissions accounted for 5.1 million
metric tons CO2e. The primary sources of emissions from
offshore petroleum and natural gas production are from valves, flanges,
open-ended lines, compressor seals, platform vent stacks, and other
source types. Flare stacks account for the majority of combustion
CO2 emissions.
Offshore petroleum and natural gas production facilities are
proposed for inclusion due to the fact that this segment represents
approximately 1.9 percent of fugitive, vented and incremental \5\
combustion emissions from the petroleum and natural gas industry, an
existing activity data collection system already exists that can
readily be used to calculate GHG emissions (i.e., GOADS) and major
fugitive and vented emissions sources can be characterized by an
existing reasonable methodology which will minimize incremental burden
for reporters. This is consistent with comments received on the initial
proposed rule.
---------------------------------------------------------------------------
\5\ The denominator includes total fugitive and vented
emissions, as well as any additional combustion related emissions
that will be required to be reported by the petroleum and natural
gas industry and that wasn't already covered in the final MRR.
---------------------------------------------------------------------------
Onshore Natural Gas Processing
Natural gas processing facilities remove hydrocarbon and water
liquids and various other constituents (e.g., hydrogen sulfide, carbon
dioxide, helium, nitrogen, and hydrocarbons heavier than methane) from
the produced natural gas. The resulting ``pipeline quality'' natural
gas is transported to transmission pipelines. Natural gas processing
facilities also include gathering/boosting stations that dehydrate and
compress natural gas to be sent to natural gas processing facilities or
directly to natural gas transmission or distribution systems.
Compressors are used within gathering/boosting stations to adequately
pressurize the natural gas so that it can be transported to natural gas
processing, transmission, and distribution facilities through gathering
pipelines. In addition, compressors at natural gas processing
facilities are used to boost natural gas pressure so that it can pass
through all of the processes and into the high-pressure transmission
pipelines.
Vented and fugitive CH4 emissions from reciprocating and
centrifugal compressors, including centrifugal compressor wet and dry
seals, wet seal oil degassing vents, reciprocating compressor rod
packing vents, and all
[[Page 18616]]
other compressor emissions, are the primary CH4 emission
sources from this segment. The majority of vented CO2
emissions come from acid gas removal vent stacks, which are designed to
remove CO2 and hydrogen sulfide, when present, from natural
gas. While these are the major emissions sources in natural gas
processing facilities, other potential sources such as dehydrator vent
stacks, piping connectors, open-ended vent and drain lines and
gathering pipelines associated with the processing plant would also
need to be reported under the proposed supplemental rule.
Onshore natural gas processing facilities are proposed for
inclusion due to the fact that these operations represent a significant
emissions source, approximately 8 percent of fugitive, vented and
incremental \6\ combustion emissions from the natural gas segment,
methods are available to estimate emissions, and there are a reasonable
number of reporters. Most natural gas processing facilities proposed
for inclusion in this supplemental proposed rulemaking would already be
required to report under subpart C and/or subpart NN of the Final MRR.
---------------------------------------------------------------------------
\6\ The denominator includes total fugitive and vented
emissions, as well as any additional combustion related emissions
that will be required to be reported by the petroleum and natural
gas industry and that wasn't already covered in the final MRR.
---------------------------------------------------------------------------
Onshore Natural Gas Transmission Compression Facilities and Underground
Natural Gas Storage
Natural gas transmission compression facilities move natural gas
throughout the U.S. natural gas transmission system. Natural gas is
also injected and stored in underground formations during periods of
low demand (e.g., spring or fall) and withdrawn, processed, and
distributed during periods of high demand (e.g., winter or summer).
Storage compressor stations are dedicated to gas injection and
extraction at underground natural gas storage facilities.
Vented and fugitive CH4 emissions from reciprocating and
centrifugal compressors, including compressor and station blowdowns,
centrifugal compressor wet and dry seals, wet seal oil degassing vents,
reciprocating compressor rod packing vents, unit isolation valves,
blowdown valves, compressor scrubber dump valves, gas pneumatic
continuous bleed devices and all other compressor fugitive emissions,
are the primary CH4 emission source from natural gas
transmission compression stations and underground natural gas storage
facilities. Dehydrators are also a significant source of CH4
emissions from underground natural gas storage facilities. While these
are the major emissions sources in natural gas transmission, other
potential sources include, but are not limited to, condensate (water
and hydrocarbon) tanks, open-ended lines and valve stem seals.
Condensate tank vents in transmission can be a significant source of
emissions from malfunctioning compressor scrubber dump valves and will
require detection of such leakage by an optical imaging instrument and
direct measurement where found present.
Onshore natural gas transmission compression facilities and
underground natural gas storage facilities are proposed for inclusion
due to the fact that these operations represent significant sources of
fugitive, vented and incremental \7\ combustion emissions, 15 and 2
percent, respectively, methods are available to estimate emissions, and
there are a reasonable number of reporters. Further, this segment was
included in the initial proposed rule and EPA has made improvements to
the proposal based on comments received.
---------------------------------------------------------------------------
\7\ The denominator includes total fugitive and vented
emissions, as well as any additional combustion related emissions
that will be required to be reported by the petroleum and natural
gas industry and that wasn't already covered in the final MRR.
---------------------------------------------------------------------------
LNG Import and Export and LNG Storage
The U.S. imports and exports natural gas in the form of LNG, which
is received, stored, and, when needed, re-gasified at LNG import and
export terminals. Import and export include both LNG movements between
U.S. and foreign sources as well as transport between U.S. sources. LNG
storage facilities liquefy and store natural gas from processing plants
and transmission pipelines during periods of low demand (e.g., spring
or fall) and re-gasify for send out during periods of high demand
(e.g., summer and winter)
Fugitive and vented CH4 and CO2 emissions
from reciprocating and centrifugal compressors, including centrifugal
compressor wet and dry seals, wet seal degassing vents, reciprocating
compressor rod packing vents, and all other compressor fugitive
emissions, are the primary CH4 and CO2 emission
source from LNG storage facilities and LNG import and export
facilities. Process units at these facilities can include vapor
recovery compressors to re-liquefy natural gas tank boil-off (at LNG
storage facilities), re-condensers, vaporization units, tanker
unloading equipment (at LNG import terminals), transportation
pipelines, and/or LNG pumps.
LNG storage ``facilities'' can be defined as facilities that store
liquefied natural gas in above ground storage tanks. LNG import
terminal can be defined as onshore or offshore facilities that receive
imported LNG via ocean transport, store it in storage tanks, re-gasify
it, and deliver re-gasified natural gas to a natural gas transmission
or distribution system. LNG export terminal (facility) can be defined
as onshore or offshore facilities that receive natural gas, liquefy it,
store it in storage tanks, and send out the LNG via ocean
transportation, including to import facilities in the United States.
EPA is proposing inclusion of these facilities because the National
Inventory has very little data on methane emissions in these segments
which are expected to grow substantially in forward years.
Petroleum and Natural Gas Pipelines
Natural gas transmission involves high pressure, large diameter
pipelines that transport gas long distances from field production and
natural gas processing facilities to natural gas distribution pipelines
or large volume customers such as power plants or chemical plants.
Crude oil transportation involves pump stations and bulk tank terminals
to move crude oil through pipelines and loading and unloading crude oil
tanks, marine vessels, and railroad tank cars. The majority of vented
and fugitive emissions from the transportation of natural gas occur at
the compressor stations, which are proposed for inclusion in the
supplemental rule and discussed above.
EPA is not proposing to include reporting of fugitive emissions
from natural gas pipeline segments between compressor stations, or
crude oil pipelines and tank terminals in the supplemental rulemaking
due to the dispersed nature of the fugitive emissions, and the fact
that once fugitives are found, the emissions are generally addressed
quickly. For natural gas gathering pipelines, EPA is proposing that
producers who own or operate gathering lines associated with their
production fields and natural gas processors who own or operate
gathering lines associated with their processing plants should include
those gathering lines in their field or processing plant reported
emissions.
Natural Gas Distribution
Natural gas distribution facilities are local distribution
companies (LDCs) that
[[Page 18617]]
include the above grade (above ground) gas metering and pressure
regulation (M&R) equipment, M&R equipment below grade in vaults, buried
pipelines and customer meters used to transport natural gas primarily
from high pressure transmission pipelines to end users. In the
distribution segment, high-pressure gas from natural gas transmission
pipelines enters a ``city gate'' station, which reduces the pressure
and distributes the gas through primarily underground mains and service
lines to individual end users. Distribution system CH4 and
CO2 emissions result mainly from fugitive emissions from
above ground gate stations (metering and regulating stations), below
grade vaults (regulator stations), and fugitive emissions from buried
pipelines. At gate stations, fugitive and vented CH4
emissions primarily come from valves, open-ended lines, connectors,
pressure safety valves, and natural gas driven pneumatic devices.
CH4 emissions in vaults are entirely fugitive, primarily
from piping connectors to meters and regulators.
Although emissions from a single vault, gate station or segment of
pipeline in the natural gas distribution segment may not be
significant, collectively these emissions sources contribute a
significant share of emissions from natural gas systems.
EPA proposes to include natural gas distribution facilities because
these operations represent a significant emissions source,
approximately 6 percent of fugitive, vented and incremental \8\
combustion emissions from the petroleum and natural gas industry. EPA
proposes that LDC's would report for all of the distribution facilities
that they own or operate.
---------------------------------------------------------------------------
\8\ The denominator includes total fugitive and vented
emissions, as well as any additional combustion related emissions
that will be required to be reported by the petroleum and natural
gas industry and that wasn't already covered in the final MRR.
---------------------------------------------------------------------------
Crude Oil Transportation
Crude oil is commonly transported by barge, tanker, rail, truck,
and pipeline from production operations and import terminals to
petroleum refineries or export terminals. Typical equipment associated
with these operations is storage tanks and pumping stations. The major
sources of CH4 and CO2 emissions include releases
from tanks and marine vessel loading operations.
EPA is not proposing to include the crude oil transportation
segment of the petroleum and natural gas industry in this supplemental
rulemaking due to its small contribution to total petroleum and natural
gas CH4 and CO2 emissions, accounting for much
less than 1 percent.
D. Selection of Reporting Threshold
EPA proposes that owners or operators of facilities with emissions
equal to or greater than 25,000 metric tons CO2e per year be
subject to these reporting requirements. This threshold is applicable
to all petroleum and natural gas system reporters covered by this
subpart: onshore petroleum and natural gas production facilities,
offshore petroleum and natural gas production facilities, onshore
natural gas processing facilities, including gathering/boosting
stations; natural gas transmission compression facilities, underground
natural gas storage facilities; LNG storage facilities; LNG import and
export facilities and natural gas distribution facilities. As described
above, under the proposed rule, for onshore petroleum and natural gas
production facilities an owner or operator (as defined by the proposed
rule) would evaluate emissions from all equipment covered by the
proposed rule, including vented, fugitive, flared and stationary
combustion, in a defined basin against the threshold to determine
applicability.
Consistent with the rest of the Final MRR, EPA is proposing that
for the purposes of determining whether a facility emits equal to or
greater than a 25,000 mtCO2e, a facility must include
emissions from all source categories for which methods are provided in
the rule. EPA proposes that when a facility determines emissions for
the purposes of the threshold determination under subpart W, that the
fuel combustion emissions estimates include both stationary and
portable equipment (e.g., compressors, drilling rigs, and dehydrators
that are skid-mounted) that are controlled by well operators through
ownership, direct operation, leased and rented equipment, and
contracted operation. Fugitive, vented and combustion emissions from
portable equipment are proposed for inclusion in the threshold
determination for this source category due to the unique nature of the
petroleum and natural gas industry. In addition to well drilling rigs
and their ancillary equipment for well completions, it is common
practice in onshore production to use skid mounted portable
compressors, glycol dehydrators and other equipment partly for
installation cost savings and partly because well flow rates decline
over time and well-head equipment becomes over sized, and is moved
around to match equipment capacity with wells of the same production
capacity.
Also due to the unique nature of the industry, EPA believes that it
may be possible that onshore petroleum and natural gas production
equipment from onshore petroleum and natural gas production facilities
may be co-located with other manufacturing facilities already covered
under other subparts of the rule (e.g., cement manufacturing facilities
or glass manufacturing facilities). It is not EPA's intent to have
these manufacturing facilities include emissions from onshore petroleum
and natural gas production equipment in their threshold determination.
EPA seeks comment on this approach.
To identify the most appropriate threshold level for reporting of
emissions, EPA conducted analyses to determine emissions reporting
coverage and facility reporting coverage at four different threshold
levels: 1,000 metric tons CO2e per year, 10,000 metric tons
CO2e per year, 25,000 metric tons CO2e per year,
and 100,000 metric tons CO2e per year. Table W-2 provides
coverage of emissions and number of facilities reporting at each
threshold level for all the industry segments under consideration for
this proposed supplemental rule.
Table W-2--Threshold Analysis for Emissions From the Petroleum and Natural Gas Industry
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Total emissions covered Facilities covered
emissions by threshold ---------------------
Segment ---------------- Total number Threshold ---------------------------
(metric tons of facilities level (metric tons Number Percent
CO2e per year) CO2e per year) Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
Onshore Petroleum & Gas Production..................... 277,798,737 27,993 100,000 187,175,289 67 466 2
----------------------------------------------------------------
.............. .............. 25,000 224,227,559 81 1,232 4
----------------------------------------------------------------
[[Page 18618]]
.............. .............. 10,000 242,390,849 87 2,413 9
----------------------------------------------------------------
.............. .............. 1,000 268,848,529 97 10,604 38
--------------------------------------------------------------------------------------------------------------------------------------------------------
Offshore Petroleum & Gas Production.................... 11,261,305 3,235 100,000 3,242,389 29 4 0
----------------------------------------------------------------
.............. .............. 25,000 5,119,405 45 58 2
----------------------------------------------------------------
.............. .............. 10,000 7,111,563 63 184 6
----------------------------------------------------------------
.............. .............. 1,000 10,553,889 94 1192 37
--------------------------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Processing................................. 33,984,015 566 100,000 24,874,783 73 130 23
----------------------------------------------------------------
.............. .............. 25,000 31,229,071 92 289 51
----------------------------------------------------------------
.............. .............. 10,000 32,982,975 97 396 70
----------------------------------------------------------------
.............. .............. 1,000 33,984,015 100 566 100
--------------------------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Transmission Compression................... 64,059,125 1,944 100,000 34,518,927 54 433 22
----------------------------------------------------------------
.............. .............. 25,000 57,683,144 90 1,145 59
----------------------------------------------------------------
.............. .............. 10,000 62,672,905 98 1,443 74
----------------------------------------------------------------
.............. .............. 1,000 64,051,661 100 1,695 87
--------------------------------------------------------------------------------------------------------------------------------------------------------
Underground Natural Gas Storage........................ 9,713,029 397 100,000 3,548,988 37 36 9
----------------------------------------------------------------
.............. .............. 25,000 7,846,609 81 133 34
----------------------------------------------------------------
.............. .............. 10,000 8,968,994 92 200 50
----------------------------------------------------------------
.............. .............. 1,000 9,696,532 100 347 87
--------------------------------------------------------------------------------------------------------------------------------------------------------
LNG Storage............................................ 2,113,601 157 100,000 695,459 33 4 3
----------------------------------------------------------------
.............. .............. 25,000 1,900,793 90 33 21
----------------------------------------------------------------
.............. .............. 10,000 2,030,842 96 41 26
----------------------------------------------------------------
.............. .............. 1,000 2,096,974 99 54 34
--------------------------------------------------------------------------------------------------------------------------------------------------------
LNG Import and Export \2\.............................. 315,888 5 100,000 314,803 99.7 4 80
----------------------------------------------------------------
.............. .............. 25,000 314,803 99.7 4 80
----------------------------------------------------------------
.............. .............. 10,000 314,803 99.7 4 80
----------------------------------------------------------------
.............. .............. 1,000 315,888 100.00 5 100
--------------------------------------------------------------------------------------------------------------------------------------------------------
Natural Gas Distribution............................... 25,258,347 1,427 100,000 18,470,457 73 66 5
----------------------------------------------------------------
.............. .............. 25,000 22,741,042 90 143 10
----------------------------------------------------------------
.............. .............. 10,000 23,733,488 94 203 14
----------------------------------------------------------------
.............. .............. 1,000 24,983,115 99 594 42
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\The emissions include fugitive and vented CH4 and CO2 and combusted CO2, N2O, and CH4 gases. The emissions for each industry segment do not match the
2008 U.S. Inventory either because of added details in the estimation methodology or use of a different methodology than the U.S. Inventory. For
additional discussion, refer to Greenhouse Gas Emissions from the Petroleum and Natural Gas Industry: Background TSD (EPA-HQ-OAR-2009-0923).
\2\ The analysis included only import facilities. There is only one export facility, located in Kenai, Alaska.
[[Page 18619]]
EPA is proposing a threshold of 25,000 metric tons CO2e
applied to those emissions sources listed in Table W-2, which will
cover approximately 83 percent of estimated vented and fugitive
emissions and incremental combustion emissions from facilities that did
not meet the reporting requirements under Subpart C alone, from the
entire petroleum and natural gas industry, while requiring only a small
fraction of total facilities to report. For additional information,
please refer to Greenhouse Gas Emissions from the Petroleum and Natural
Gas Industry: Background TSD (EPA-HQ-OAR-2009-0923). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the Economic Impact
Analysis.
Although EPA is proposing an emissions threshold of 25,000
mtCO2e for all segments of the petroleum and natural gas
industry, EPA is taking comment on whether a 10,000 mtCO2e
threshold for onshore petroleum and natural gas production would be
more appropriate.
For onshore petroleum and natural gas production, EPA is proposing
that portable and stationary fuel combustion emissions be included in
the threshold determination due to the large percentage of emissions
from portable equipment in the petroleum and natural gas industry. EPA
considered lowering the threshold to 10,000 mtCO2e and
excluding portable equipment from the threshold determination (and
reporting), however, data were not available to distinguish portable
and stationary combustion emissions in order to evaluate the lower
threshold considering just stationary combustion emissions.
Secondly, for onshore petroleum and natural gas production, EPA is
proposing that owners or operators report at the basin level. EPA is
seeking comment on owners or operators reporting at the field level.
Although EPA believes that a 25,000 mtCO2e threshold is
appropriate for the basin level approach, as described above, EPA seeks
comment on whether the threshold should be lowered to 10,000
mtCO2e if reporting were to be at the field level. Table W-3
presents the emissions and facility coverage for a field level
definition for onshore petroleum and natural gas production.
Table W-3--Emissions Coverage and Entities Reporting for Field Level Facility Definition
----------------------------------------------------------------------------------------------------------------
Emissions covered Facilities covered
---------------------------------------------------------------
Threshold level \2\ Metric tons
CO2e/year Percent Number Percent
----------------------------------------------------------------------------------------------------------------
100,000......................................... 99,776,033 38 305 0
25,000.......................................... 144,547,282 55 1,253 2
10,000.......................................... 169,160,462 64 2,846 3
1,000........................................... 242,621,431 92 39,652 48
----------------------------------------------------------------------------------------------------------------
In addition to seeking comment on the proposed threshold for
onshore production, EPA more broadly is seeking comment on the
selection of the threshold for all segments of the petroleum and
natural gas industry.
E. Selection of Proposed Monitoring Methods
Many domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating emissions from petroleum
and natural gas operations, including the 2006 IPCC Guidelines, U.S.
GHG Inventory, DOE 1605(b), and corporate industry protocols developed
by the American Petroleum Institute, the Interstate Natural Gas
Association of America, and the American Gas Association. The
methodologies proposed vary by the emissions source and the level of
accuracy desired in the estimation.
EPA has carefully considered possible options to estimate emissions
from every emission source proposed for reporting. EPA has proposed to
use the most appropriate method taking into account both the cost to
the reporter as well as accuracy of emissions achieved through the
proposed method. Overall, we propose the following types of monitoring
methods: (1) Direct measurement to develop site and source-specific
emission factors; (2) engineering estimation; (3) combination of direct
measurement and engineering estimation; (4) leak detection and use of
leaker emission factor; and (5) population count and population
emission factors. Table W-4 of this preamble provides a list of the
emissions sources to be reported with the corresponding monitoring
methods.
A monitoring method proposed for a specific source is to be used
across all reporting segments of the petroleum and gas system. Two
exceptions to this are: (1) For tanks in onshore natural gas
transmission facilities that exhibit gas bypass from scrubber dump
valves, EPA is proposing to require direct measurement under the
proposal, whereas in other segments under the proposal, the emissions
from tanks would be required to be estimated using E&P Tank simulation
software; and (2) under the proposal, fugitive emissions from onshore
petroleum and natural gas production and inaccessible to plain view
(buried or below grade in vaults) emissions in gas distribution would
require estimation using population emissions factors as opposed to
other segments' fugitive emissions that require leak detection and the
use of leaker emissions factors. Finally, offshore petroleum and
natural gas production platforms would be required under the proposal
to use methods provided by the most recent GOADS reporting system. This
means that Federal Gulf of Mexico platforms would report emissions
already being calculated and reported to MMS as a part of the GOADS
study and the remaining platforms that are not a part of the GOADS
study (i.e., platforms in all state waters and other Federal waters
outside the Gulf of Mexico) would be required to adopt the GOADS
methodology.
Table W-4. Source Specific Monitoring Methods and Emissions
Quantification
------------------------------------------------------------------------
Emissions
Emission source Monitoring methods quantification
methods
------------------------------------------------------------------------
Natural Gas Pneumatic Bleed Engineering Manufacturer
Devices (High or Continuous). Estimation. device model
bleed rate and
engineering
calculation.
[[Page 18620]]
Natural Gas Pneumatic Bleed Component Count... Population
Devices (Low). emissions factor.
Natural Gas Driven Pneumatic Engineering Manufacturer model
Pump Venting. Estimation. emissions per
unit volume and
volume pumped.
Acid Gas Removal Vent Stacks Engineering Engineering
(CO2 only). Estimation. Calculation and
flow meters.
Dehydrator Vent Stacks.......... Engineering GlyCalc simulation
Estimation. software.
Well Venting for Liquids (1) Engineering (1) Field specific
Unloading. Estimation or (2) emission factor
Direct times events or
Measurement. (2) Flow metered
emission factor
times events.
Gas Well Venting during (1) Engineering (1) Field specific
Completions or Workovers. Estimation, or emission factor
(2) Direct times events or
Measurement. (2) Flow metered
emission factor
times events.
Blowdown Vent Stacks............ Engineering Equipment specific
Estimation. emission factor
and number of
events.
Storage Tanks (Onshore Engineering E&P Tank equipment
Production and Processing). Estimation. specific emission
factor times
throughput.
Storage Tanks (Transmission).... Direct Measurement Flow metered
emission factor
time operating
hours.
Well Testing Venting and Flaring Engineering Gas to oil Ratio
Estimation. (GOR); flow rate.
Associated Gas Venting and Engineering Gas to oil Ratio
Flaring. Estimation. (GOR); flow rate.
Flare Stacks.................... (1) Direct Engineering
Measurement or Calculation.
(2) Engineering
Estimation.
Centrifugal Compressor Wet Seal Direct Measurement Flow metered
Oil Degassing Vent. equipment
specific emission
factor times
operating hours.
Large Reciprocating Compressor Direct Measurement Flow metered
Rod Packing Vents. equipment
specific emission
factor times
operating hours.
Large Compressor Blowdown Valve Leak Detection Flow metered
Leak. with optical gas equipment
imaging specific emission
instrument. factor times
operating hours.
Large Compressor Blowdown Vent Leak Detection Flow metered
(Unit Isolation Valve Leak). with optical gas equipment
imaging specific emission
instrument. factor times
stand-by
depressurized
hours.
Fugitive Sources (Processing, Leak Detection Leaker emission
Transmission, Underground with optical gas factors times
Storage, LNG Storage, LNG imaging detected leaks.
Import Export, LDC). instrument.
Fugitive Sources (Onshore Component Count... Population
Production, LDC). Emission Factors
times components.
------------------------------------------------------------------------
1. Direct Measurement
EPA is proposing to require five sources in this supplemental
proposal to directly measure emissions: storage tanks (transmission)
when scrubber dump valves are detected leaking, centrifugal compressor
wet seal oil degassing vents, large reciprocating compressor rod
packing vents, large compressor blowdown vent valve leaks, and large
compressor blowdown vent (unit isolation valve leaks), the latter two
when leakage is detected. For example, storage tanks in the onshore
natural gas transmission segment typically store the condensate (water,
light hydrocarbons, seal oil) from the scrubbing of pipeline quality
gas. The volume and composition of liquid is typically low and
variable, respectively, in comparison to the volumes and composition of
hydrocarbon liquids stored in the upstream segments of the industry.
Hence the emissions from condensate itself in the transmission segment
are considered insignificant. However, scrubber dump valves malfunction
or stick-open due to debris in the condensate and can remain open
resulting in natural gas bypass via the open dump valve to and through
the condensate tank, and therefore the use of E&P Tanks and other
models are not applicable to tanks in the transmission segment. The
only potential option for measuring emissions from scrubber dump valves
is to monitor storage tank emissions with a gas imaging camera to
determine if the emissions do not subside and become negligible when
dump valves close. If the scrubber dump valve is stuck and leaking
natural gas through the tank then the emissions will be visibly
significant and will not subside to inconspicuous volumes. If the
scrubber dump valve functions normally and shuts completely after the
condensate has been dumped then the storage tank, emissions should
subside and taper off to insignificant quantities. If emissions are
detected to be continuous for a duration of five minutes then a one-
time measurement would be required using a temporary meter to establish
an equipment specific emission factor.
This proposal is based on the fact that the emissions magnitude
from these five sources are significant enough to warrant reporting for
the supplemental proposed rule and that no credible engineering
estimation methods or emissions factors exist that can accurately
characterize the emissions. There are several public reference studies
and guidance documents that provide emissions factors for these
sources. However, after close review, EPA has determined that these
emissions factors cannot uniquely characterize the emissions
specifically from individual equipment or a facility. For example, the
emissions from wet seal degassing and rod packing are directly
correlated to the size of the compressor, throughput, and the operating
time of the compressor in the reporting year. Also, in the case of unit
isolation valves and compressor blow down valves the emissions
magnitude varies depending on operational and maintenance practices as
valves can have excessive leakage, especially when a compressor is not
in operation. These factors do not get accounted for using an emissions
factor.
The proposed supplemental rule would require that rod packing and
blowdown valves be measured for emissions both in operating as well as
standby pressurized modes. In addition, unit isolation valve leaks
would be required to be measured at the
[[Page 18621]]
blowdown vent in the standby de-pressurized mode. To correctly quantify
emissions from centrifugal and large reciprocating compressors the
proposal would require that, for each compressor, one measurement be
taken in each of the operational modes that occurs during a reporting
period: (i) Operating, (ii) standby pressurized, and (iii) not
operating, depressurized. Depending on the operational practices each
mode could have significantly different emissions and would need to be
separately quantified as a part of the proposed rule.
For direct measurement, EPA proposes that the following
technologies be used: high volume samplers, meters (such as rotameters,
turbine meters, hot wire anemometers, and others), and/or calibrated
bags. EPA recognizes that different measurement equipment would be
required for different source emissions measurement depending on the
configuration of the system. Hence the proposed rule provides these
options for multiple direct measurement equipment, but the reporter
must calibrate and maintain the equipment based on either consensus
based standards or an appropriate method specified by the equipment
manufacturer, as specified in the proposed rule. Where a vent emission
source cannot be accessed on the ground or from a fixed platform, the
reporter has the choice of using a man-lift or installing either a
permanent or temporary vent line access port through which a meter can
be inserted to measure flow or velocity. If emissions exceed the
maximum range of one measurement instrument, the reporter would be
required to use a different instrument option that can measure larger
magnitude emissions levels. For example, if a high volume sampler
maximum rate is exceeded by an emissions source, then emissions would
be required to be directly measured using either calibrated bagging or
a meter. CH4 and CO2 emissions from the emissions
stream would be required to be calculated using the composition of the
gas in the process equipment (compressor).
2. Engineering Estimation
This proposed rule would require two main types of engineering
calculation methods for emissions; (1) volumetric calculation method,
and (2) engineering first principle methods.
(1) Volumetric Calculation Method
The volumetric calculation method has been proposed for calculating
CH4 and CO2 vent emissions from sources where the
variable in the emissions magnitude on an annual basis is the number of
times the source releases CH4 and CO2 emissions
to the atmosphere. In addition, the estimation of the total volume of
emissions is a matter of simple arithmetic calculation without the need
for complex calculations. For example, when a compressor is taken
offline for maintenance, the volume of CH4 and
CO2 blowdown vent emissions that are released is the same
during each release, is easily calculable, and the only variable is the
number of times the compressor is taken offline and vented.
(2) Engineering First Principle Methods
Emissions from sources such as tanks and glycol dehydrators can be
reliably calculated using standard engineering first principle methods
such as those available in E&P Tank and GlyCalc. The use of such
standard and readily available software is a cost-effective way to
uniformly estimate emissions that are representative for the two
sources. To maintain standardization across reporters the proposed rule
would require the use of E&P Tank for estimating the emissions from
well-pad separator conditions when flashed to atmospheric pressure in
any downstream stock tank, and GlyCalc for glycol dehydrators.
E&P Tank is available for free and GlyCalc can be purchased at a
small fee. Also, these two software models are widely used in the
industry and the operation of the software is well understood. Using
such software also addresses safety concerns that are associated with
direct measurement from the two sources. For example, sometimes the
temperature of the emissions stream for glycol dehydrator vent stacks
is too high for operators to safely measure emissions. EPA seeks
comment on whether there are additional or alternative software
packages to E&P Tank and GlyCalc that should be required to be used to
calculate emissions.
In cases where tank emissions do not represent equilibrium
conditions of the liquid in a gas-liquid separator and no publicly
available data are available on vapor bypass direct measurement would
be required under the proposal. For pressurized liquids sent to
atmospheric storage tanks where tank emissions are not expected to be
represented by the equilibrium conditions of the liquid in a gas-liquid
separator as calculated by the E&P Tank Model, then emissions
calculated by E&P Tank would be multiplied by an empirical factor.
The supplemental proposed rulemaking does not include emissions
from tanks containing primarily water with the exception of
transmission station condensate tanks where dump valve are determined
to be bypassing gas. Therefore, EPA seeks comments on how to quantify
emissions from tanks storing water without resulting in additional
reporting burden to the facilities.
For further discussion of these software programs and emissions
calculation methods, refer to Greenhouse Gas Emissions from the
Petroleum and Natural Gas Industry: Background TSD (EPA-HQ-OAR-2009-
0923).
3. Combination of Direct Measurement and Engineering Estimation
Several sources provide a choice between engineering estimation
based on operating data and direct measurement (if meters are already
installed). For continuous flaring, a one-time direct measurement or
engineering estimate may be performed in conjunction with engineering
estimation based on operating data that relates to the quantity of
flared gas. For well completion venting and well workover venting (each
during flowback after hydraulic fracturing, the only significant well
completion emissions), EPA explored the possibility of using a meter
for measuring hydrocarbon gas lost during these venting events which
may last from one to ten days. Some companies have reported directly
measuring these emissions under certain circumstances. However, such
metering could be technically challenging, if not impossible, and also
burdensome given the number of well completions and workovers being
conducted on an annual basis.
It is important to note, however, that no body of data has been
identified that can be summarized into generally applicable emissions
factors to characterize emissions from these sources in each unique
field. In fact, the emissions factor being used in the 2008 U.S. GHG
Inventory is believed to significantly underestimate emissions based on
industry experience as included in the Natural Gas STAR Program
publicly available information (http://www.epa.gov/gasstar/). In
addition, the 2008 U.S. GHG Inventory emissions factor was developed
prior to the boom in unconventional well drilling (1992) and in the
absence of any field data and does not capture the diversity of well
completion and workover operations or the variance in emissions that
can be expected from different hydrocarbon reservoirs in the country.
As a result, EPA proposes the development of a field-specific
emission factor either by direct measurement of
[[Page 18622]]
flow rate of hydrocarbons using a meter or by an engineering estimation
based on well choke pressure drop. Given the large number of well
completions and well workovers, EPA proposes that one representative
well completion and one well workover per field horizon be developed to
characterize emissions per day of venting from all other completions
and workovers in that field horizon. The reporter would be required to
update this factor every two years. This would alleviate burden but at
the same time achieve a reasonable characterization of the emissions
from these two sources.
5. Use of Leak Detection and Leaking Component Emission Factors
Each segment of the petroleum and gas system has a variety of
fugitive emissions sources that at a source type level have low
emissions volume, but combined together at a segment level contribute
significantly towards the total emissions from petroleum and gas
systems. EPA considered several options for estimating emissions from
fugitive emissions sources. One option considered was to use a
population count of each fugitive emissions source (e.g., source types
such as valves, connectors, etc.) and multiply it by a population
emissions factor. This option would not account for differences in
operational and maintenance practices among facilities. If population
emissions factors are used then the fugitive emissions from a
particular facility will remain constant indefinitely until the
facilities are modified (i.e., change the population of equipment) or
new factors are provided. This approach also will not account for
fugitive emissions reduction measures the industry has undertaken in
the last few years since the population emission factors were
developed. Facilities with good maintenance practices may have fugitive
emissions lower than the population emission factors. As described
further below, EPA requests comment on the use of emission factors and
ways in which these shortcomings may be overcome.
Another option considered was the use of fugitive emissions
detection (e.g., an infrared camera) and direct measurement (e.g.,
calibrated bags or high volume samplers) for fugitive sources. This
option may be more cost-effective when the sources of fugitive
emissions are in a relatively small geographic area such as at a
processing plant, gas compressor station, or distribution gate station.
This approach, however, could be less cost effective for widely
dispersed sources (e.g., well pads and gathering lines).
Hence, to overcome these issues, EPA proposes conducting fugitive
emissions detection and then applying leaking component (or leak only)
emissions factors for processing, transmission, underground storage,
LNG storage, LNG import and export terminals, and LDC gate stations.
The fugitive emissions leak detection method does not require
corresponding direct measurement of the fugitive emissions, which is
significantly more burdensome than fugitive emissions detection using
the most modern optical gas imaging instrument detection technology.
This method is an improvement over the use of population emissions
factors because the factors were developed for leaking components and
applied only to leaking components, leading to a more accurate
calculation of emissions from each piece of equipment. Several
commenters to the initial proposed rule recommended leak detection with
an optical gas imaging instrument and quantification with emission
factors. In addition, leaking component emissions factors are applied
only to those emissions sources that are determined to be emitting as a
result of the fugitive emissions detection process.
EPA analyzed new fugitive leak studies specifically performed on
natural gas facilities in processing plants and transmission compressor
stations, as recommended by several Subpart W initial proposed rule
commenters. Leaking component emissions factors from these studies were
compared with other studies (see below). EPA found that emission
factors generated from the Clearstone studies related better to
methane-rich stream fugitives and were more appropriate than other
emission factors developed for highly regulated refinery and
petrochemical plants on VOC emissions. Therefore, EPA is using
emissions data from the Clearstone studies as the basis for the leaker
factors proposed in this rule. EPA requests comments on the use of
emission factors from the Clearstone studies. For further details see
Greenhouse Gas Emissions from the Petroleum and Natural Gas Industry:
Background TSD (EPA-HQ-OAR-2009-0923).
Emission References for Petroleum and Natural Gas Systems
API. Compendium of Greenhouse Gas Emissions Methodologies for the
Oil and Gas Industry. American Petroleum Institute. Table 4-7, page 4-
30. February 2004.
API. Emission Factors for Oil and Gas Production Operations. Table
8, page 10. API Publication Number 4615. January 1995.
EPA. Identification and Evaluation of Opportunities to Reduce
Methane Losses at Four Gas Processing Plants. Clearstone Engineering
Ltd. June 20, 2002. http://www.epa.gov/gasstar/documents/four_plants.pdf.
EPA. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-
2007. Annexes. Tables A-112-A-125. U.S. EPA. April 2009. http://epa.gov/climatechange/emissions/downloads09/Annexes.pdf.
EPA. Lessons Learned: Replacing Wet Seals with Dry Seals in
Centrifugal Compressors. U.S. EPA 2006. http://www.epa.gov/gasstar/documents/ll_wetseals.pdf.
EPA. Protocol for Equipment Leak Emission Estimates. Emission
Standards Division. U.S. EPA. SOCMI Table 2-7. November 1995. http://www.epa.gov/ttn/chief/efdocs/equiplks.pdf.
GRI. Methane Emissions from the Natural Gas Industry. Volume 6.
Table 4-2 and Appendix A, page A-2. June 1996. http://www.epa.gov/gasstar/documents/emissions_report/6_vented.pdf.
GRI. Methane Emissions from the Natural Gas Industry. Volume 8.
Tables 4-3, 4-6 and 4-24. June 1996. http://www.epa.gov/gasstar/documents/emissions_report/8_equipmentleaks.pdf.
GRI. Methane Emissions from the Natural Gas Industry. Volume 9.
Tables 8-9 and 9-4. June 1996. http://www.epa.gov/gasstar/documents/emissions_report/9_underground.pdf.
GRI. Methane Emissions from the Natural Gas Industry. Volume 10.
Table 7-1. June 1996. http://epa.gov/gasstar/documents/emissions_report/10_metering.pdf.
ICF. Estimates of Methane Emissions from the U.S. Oil Industry.
Draft. Page 13. October 1999.
Clearstone. Handbook for Estimating Methane Emissions from Canadian
Natural Gas Systems. Clearstone Engineering Ltd., Enerco Engineering
Ltd., and Radian International. Pages 61-63. May 25, 1998.
National Gas Machinery Laboratory, Kansas State University;
Clearstone Engineering, Ltd.; Innovative Environmental Solutions, Inc.
Cost-Effective Directed Inspection and Maintenance Control
Opportunities at Five Gas Processing Plants and Upstream Gathering
Compressor Stations and Well Sites. For EPA Natural Gas STAR Program.
March 2006.
Clearstone. Handbook for Estimating Methane Emissions from Canadian
Natural Gas Systems. Clearstone Engineering Ltd., Enerco Engineering
Ltd, and Radian International. 2007.
[[Page 18623]]
EPA considered the use of the three major types of emissions
detection equipment: optical gas imaging instruments, IR laser detector
instruments and Toxic Vapor Analyzers (TVA) or Organic Vapor Analyzers
(OVA). Optical gas imaging instruments are able to scan hundreds of
source types quickly, allowing for the most efficient survey of
emissions at a broad range of facilities. In addition, EPA recently
adopted detailed performance standards for the optical gas imaging
camera in the Alternative work practice for monitoring equipment leaks
(AWP) (40 CFR part 60 subpart A Sec. 60.18(i)(1) and (2)). We
recognize that the purchase of optical gas imaging instruments can be
costly, especially for smaller facilities. However, EPA believes that
most facilities will opt for contractors to conduct emissions detection
once per year. As mentioned above, several commenters to the initial
proposed rule recommended leak detection with an optical gas imaging
instrument in accordance with the EPA AWP. Hence, the supplemental
proposed rule requires the use of an optical gas imaging instrument
compliant with the operational requirements of the EPA AWP. In contrast
to the EPA AWP, however, the proposed rule does not require multiple
surveys per year and does not require leak repair. As discussed further
below, for this proposed rule, EPA requires comprehensive annual leak
detection of the fugitive emissions sources specified in the proposed
rule. The proposed supplemental rule does not allow for the use of an
OVA/TVA. The OVA/TVA requires the operator to physically access the
emissions source with the probe and thus is much more time intensive
than using the optical gas imaging instrument. In addition, the OVA/TVA
range is limited to the reach of an operator standing on the ground or
fixed platform, thus excluding all emissions out of reach. However, EPA
is seeking comments on allowing the OVA/TVA to be used as another
option to the optical imaging camera in this proposed rule.
EPA is aware that the optical gas imaging instrument's ``detection
sensitivity levels'' as required by the AWP were established from data
on volatile organic compound (VOC) emissions from petroleum refineries
and chemical plants. The optical gas imaging instrument has been used
extensively to successfully detect methane emissions in the petroleum
and gas industry by petroleum and gas companies. A 2006 independent
study funded through a grant by EPA and conducted by Clearstone
Engineering, was an extensive study of methane emissions in gas
processing plants and upstream gathering compressor stations and well
sites. Method 21 was employed to detect leaks and HiFlow samplers were
used to determine the emissions from those leaks. This study surveyed
approximately 74,000 components finding 3,650 leaks (4.9 percent). Of
these leaks, 497 (<1 percent of total components) contributed 90
percent of the total fugitive emissions. The smallest of the 497 leaks
was 177 grams per hour, so an optical gas imaging instrument should be
able to adequately image methane leaks since the smallest leak was well
above the 60 to 100 gram per hour detection sensitivity in Table 1 of
the AWP. Therefore, for the purposes of this reporting rule, EPA
determined that an optical gas imaging instrument that meets the
detection sensitivity requirements of the AWP for any monitoring
frequency as specified in Table 1 of the AWP, is acceptable for use
under this proposed rule. Leak detection and leaker emission factors
only apply to emissions sources in streams with gas content greater
than 10 percent CH4 plus CO2 by weight. Emissions
sources in streams with gas content less than 10 percent CH4
plus CO2 by weight do not need to be reported.
The proposed rule requires that the survey for fugitive emissions
detection be comprehensive. This means that, on an annual basis, the
entire population of fugitive emissions sources proposed for reporting
in this rule would be surveyed at least once. EPA proposes that
emissions are quantified using leaker emissions factors. Under the
proposal, if a component fugitive emission is detected, emissions are
assumed to occur the entire 365 days in the year.
EPA is aware that the petroleum and natural gas industry is already
implementing voluntary fugitive emissions detection and repair
programs. Such voluntary programs are useful, but pose an accounting
challenge with respect to emissions reporting for this proposed rule.
The proposed approach does not preclude any owner or operator from
detecting and repairing fugitive emissions prior to quantifying
emissions for the purposes of reporting under this proposed rule.
To address this issue, EPA considered, but did not propose,
requiring a facility to conduct multiple surveys and to report
emissions using the appropriate leaker factors. Under this approach, if
a specific emission source is found not leaking in the initial survey
but leaking in subsequent surveys, emissions would be quantified from
the date of the first survey where a leak was detected forward through
the time when the leak is fixed, or the end of the year, whichever is
first. Similarly, if an emissions source is found to be leaking in the
initial survey, emissions would be quantified from the date of that
survey through to when the leak is repaired, or the end of the year,
whichever is first. Under this approach, emissions would reflect leak
reductions as determined by repairs and follow-up detection surveys
EPA seeks comment on whether this alternative approach better
estimates annual facility emissions without resulting in additional
reporting burden to the facilities. Further, we seek comment on
whether, if implemented, multiple surveys should be optional or
required for owners or operators.
6. Use of Population Count and Population Emission Factor
Fugitive emissions detection and use of leaking component emissions
factors are not always cost effective and can be burdensome. This is
particularly true of onshore petroleum and natural gas production where
the fugitive sources are spread out across large geographical areas and
fugitive emissions are a minor contributor to total segment emissions.
In the distribution segment, pipeline fugitive emissions are a large
fraction of total emissions, but the pipelines are buried where leaks
are difficult to detect. Similarly, metering/regulator stations, which
are an important source of fugitive emissions, are sometimes located
inside underground vaults that are difficult to access. In such
scenarios, fugitive emissions detection can be burdensome. Therefore,
for onshore petroleum and natural gas production, gas gathering
pipelines and LDC pipelines and M&R stations below grade in vaults, the
proposed rule requires the use of population count of emissions sources
and population emissions factor to estimate fugitive emissions.
Population count and population emission factors only apply to
emissions sources in streams with gas content greater than 10 percent
CH4 plus CO2 by weight. Emissions sources in
streams with gas content less than 10 percent CH4 plus
CO2 by weight do not need to be reported. EPA is using
emissions data from studies listed in the Emission References
(2, 4, 5, 7, 8, 9
above) as the basis for the population emissions factors proposed in
this rule. However, the API compendium emissions factors that we are
proposing to use in the upstream oil and gas production sector may be
underestimating emissions. EPA seeks comment on how to improve these
[[Page 18624]]
factors and/or collect more accurate data.
7. Alternative Monitoring Methods Considered
Before selecting the monitoring methods proposed above, we
considered additional measurement methods. The use of Method 21 was
considered for fugitive emissions detection and measurement. Although
Toxic Vapor Analyzers (TVA) and Organic Vapor Analyzers (OVA) were
considered they were not proposed for fugitive emissions detection and
quantification.
Method 21. This is the reference method for equipment leak
detection and repair regulations for volatile organic compound (VOC)
and hazardous air pollutant (HAP) emissions under several 40 CFR part
60, 40 CFR part 61, 40 CFR part 63, and 40 CFR part 65 emission
standards. Petroleum refineries, chemical plants and large gas
processing plants are required under state and federal laws to perform
LDAR (Leak Detection and Repair) to control VOC air pollution
emissions. LDAR programs require VOC and/or HAP leak detection using
instruments specified in Method 21, and requires repair of leaks if the
rate is above the leak definitions specified within the specific
regulation (typically between 500 parts per million to 10,000 parts per
million as read on an OVA). Some states and air quality districts have
lower leak definitions than the Federal standards. LDAR programs
require facilities to conduct multiple surveys per year: either
following equipment-specific frequencies using VOC monitoring
instruments, or bi-monthly, semi-quarterly or monthly using an optical
gas imaging instrument, frequency depending on the sensitivity
detection of the instrument. While LDAR programs do not require
quantification, state inventories of air emissions use this LDAR leak
detection data with ``leaker'' factors developed by the Synthetic
Organic Chemicals Manufacturing Industry (SOCMI) to estimate the
quantity of VOC emissions. These factors were developed from petroleum
refinery and petrochemical plant data using Method 21. SOCMI factors
adjusted for methane content are considerably lower than the methane
factors proposed in this rule, which were developed from more recent
studies of gas processing plants and compressor stations.
The Federal LDAR program recently adopted an alternative work
practice that allows use of optical gas imaging instruments in place of
the VOC monitoring instrument specified in Method 21. In a similar
vein, this rule proposes the use of optical gas imaging instruments to
detect leaks once per year, and has developed leaker factors specific
to methane from several recent studies quantifying component leaks in
petroleum and gas facilities. While this rule proposes a similar
approach to Method 21, given that this is a reporting rule for
collecting annual GHG emissions, there are several key differences: the
proposed annual reporting rule is focused on gathering fugitive and
vented CO2 and CH4 emissions, does not require
multiple surveys per year, and does not allow measurement using an OVA/
TVA for the reasons cited above. Optical gas imaging instruments were
found to be more appropriate for leak detection for the proposed
supplemental rule as these instruments are able to scan hundreds of
source components quickly, including components out of reach for an
OVA/TVA.
Mass Balance for Quantification. Except in one case, EPA
considered, but decided not to propose, the use of a mass balance
approach for quantifying emissions across an entire facility. This
approach would take into account the volume of gas entering a facility
and the amount exiting the facility, with the difference assumed to be
emitted to the atmosphere. This is most often discussed for emissions
estimation from the transportation segment of the industry. However,
for pipeline transportation, the mass balance is often not recommended
because of the uncertainties surrounding meter readings, the highly
variable line pack of high pressure gas and the large volumes of
throughput relative to emissions.
EPA is proposing this approach in the case of one emission source--
acid gas recovery units. Typically, the natural gas volumes and
compositions are measured both at the inlet and outlet of the acid gas
recovery units as it is required to ensure that natural gas meets
transmission system pipeline specifications. Hence, it is considered
sufficiently feasible to use the mass balance approach for this source.
For all other facilities and sources, the accuracy required in volume
measurements will be a significant added burden in addition to being
unreliable in many cases.
F. Selection of Procedures for Estimating Missing Data
The proposal requires data collection for a single source a minimum
of once a year. If data are lost or an error occurs during emissions
detection and/or measurement or calculation, the operator would be
required to carry out the detection, direct measurement, and/or
calculation a second time to obtain the relevant data point(s) as soon
as the missing data are discovered. If this falls outside of the
reporting year (e.g. between the end of the reporting year and the date
when the emissions must be reported) the operator would be required to
perform the necessary data development and report the results for the
previous year. This prior year's lost data replacement could not be
used as the one-time data collection for the current year. Where
missing data procedures are used for the previous year, at least 30
days would be required to separate emissions estimation and/or
measurements for the previous year and emissions estimation and/or
measurements for the current year of data collection in order to better
represent emissions estimates for different years. Similarly,
engineering estimates would account for relevant source counts and
frequency from the previous reporting period.
G. Selection of Data Reporting Requirements
EPA proposes that emissions from the petroleum and natural gas
industry be reported on an annual basis. The reporting should be by the
owner or operator of the facility as defined in the supplemental rule.
Emissions from each source type at the facility would be required to be
aggregated for reporting, with a few exceptions for field level
reporting (e.g., well completions and well workovers). For other
equipment, unit-level reporting would not be required. For example, the
owner or operator with multiple reciprocating compressors in an onshore
production basin would be required to report emissions collectively
from all rod packings on all cylinders from all compressors for all
fields in that basin as specified in this proposed rulemaking.
Generally, EPA has proposed that onshore production be reported at the
basin level, as opposed to the unit or field level, to minimize
reporting burden. EPA notes that in a concurrent proposed rulemaking
for facilities that conduct CO2 injection or geologic
sequestration (subpart RR), the term ``facility'' is defined at a more
disaggregated level, specifically as a ``well or group of wells.'' EPA
seeks comment on the use of more disaggregated reporting options for
subpart W.
Emissions from all sources proposed for monitoring, whether in
operating condition or on standby, would have to be reported. Any
emissions resulting from standby compressor sources would
[[Page 18625]]
be separately identified from the aggregate emissions.
The owner or operator would be required to report the following
information to EPA as a part of the annual emissions reporting:
fugitive, vented and flare combustion emissions monitored at an
aggregate source level (unless specified otherwise), emissions from
standby sources; and activity data for each aggregate source type
level. Owners or operators of natural gas distribution facilities would
report emissions at the individual station level.
Additional data are proposed to be reported to support
verification: Engineering estimate of total component count; total
number of compressors and average operating hours per year in each mode
of operation for compressors, if applicable; minimum, maximum and
average throughput per year; and specification of the type of any
control device used, including flares. For offshore petroleum and
natural gas production facilities, the number of connected wells, and
whether they are producing oil, gas, or both is proposed to be
reported. For compressors specifically, EPA proposes that the total
number of compressors of each type (reciprocating, centrifugal with dry
seals and centrifugal with wet seals) and average operating hours per
year be reported.
A full list of data proposed to be reported is included in proposed
40 CFR part 98, subparts A and W.
H. Selection of Records That Must Be Retained
The owner or operator shall retain relevant information associated
with the monitoring and reporting of emissions to EPA for three years
as follows: Throughput of the facility when the emissions direct
measurement was conducted; date(s) of measurement, detection and
measurement instruments used, if any; and results of the emissions
detection survey, including a video record of the leak survey.
A full list of records proposed to be retained is included in
proposed 40 CFR part 98, subparts A and W.
III. Economic Impacts of the Proposed Rule
This section of the preamble examines the costs and economic
impacts of this proposed supplemental rule, including the estimated
costs and benefits of the rule, and the estimated economic impacts of
the rule on affected entities, including estimated impacts on small
entities. Complete details of the economic impacts of the final rule
can be found in the text of the Economic Impact Analysis for the
Mandatory Reporting of Greenhouse Gas Emissions under Subpart W
Supplemental Rule (EPA-HQ-OAR-2009-0923). In brief, all equipment and
labor activities for complying with each emissions estimate in the rule
were analyzed by technical experts with relevant industry experience.
The estimated labor hours and labor categories were applied to each
industry segment, in some cases proportioned to small, medium and large
facilities where such variation exists, to quantify the total labor
hours, multiplied by Government statistics on labor rates, arriving at
the total labor and equipment costs for the estimated numbers of
sources. Administrative costs for reviewing the reporting rules,
training personnel, documenting emissions data and emissions estimates,
approving the submission to the EPA, submitting reports and maintaining
records were included for each reporting company. These total bottom-up
cost estimates were divided by the emissions captured to arrive at the
dollar per metric ton, and divided by the number of reporting entities
to arrive at average costs per entity. The methods proposed by EPA are
a balance between minimizing these costs, maximizing emissions coverage
and maximizing quality of emissions estimates. The cost to affected
parties on a dollar per metric ton has been reduced by greater than 50
percent when compared to the initial petroleum and natural gas
proposal. To achieve this cost reduction, EPA significantly modified
the rule to rely significantly less on direct measurement and more on
engineering estimates, leaker factors and emissions factors. Table W-5
and Table W-6 compare the first year and subsequent year costs,
respectively, to reporters for reporting fugitive and vented emissions
based on the reporting requirements proposed under the initial proposal
as compared to the new supplemental proposed rule.
Table W-5--Estimated First Year Cost for Reporting Fugitive and Vented Emissions for Petroleum and Natural Gas
Systems, MMTCO2E
----------------------------------------------------------------------------------------------------------------
Initial proposed rule1 New supplemental proposed
-------------------------------- rulemaking
Segment -------------------------------
Cost Cost per tonne Cost Cost per tonne
($million) ($/tonne) ($million) ($/tonne)
----------------------------------------------------------------------------------------------------------------
Original six segments........................... $32.5 $0.38 $26.7 $0.28
Onshore Production.............................. NA NA 27.7 0.18
Natural Gas Distribution........................ NA NA 1.6 0.07
---------------------------------------------------------------
Total Segments.............................. 32.5 0.38 56.0 0.21
----------------------------------------------------------------------------------------------------------------
\1\ The costs for the initial proposed rule, shown here, reflect the in-house monitoring option. Costs for the
alternative contractor monitoring option can be found in Docket EPA-HQ-OAR-2008-0508-0138.
TABLE W-6--Estimated Subsequent Year Cost for Reporting Fugitive and Vented Emissions for Petroleum and Natural
Gas Systems, MMTCO2E
----------------------------------------------------------------------------------------------------------------
Initial proposed rule New supplemental proposed
-------------------------------- rulemaking
Segment -------------------------------
Cost Cost per tonne Cost Cost per tonne
($million) ($/tonne) ($million) ($/tonne)
----------------------------------------------------------------------------------------------------------------
Original six segments........................... $28.1 $0.33 11.8 $0.13
Onshore Production.............................. NA NA 8.6 0.06
Natural Gas Distribution........................ NA NA 1.0 0.04
---------------------------------------------------------------
[[Page 18626]]
Total Segments.............................. $28.1 $0.33 21.4 0.08
----------------------------------------------------------------------------------------------------------------
\1\ Subsequent year in the initial proposed rule was defined as Year 2 whereas in the supplemental proposed rule
it is defined as the average of Years 2, 3, and 4.
A. How were compliance costs estimated?
1. Summary of EPA's Consideration of Comments Received on the Initial
Proposal
A majority of the comments received on the compliance costs of the
fugitive emissions reporting rule focused on facility level costs for
detection and measurement of emissions. Commenters noted that costs
estimated for certain petroleum and gas industry segments ignored
available data on average leak factors. Some who commented specifically
referred to government programs that gather similar, or in the case of
offshore petroleum and gas production in the Gulf of Mexico Federal
waters, some of the same data as required under Subpart W. Others who
commented noted that Subpart W had higher estimated compliance costs
than other sectors for much smaller GHG emissions.
EPA recognizes that the costs presented for some petroleum and gas
industry segments in the initial proposal were relatively high for
smaller emissions quantified than other industry sectors. EPA also
recognizes that for many fugitive and vented emissions sources, new
data exist on component emission factors, and long established data may
be justified for smaller, inaccessible to plain view or more burdensome
to identify emission sources. Furthermore, EPA recognizes that other
government programs gather similar or the same data as proposed by this
rule.
This proposed supplemental rule incorporates a number of different
methodologies to provide improved emissions coverage at a lower cost
burden to affected facilities. The approach used in determining the
appropriate methodology for the supplemental was to minimize the use of
direct measurement of emissions (which results in a higher cost burden
to affected facilities) except for the most significant emissions
sources where other options are not available, and to use engineering
estimates, emissions modeling software, and leak detection and publicly
available emission factors for most vented and fugitive sources. For
smaller fugitive and inaccessible to plain view (i.e. buried or below
grade in vaults) sources, component count and population emissions
factors are proposed. In the case of Offshore platforms, EPA is
recommending that emissions identified under the Minerals Management
Services (MMS) GOADS (Gulfwide Offshore Activities Data System) be used
for reporting, and the GOADS process be extended to platforms in other
Federal regions (i.e., California and Alaska) and all State waters.
These alternative methodologies will provide similar or better coverage
of vented and fugitive methane and carbon dioxide emissions in the
petroleum and gas industry, while significantly reducing industry
burden.
As described in the next section, EPA collected and evaluated cost
data from multiple sources, and weighed the analysis prepared at
initial proposal against the input received through public comments. In
any analysis of this type, there will be variations in costs among
facilities, and after thoroughly reviewing the available information,
we have concluded that the costs developed for this supplemental
proposed rule in each petroleum and gas industry segment appropriately
reflects a ``representative facility'' in those segments.
2. Summary of Method Used To Estimate Compliance Costs
EPA estimated costs of complying with the rule for reporting
fugitive and vented GHG emissions in each affected petroleum and gas
industry facility, as well as emissions from stationary combustion
sources at petroleum and gas industry facilities (for threshold and
burden analysis only; stationary combustion is reported under Subpart
C). This supplemental rulemaking proposes methodologies for reporting
fugitive and vented emissions from oil and gas facilities. Once
triggering the proposed rule, all of these facilities would also have
to report emissions from stationary combustion. The costs of compliance
for this proposed rule includes the costs associated with calculating
and reporting fugitive and vented emissions, as well as the costs of
any incremental combustion-related emissions that would be required to
be reported by facilities (i.e., combustion emissions that were not
already required to be reported under the final MRR). The
representative year of the analysis is 2006 and all annual costs were
estimated using the 2006 population of emitting sources. EPA used
available industry and EPA data to characterize conditions at affected
sources. Incremental monitoring, recordkeeping, and reporting
activities were then identified for each type of facility and the
associated costs were estimated.
The costs of complying with the rule will vary from one petroleum
and gas industry segment and facility to another, depending on the
types of emissions, the number of affected sources at the facility,
existing monitoring, recordkeeping, and reporting activities at the
facility, etc. The costs include labor costs for developing a plan,
setting up records, collecting field data, performing monitoring,
inputting field data into engineering models, recordkeeping, and
reporting activities necessary to comply with the rule. For some
facilities, costs include expenditures related to monitoring,
recording, and reporting both process emissions of GHGs and emissions
from stationary combustion. For other facilities (e.g., LDCs), the only
emissions of GHGs are process emissions. EPA's estimated costs of
compliance are discussed in greater detail below:
Labor Costs. The costs of complying with and administering this
rule include time of managers, technical, operational and
administrative staff in the private sector. Staff hours are estimated
for activities, including:
Developing a plan: reporting entity management and
technical staff hours to applicability to the rule, organize
indoctrination of rule requirements, identify staffing assignments,
train staff, schedule activities as required below.
[[Page 18627]]
Setting up records: technical and field staff hours to
develop data collection sheets and analytical model equations or
linkages to input data into standardized models
Collecting field data: technical and field staff hours to
collect necessary site-specific data and input that data into the
analytical input tables.
Monitoring: staff hours to procure, install, operate and
maintain emissions monitoring equipment, instruments and engineering
analysis systems.
Engineering models: technical staff hours to link and
execute engineering emissions estimation models and analytical
procedures and to organize output data as required for reporting
emissions.
Record keeping: staff hours required to organize, file and
secure critical data and emissions quantification results as required
for reporting and for documenting determinations of facilities
exceeding and not exceeding reporting thresholds.
Reporting: management and staff hours to organize data,
perform quality assurance/quality control, inform key management
personnel, and reporting it to EPA through electronic systems.
Staff activities and associated labor costs will vary from facility
to facility and potentially vary over time where first year start-up
costs are more significant and where site-specific emissions factors
are developed every two or three years. Thus, cost estimates are
developed for start-up and first-time reporting, and subsequent
reporting. Wage rates to monetize staff time are obtained from the
Bureau of Labor Statistics (BLS).
Equipment Costs. Equipment costs include both the initial purchase
price of monitoring equipment and any facility/process modification
that may be required for installation and/or use of monitoring
equipment. For example, the cost estimation method for large compressor
seal emissions includes both purchase of a flow measurement instrument
and installation of a measurement port in the vent piping where the end
of the vent is inaccessible. Based on expert judgment, the engineering
costs analyses annualized capital equipment costs with appropriate
lifetime and interest rate assumptions. Cost recovery periods and
interest rates vary by industry, but typically, one-time capital costs
are amortized over a 10-year cost recovery period at a rate of seven
percent.
B. What are the costs of the proposed rule?
1. Summary of Costs
For the cost analysis, EPA gathered existing data from EPA studies
and publications, industry trade associations and publicly available
data sources (e.g., labor rates from the BLS) to characterize the
processes, sources, sectors, facilities, and companies/entities
affected. EPA also considered cost data submitted in public comments on
the proposed rule. Costs were estimated on a per entity basis and then
weighted by the number of entities affected at the 25,000 metric tons
CO2e threshold.
To develop the costs for the rule, EPA estimated the number of
affected facilities in each source category, the number and types of
process equipment at each facility, the number and types of processes
that emit GHGs, process inputs and outputs (especially for monitoring
procedures that involve a carbon mass balance), and the measurements
that are already being made for reasons not associated with the rule
(to allow only the incremental costs to be estimated). Many of the
affected source categories, especially those that are the largest
emitters of GHGs (e.g., glycol dehydrators, petroleum stock tanks, gas
processing plants) are subject to national emission standards and we
use data generated in the development of these standards to estimate
the number of sources affected by the proposed reporting rule.
Other components of the cost analysis included estimates of labor
hours to perform specific activities, cost of labor, and cost of
monitoring equipment. Estimates of labor hours were based on previous
analyses of the costs of monitoring, reporting, and recordkeeping for
other rules; information from the industry characterization on the
number of units or process inputs and outputs to be monitored; and
engineering judgment by industry and EPA industry experts and
engineers. Labor costs were taken from the BLS and adjusted to account
for overhead. Monitoring costs were generally based on cost algorithms
or approaches that had been previously developed, reviewed, accepted as
adequate, and used specifically to estimate the costs associated with
various types of measurements and monitoring.
A detailed engineering analysis was conducted for each petroleum
and gas industry segment of this proposed rule to develop unique unit
costs. This analysis is documented in the Economic Impact Analysis for
the Mandatory Reporting of Greenhouse Gas Emissions under Subpart W
Supplemental Rule (EPA-HQ-OAR-2009-0923). The Greenhouse Gas Emissions
from the Petroleum and Natural Gas Industry: Background TSD (EPA-HQ-
OAR-2009-0923) provides a discussion of the applicable engineering
estimating and measurement technologies and any existing programs and
practices. Incremental combustion-related emissions that would be
required to be reported by facilities (as noted above) were estimated
using Tier 1 factors from Subpart C of the Final MRR. Section 4 of the
Economic Impact Analysis for the proposed rule contains a description
of the engineering cost analysis.
Table W-7 of this preamble presents: the emissions covered under
this proposed supplemental rule, the first year total costs and the
first year cost per ton for process and combustion emissions, and these
values for the subsequent years. EPA estimates that the total cost for
process emissions in the first year is $56.0 million, and the total
national annualized cost for subsequent years is $21.4 million (2006$).
Of these costs, roughly 49.5 percent fall upon the onshore production
segment in the first year, while 34.5 percent fall upon the gas
transmission segment. Offshore production, which is largely covered by
the MMS GOADS study data, is estimated to incur approximately 0.5
percent of costs every three or four years; other segments incurring
relatively large shares of costs are gas processing (12.5 percent) and
local distribution companies (3 percent). The reporting of incremental
combustion related emission for all segments of the petroleum and
natural gas industry are estimated to cost $3.9 million in both the
first and subsequent years.
The threshold, in large part, determines the number of entities
required to report GHG emissions and hence the costs of the rule. The
number of entities excluded increases with higher thresholds. Table W-8
of this preamble provides the cost-effectiveness analysis for various
thresholds examined. Two metrics are used to evaluate the cost-
effectiveness of the emissions threshold. The first is the average cost
per metric ton of emissions reported ($/metric ton CO2e).
The second metric for evaluating the threshold option is the
incremental cost of reporting emissions. The incremental cost is
calculated as the additional (incremental) cost per metric ton starting
with the least stringent option and moving successively from one
threshold option to the next. For more information about the first year
capital costs (unamortized), project lifetime and
[[Page 18628]]
the amortized (annualized) costs for each petroleum and gas industry
segment please refer to section 4 of the Economic Analysis for the
proposed rule. Not all segments require capital expenditures but those
that do are clearly documented in the Economic Impact Analysis for the
proposed rule.
Table W-7--National Cost Estimates for Petroleum and Natural Gas Systems
[2006$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
First year Subsequent years
-----------------------------------------------------------------------------
Subpart W--petroleum and natural gas systems NAICS $million\1\ $million
------------- Million $/ton ------------- Million $/ton
2006 MtCO2e 2006 MtCO2e
--------------------------------------------------------------------------------------------------------------------------------------------------------
Fugitive and Vented Emissions................................ 211, 486 $56 272.0 $0.21 $21.4 272.0 $0.08
Combustion Emissions......................................... ........... 3.9 79.1 0.05 3.9 79.1 0.05
------------------------------------------------------------------------------------------
Total Private Sector Emissions........................... ........... 59.9 351.1 0.17 25.3 351.1 0.07
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table W-8--Threshold Cost-Effectiveness Analysis
[Subsequent year, 2006$]
----------------------------------------------------------------------------------------------------------------
Percentage of
Threshold Facilities Total costs Downstream total Average Incremental
(metric tons required to (million emissions downstream reporting cost cost ($/
CO2e) report $2006) reported emissions ($/ton) metric ton)
(MtCO2e/year) reported \1\
----------------------------------------------------------------------------------------------------------------
100,000 1,143 $13.66 273 64 $0.05 $0.05
25,000 3,037 25.30 351 83 0.08 0.13
10,000 4,884 38.62 380 90 0.10 0.23
1,000 15,057 97.18 415 98 0.23 0.46
----------------------------------------------------------------------------------------------------------------
\1\ Cost per metric ton relative to the selected option.
C. What are the economic impacts of the proposed rule?
1. Summary of Economic Impacts
EPA prepared an economic impact analysis to evaluate the impacts of
the rule on affected small to large reporting entities. In evaluating
the various reporting options considered, EPA conducted a cost-
effectiveness analysis, comparing the cost per metric ton of GHG
emissions across reporting options. EPA used this information to
identify the preferred options described in today's proposed rule.
To estimate the economic impacts of the rule, EPA first conducted a
screening assessment, comparing the estimated total annualized
compliance costs for the petroleum and gas industry, where industry is
defined in terms of North American Industry Classification System
(NAICS) code, with industry average revenues. Overall national costs of
the rule are significant because there are a large number of affected
entities, but per-entity costs are low due to large coverage of
emissions from these entities. Average cost-to-sales ratios for
establishments in the affected NAICS codes for all segments is less
than 1 percent, except in the 1-20 employee range for the onshore
petroleum and natural gas segment.
These low average cost-to-sales ratios indicate that the proposed
rule is unlikely to result in significant changes in firms' production
decisions or other behavioral changes, and thus unlikely to result in
significant changes in prices or quantities in affected markets. Thus,
EPA followed its Guidelines for Preparing Economic Analyses (EPA, 2002,
p. 124-125) and used the engineering cost estimates to measure the
social cost of the rule, rather than modeling market responses and
using the resulting measures of social cost. Table W-9 of this preamble
summarizes cost-to-sales ratios for affected industries.
Table W-9--Estimated Cost-to-Sales Ratios for Affected Entities
[Year 1]
----------------------------------------------------------------------------------------------------------------
Average cost per Average entity
NAICS NAICS description entity ($1,000/ cost-to-sales
entity) ratio\1\
----------------------------------------------------------------------------------------------------------------
211..................................... Crude Petroleum and Natural Gas $24 0.11%
Extraction.
486210.................................. Pipeline Transportation of Natural 18 0.10%
Gas.
221210.................................. Natural Gas Distribution.......... 11 0.05%
----------------------------------------------------------------------------------------------------------------
\1\ This ratio reflects first year costs. Subsequent year costs will be slightly lower because they do not
include initial start-up activities.
[[Page 18629]]
D. What are the impacts of the proposed rule on small businesses?
1. Summary of Impacts on Small Businesses
As required by the RFA and Small Business Regulatory Enforcement
and Fairness ACT (SBREFA), EPA assessed the potential impacts of the
rule on small entities (small businesses, governments, and non-profit
organizations). (See Section IV.C of this preamble for definitions of
small entities.)
EPA has determined the selected threshold maximizes the rule
coverage with 83 percent of U.S. GHG emissions from the industry
segments reported by approximately 3,037 reporters, while keeping
reporting burden to a minimum. Furthermore, many industry stakeholders
that EPA met with expressed support for a 25,000 metric ton
CO2e threshold because it sufficiently captures the majority
of GHG emissions in the U.S., while excluding most of the smaller
facilities and sources. We received many comments related to monitoring
and reporting requirements in specific source categories, and made many
changes in response to reduce burden on reporters. For information on
these issues, refer to the discussion of each segment in this preamble.
EPA conducted a screening assessment comparing compliance costs to
onshore petroleum and natural gas production specific receipts data for
establishments owned by small businesses. This ratio constitutes a
``sales'' test that computes the annualized compliance costs of this
rule as a percentage of sales and determines whether the ratio exceeds
one percent.\9\ The cost-to-sales ratios were constructed at the
establishment level (average reporting program costs per establishment/
average establishment receipts) for several business size ranges. This
allowed EPA to account for receipt differences between establishments
owned by large and small businesses and differences in small business
definitions across affected industries. The results of the screening
assessment are shown in Table W-10 of this preamble.
---------------------------------------------------------------------------
\9\ EPA's RFA guidance for rule writers suggests the ``sales''
test continues to be the preferred quantitative metric for economic
impact screening analysis.
Table W-10.--Estimated Cost-to-Sales Ratios for First Year Costs by Industry and Enterprise Size\a\
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Average Owned by enterprises with:
SBA Size Standard cost per -------------------------------------------------------------------------------
Industry NAICS NAICS Description (effective March 11, entity All 100 to 500 to 750 to 1,000 to
2008) ($1,000/ enterprises <20 20 to 99 499 749 <500 999 1,499
entity) employees\f\ employees employees employees employees employees employees
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Onshore petroleum and natural gas 211 Crude Petroleum and 500 employees........ $24 0.11% 1.83% 0.16% 0.07% 0.03% 0.65% 0.04% 0.03%
production; offshore petroleum Natural Gas
and natural gas production; LNG Extraction.
storage; LNG import and export.
Onshore natural gas processing; 486210 Pipeline 7.5 million dollars.. 18 0.10 0.14 0.47 \b\ 0.28 \b\ ......... 0.12 ......... .........
onshore natural gas transmission; Transportation of
underground natural gas storage. Natural Gas.
Natural gas distribution.......... 221210 Natural Gas 7.5 million dollars.. 11 0.05 0.22 0.02 0.05 0.09 0.06 0.02 0.02
Distribution.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise
and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise--the enterprise employment and annual payroll are summed from the
associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.
Since the SBA's business size definitions (http://www.sba.gov/size) apply to an establishment's ultimate parent company, we assume in this analysis that the enterprise definition above is
consistent with the concept of ultimate parent company that is typically used for SBREFA screening analyses.
\2\ The Census Bureau has missing data ranges for this employee range. Hence the receipts are an underestimate of the true value. Therefore, the cost-to-sales ratio is a conservative estimate.
As shown, the cost-to-sales ratios are less than one percent for
establishments owned by small businesses that EPA considers most likely
to be covered by the reporting program, except the ratio for 1-20
employee range for crude petroleum and natural gas extraction, which is
greater than 1 percent but less than 2 percent. The petroleum and
natural gas industry has a large number of enterprises, the majority of
them in the 1-20 employee range. However, a large fraction of
production comes from large corporations and not those with less than
20 employee enterprises. The smaller enterprises in most cases deal
with very small operations (such as a single family owning a few
production wells) that are unlikely to cross even the 25,000 metric
tons CO2e threshold considered for the rule. An exception to
such a scenario is a small (less than 20 employee) enterprise owning
large operations but conducting nearly all of its operations through
contractors. This is not an uncommon practice in the onshore petroleum
and natural gas production segment. Such enterprises, however, are a
very small group among the over 19,000 enterprises in the less than 20
employee category and EPA proposes to cover them in the rule.
EPA took a conservative approach with the model entity analysis.
Although the appropriate SBA size definition should be applied at the
parent company (enterprise) level, data limitations allowed us only to
compute and compare ratios for a model establishment within several
enterprise size ranges.
Although this rule will not have a significant economic impact on a
substantial number of small entities, the Agency nonetheless tried to
reduce the impact of this rule on small entities, including seeking
input from a wide range of private- and public-sector
[[Page 18630]]
stakeholders. When developing the rule, the Agency took special steps
to ensure that the burdens imposed on small entities were minimal. The
Agency conducted several meetings with industry trade associations to
discuss regulatory options and the corresponding burden on industry,
such as recordkeeping and reporting. The Agency investigated
alternative thresholds and analyzed the marginal costs associated with
requiring smaller entities with lower emissions to report. The Agency
also recommended a hybrid method for reporting, which provides
flexibility to entities and helps minimize reporting costs.
E. What are the benefits of the proposed rule for society?
EPA examined the potential benefits of the proposed GHG reporting
rule for petroleum and natural gas systems. The benefits of a reporting
system are based on their relevance to policy making, transparency
issues, and market efficiency. Benefits are very difficult to quantify
and monetize. Instead of a quantitative analysis of the benefits, EPA
conducted a systematic literature review of existing studies including
government, consulting, and scholarly reports.
A mandatory reporting system for petroleum and natural gas systems
will benefit the public by increased transparency of facility emissions
data. Transparent, public data on emissions allows for accountability
of polluters to the public stakeholders who bear the cost of the
pollution. Citizens, community groups, and labor unions have made use
of data from Pollutant Release and Transfer Registers to negotiate
directly with polluters to lower emissions, circumventing greater
government regulation. Publicly available emissions data also will
allow individuals to alter their consumption habits based on the GHG
emissions of producers.
The greatest benefit of mandatory reporting of petroleum and
natural gas systems GHG emissions to government will be realized in
developing future GHG policies. For example, in the European Union's
Emissions Trading System, a lack of accurate monitoring at the facility
level before establishing CO2 allowance permits resulted in
allocation of permits for emissions levels an average of 15 percent
above actual levels in every country except the United Kingdom.
As the primary constituent of natural gas, methane is also an
important energy source. As a result, methane emissions reductions can
provide significant economic and environmental benefits. EPA has been
working in collaboration with oil and natural companies in the U.S. as
part of the Natural Gas STAR Program since 1993. Through this
collaborative partnership program, EPA has identified over 120 proven,
cost effective technologies and practices to reduce methane emissions
across operations in all of the major industry sectors--production,
gathering and processing, transmission, and distribution. The proposed
reporting rule will increase knowledge of the location and magnitude of
significant methane emissions sources in the oil and gas industry which
can result in cross-cutting benefits on domestic energy supply,
industrial efficiency and safety, and revenue generation.
Benefits to industry of GHG emissions monitoring include the value
of having independent, verifiable data to present to the public to
demonstrate appropriate environmental stewardship, and a better
understanding of their emission levels and sources to identify
opportunities to reduce emissions. Such monitoring allows for inclusion
of standardized GHG data into environmental management systems,
providing the necessary information to achieve and disseminate their
environmental achievements.
Standardization will also be a benefit to industry, once facilities
invest in the institutional knowledge and systems to report emissions,
the cost of monitoring should fall and the accuracy of the accounting
should improve. A standardized reporting program will also allow for
facilities to benchmark themselves against similar facilities to
understand better their relative standing within their industry.
Section VI of the RIA for the Final MRR summarizes the anticipated
benefits of the finalized rule, which include providing the government
with sound data on which to base future policies and providing industry
and the public independently verified information documenting firms'
environmental performance. While EPA has not quantified the benefits of
the mandatory reporting rule, EPA believes that they are substantial
and outweigh the estimated costs.
IV. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993),
this action is a ``significant regulatory action'' because it raises
novel legal or policy issues arising out of legal mandates, the
President's priorities, or the principles set forth in the EO.
Accordingly, EPA submitted this action to the Office of Management and
Budget (OMB) for review under EO 12866.
B. Paperwork Reduction Act
The information collection requirements in this proposed rule 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 prepared by EPA has been
assigned EPA ICR number 2376.01.
EPA plans to collect complete and accurate facility-level GHG
emissions from the petroleum and natural gas industry. Accurate and
timely information on GHG emissions is essential for informing future
climate change policy decisions. Through data collected under this
proposed rule, EPA will gain a better understanding of the relative
emissions of different segments of the petroleum and natural gas
industry and the distribution of emissions from individual facilities
within those industries. The facility-specific data will also improve
our understanding of the factors that influence GHG emission rates and
actions that facilities are already taking to reduce emissions.
Additionally, EPA will be able to track the trend of emissions from
facilities within the petroleum and natural gas industry over time,
particularly in response to policies and potential regulations. The
data collected by this proposed rule will improve EPA's ability to
formulate climate change policy options and to assess which segments of
the petroleum and gas industry would be affected, and how these
segments would be affected by the options.
This information collection is mandatory and will be carried out
under CAA section 114. Information identified and marked as CBI will
not be disclosed except in accordance with procedures set forth in 40
CFR part 2. However, emissions data collected under CAA section 114
cannot generally be claimed as CBI and will be made public.\10\
---------------------------------------------------------------------------
\10\ Although CBI determinations are usually made on a case-by-
case basis, EPA has issued guidance in an earlier Federal Register
notice on what constitutes emissions data that cannot be considered
CBI (956 FR 7042-7043, February 21, 1991). As discussed in Section
II.R of the Final MRR preamble, EPA is initiating a separate notice
and comment process to make CBI determinations for the data
collected under this rulemaking. EPA intends to issue this notice in
early 2010, and will include in the notice the data proposed for
collection in this rulemaking.
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The projected cost and hour burden for non-federal respondents is
$37.8 million and 478,774 hours per year. The
[[Page 18631]]
estimated average burden per response is 98.2 hours; the frequency of
response is annual for all respondents that must comply with the
proposed rule's reporting requirements; and the estimated average
number of likely respondents per year is 3,038. The cost burden to
respondents resulting from the collection of information includes the
total capital cost annualized over the equipment's expected useful life
(averaging $5.3 million), a total operation and maintenance component
(averaging $1.6 million per year), and a labor cost component
(averaging $30.9 million per year).\11\ Burden is defined at 5 CFR
1320.3(b).
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\11\ Burden is defined at 5 CFR 1320.3(b). These cost numbers
differ from those shown elsewhere in the Economic Analysis because
the ICR costs represent the average cost over the first three years
of the proposed rule, but costs are reported elsewhere in the
Economic Analysis for the first year of the proposed rule and for
subsequent years of the proposed rule. In addition, the ICR focuses
on respondent burden, while the Economic Analysis includes EPA
Agency costs.
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An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9.
To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, EPA has established a public docket for
this rule, which includes this ICR, under Docket ID number (EPA-HQ-OAR-
2009-0923). Submit any comments related to the ICR to EPA and OMB. See
ADDRESSES section at the beginning of this notice for where to submit
comments to EPA. Send comments to OMB at the Office of Information and
Regulatory Affairs, Office of Management and Budget, 725 17th Street,
NW., Washington, DC 20503, Attention: Desk Office for EPA. Since OMB is
required to make a decision concerning the ICR between 30 and 60 days
after April 12, 2010, a comment to OMB is best assured of having its
full effect if OMB receives it by May 12, 2010. The final rule will
respond to any OMB or public comments on the information collection
requirements contained in this proposal.
C. Regulatory Flexibility Act (RFA)
The 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 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. The small
entities directly regulated by this proposed rule include small
businesses in the petroleum and natural gas industry, small
governmental jurisdictions and small non-profits. We have determined
that some small businesses will be affected because their production
processes emit GHGs that must be reported.
The small entities directly regulated by this proposed rule include
small businesses in the petroleum and gas industry, small governmental
jurisdictions and small non-profits. We have determined that some small
businesses will be affected because their production processes emit
GHGs that must be reported.
For affected small entities, EPA conducted a screening assessment
comparing compliance costs for affected industry segments to petroleum
and gas-specific data on revenues for small businesses. This ratio
constitutes a ``sales'' test that computes the annualized compliance
costs of this proposed rule as a percentage of sales and determines
whether the ratio exceeds some level (e.g., 1 percent or 3 percent).
The cost-to-sales ratios were constructed at the establishment level
(average compliance cost for the establishment/average establishment
revenues).
As shown in Table W-10, the average ratio of annualized reporting
program costs to receipts of establishments owned by model small
enterprises was less than 1 percent for industries presumed likely to
have small businesses covered by the reporting program. Although the
costs to receipts for entities with 1-20 employees is over 1 percent,
these facilities would likely not exceed the proposed 25,000
mtCO2e threshold, a threshold supported by many stakeholders
as one that sufficiently captures the majority of GHG emissions while
excluding small facilities. Further, these sales tests examine the
average establishment's total annualized mandatory reporting costs to
the average establishment receipts for enterprises within several
employment categories. The average entity costs used to compute the
sales test are the same across all of these enterprise size categories.
As a result, the sales-test will overstate the cost-to-receipt ratio
for establishments owned by small businesses, because the reporting
costs are likely lower than average entity estimates provided by the
engineering cost analysis.
The screening analysis thus indicates that the proposed rule will
not have a significant economic impact on a substantial number of small
entities. The screening assessment for small governments for the Final
MRR compared the sum of average costs of compliance for combustion,
local distribution companies, and landfills to average revenues for
small governments. Even for a small government owning all three source
types, the costs constitute less than 1 percent of average revenues for
the smallest category of governments (those with fewer than 10,000
people).
Although this proposed rule will not have a significant economic
impact on a substantial number of small entities, EPA nonetheless took
several steps to reduce the impact of this proposed rule on small
entities. For example, EPA determined appropriate thresholds that
reduce the number of small businesses reporting. In addition, EPA is
proposing different monitoring methods for different emissions sources,
requiring direct measurement only for selected sources. Also, EPA is
proposing annual instead of more frequent reporting.
Through comprehensive outreach activities prior to proposal of the
initial rule, EPA held approximately 100 meetings and/or conference
calls with representatives of the primary audience groups, including
numerous trade associations and industries in the petroleum and gas
industry that include small business members. EPA's outreach activities
prior to proposal of the initial rule are documented in the memorandum,
``Summary of EPA Outreach Activities for Developing the Greenhouse Gas
Reporting Rule,'' located in Docket No. EPA-HQ-OAR-2008-0508-053. After
the initial proposal, EPA posted a guide for small businesses on the
EPA GHG reporting rule Web site, along with a general fact sheet for
the rule, information sheets for every source category, and an FAQ
document. EPA also operated a hotline
[[Page 18632]]
to answer questions about the proposed rule. We continued to meet with
stakeholders and entered documentation of all meetings into the docket.
During rule implementation, EPA would maintain an ``open door''
policy for stakeholders to ask questions about the proposed rule or
provide suggestions to EPA about the types of compliance assistance
that would be useful to small businesses. EPA intends to develop a
range of compliance assistance tools and materials and conduct
extensive outreach for the proposed rule.
We have therefore concluded that today's proposed rule will not
have a significant economic impact on a substantial number of small
entities. We continue to be interested in the potential impacts of the
proposed rule on small entities and welcome comments on issues related
to such impacts.
D. Unfunded Mandates Reform Act (UMRA)
The UMRA seeks to protect State, local, and Tribal governments from
the imposition of unfunded Federal mandates. In addition, the Act seeks
to strengthen the partnership between the Federal government and State,
local, and Tribal governments and ensure that the Federal government
covers the costs incurred during compliance with Federal mandates.
Title II of the UMRA of 1995, Public Law 104-4, establishes
requirements for Federal agencies to assess the effects of their
regulatory actions on State, local, and tribal governments and the
private segment. Under section 202 of UMRA, EPA generally must prepare
a written statement, including a cost-benefit analysis, for proposed
and final rules with Federal mandates that may result in expenditures
to State, local, and Tribal governments, in the aggregate, or to the
private segment, of $100 million or more in any one year.
Before promulgating an EPA rule for which a written statement is
needed, section 205 of UMRA generally requires EPA to identify and
consider a reasonable number of regulatory alternatives and adopt the
least costly, most cost-effective or least burdensome alternative that
achieves the objectives of the rule. The provisions of section 205 do
not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted.
Before EPA establishes any regulatory requirements that may
significantly or uniquely affect small governments, including Tribal
governments, it must have developed under section 203 of UMRA a small
government agency plan. The plan must provide for notifying potentially
affected small governments, enabling officials of affected small
governments to have meaningful and timely input in the development of
EPA regulatory proposals with significant Federal intergovernmental
mandates, and informing, educating, and advising small governments on
compliance with the regulatory requirements.
EPA has determined that the Subpart W rule does 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 segment in any one year. Expenditures associated with
compliance, defined as the incremental costs beyond the existing
regulations will not surpass $100 million in the aggregate in any year.
Thus, today's rule is not subject to the requirements of sections 202
and 205 of 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 regulation
applies to facilities that directly emit greenhouse gases. It does not
apply to governmental entities unless the government entity owns a
facility in the petroleum and gas industry that directly emits
greenhouse gases above threshold levels. In addition, this proposed
rule does not impose any implementation responsibilities on State,
local, or Tribal governments and it is not expected to increase the
cost of existing regulatory programs managed by those governments.
Thus, the impact on governments affected by the proposed rule is
expected to be minimal.
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. This regulation applies directly to
petroleum and natural gas facilities that emit greenhouse gases. Few,
if any, state or local government facilities would be affected. 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
EPA has concluded that this action may have tribal implications.
However, it will neither impose substantial direct compliance costs on
tribal governments, nor preempt Tribal law. This regulation would apply
directly to petroleum and natural gas facilities that emit greenhouses
gases. Although few facilities that would be subject to the rule are
likely to be owned by tribal governments, EPA has sought opportunities
to provide information to tribal governments and representatives during
rule development. EPA consulted with tribal officials early in the
process of developing this regulation to permit them to have meaningful
and timely input into its development. EPA sought opportunities to
provide information to Tribal governments and representatives during
development of the mandatory GHG reporting rule that was proposed in
April 2009 and finalized in September 2009. Today's action is a
supplemental proposal to that rule. In consultation with EPA's American
Indian Environment Office, EPA's outreach plan included tribes. EPA
conducted several conference calls with Tribal organizations during the
proposal phase. For example, EPA staff provided information to tribes
through conference calls with multiple Indian working groups and
organizations at EPA that interact with tribes and through individual
calls with two Tribal board members of TCR. In addition, EPA prepared a
short article on the GHG reporting rule that appeared on the front page
of a Tribal newsletter--Tribal Air News--that was distributed to EPA/
OAQPS's network of Tribal organizations. EPA gave a presentation on
various climate efforts, including the mandatory reporting rule, at the
National Tribal Conference on Environmental Management on June 24-26,
2008. In addition, EPA had copies of a short information sheet
distributed at a meeting of the National Tribal Caucus. See the
``Summary of EPA Outreach Activities for Developing the GHG reporting
rule,'' in Docket No. EPA-HQ-OAR-2008-0508-055 for a complete list of
Tribal contacts. EPA
[[Page 18633]]
participated in a conference call with Tribal air coordinators in April
2009 and prepared a guidance sheet for Tribal governments on the
proposed rule. It was posted on the MRR Web site and published in the
Tribal Air Newsletter.
EPA specifically solicits additional comment on this proposed rule
from Tribal officials.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
EPA interprets EO 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 EO has the
potential to influence the regulation. This action is not subject to EO
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 proposed rule is not a ``significant energy action'' as
defined in EO 13211 (66 FR 28355, May 22, 2001) because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. Further, we have concluded that this
proposed rule is not likely to have any adverse energy effects. This
proposed rule relates to monitoring, reporting and recordkeeping at
petroleum and gas facilities that emit over 25,000 mtCO2e
and does not impact energy supply, distribution or use. Therefore, we
conclude that this proposed rule is not likely to have any adverse
effects on energy supply, distribution, or use.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113 (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 rulemaking involves technical standards. EPA provides the
flexibility to use any one of the voluntary consensus standards from at
least seven different voluntary consensus standards bodies, including
the following: ASTM, ASME, ISO, Gas Processors Association, and
American Gas Association. These voluntary consensus standards will help
facilities monitor, report, and keep records of greenhouse gas
emissions. No new test methods were developed for this proposed rule.
Instead, from existing rules for source categories and voluntary
greenhouse gas programs, EPA identified existing means of monitoring,
reporting, and keeping records of greenhouse gas emissions. The
existing methods (voluntary consensus standards) include a broad range
of measurement techniques, including many for combustion sources such
as methods to analyze fuel and measure its heating value; methods to
measure gas or liquid flow; and methods to gauge and measure petroleum
and petroleum products.
By incorporating voluntary consensus standards into this proposed
rule, EPA is both meeting the requirements of the NTTAA and presenting
multiple options and flexibility for measuring greenhouse gas
emissions.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order (EO) 12898 (59 FR 7629 (Feb. 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.
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: March 22, 2010.
Lisa P. Jackson,
Administrator.
For the reasons stated in the preamble, the Environmental
Protection Agency proposes to amend 40 CFR part 98 as follows:
PART 98--MANDATORY GREENHOUSE GAS REPORTING
1. The authority citation for part 98 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart A--[Amended]
2. Section 98.2 is amended by revising paragraph (a) introductory
text to read as follows:
Sec. 98.2 Who must report?
(a) The GHG reporting requirements and related monitoring,
recordkeeping, and reporting requirements of this part apply to the
owners and operators of any facility that is located in the United
States or under or attached to the Outer Continental Shelf (as defined
in 43 U.S.C. 1331) and that meets the requirements of either paragraph
(a)(1), (a)(2), or (a)(3) of this section; and any supplier that meets
the requirements of paragraph (a)(4) of this section:
* * * * *
3. Section 98.6 is amended by adding the following definitions in
alphabetical order and revising the definition of ``United States'' to
read as follows:
Sec. 98.6 Definitions.
Absorbent circulation pump means a pump commonly powered by natural
gas pressure that circulates the absorbent liquid between the absorbent
regenerator and natural gas contactor.
* * * * *
Acid Gas means hydrogen sulfide (H2S) and carbon dioxide
(CO2) contaminants that are separated from sour natural gas
by an acid gas removal.
Acid Gas Removal unit (AGR) means a process unit that separates
hydrogen sulfide and/or carbon dioxide from sour natural gas using
liquid or solid absorbents or membrane separators.
Acid gas removal vent stack emissions mean the acid gas separated
from the acid gas absorbing medium (e.g., an amine solution) and
released with methane and other light hydrocarbons to the atmosphere or
a flare.
* * * * *
Air injected flare means a flare in which air is blown into the
base of a flare stack to induce complete combustion of low Btu natural
gas (i.e.,
[[Page 18634]]
high non-combustible component content).
* * * * *
Blowdown vent stack emissions mean natural gas released due to
maintenance and/or blowdown operations including but not limited to
compressor blowdown and emergency shut-down (ESD) system testing.
* * * * *
Calibrated bag means a flexible, non-elastic, anti-static bag of a
calibrated volume that can be affixed to a emitting source such that
the emissions inflate the bag to its calibrated volume.
* * * * *
Centrifugal compressor means any equipment that increases the
pressure of a process natural gas by centrifugal action, employing
rotating movement of the driven shaft.
Centrifugal compressor dry seals mean a series of rings around the
compressor shaft where it exits the compressor case that operates
mechanically under the opposing forces to prevent natural gas from
escaping to the atmosphere.
Centrifugal compressor dry seals emissions mean natural gas
released from a dry seal vent pipe and/or the seal face around the
rotating shaft where it exits one or both ends of the compressor case.
Centrifugal compressor wet seal degassing venting emissions means
emissions that occur when the high-pressure oil barriers for
centrifugal compressors are depressurized to release absorbed natural
gas. High-pressure oil is used as a barrier against escaping gas in
centrifugal compressor shafts. Very little gas escapes through the oil
barrier, but under high pressure, considerably more gas is absorbed by
the oil. The seal oil is purged of the absorbed gas (using heaters,
flash tanks, and degassing techniques) and recirculated. The separated
gas is commonly vented to the atmosphere.
* * * * *
Coal Bed Methane (CBM) means natural gas which is extracted from
underground coal deposits or ``beds.''
* * * * *
Component, for the purposes of subpart W only, means but is not
limited to each metal to metal joint or seal of non-welded connection
separated by a compression gasket, screwed thread (with or without
thread sealing compound), metal to metal compression, or fluid barrier
through which natural gas or liquid can escape to the atmosphere.
Compressor means any machine for raising the pressure of a natural
gas by drawing in low pressure natural gas and discharging
significantly higher pressure natural gas.
* * * * *
Condensate means hydrocarbon and other liquid separated from
natural gas that condenses due to changes in the temperature, pressure,
or both, and remains liquid at storage conditions, includes both water
and hydrocarbon liquids.
* * * * *
Conventional wells mean gas wells in producing fields that do not
employ hydraulic fracturing to produce commercially viable quantities
of natural gas.
* * * * *
Dehydrator means a device in which a liquid absorbent (including
but not limited to desiccant, ethylene glycol, diethylene glycol, or
triethylene glycol) directly contacts a natural gas stream to absorb
water vapor.
Dehydrator vent stack emissions means natural gas released from a
natural gas dehydrator system absorbent (typically glycol) reboiler or
regenerator, including stripping natural gas and motive natural gas
used in absorbent circulation pumps.
* * * * *
De-methanizer means the natural gas processing unit that separates
methane rich residue gas from the heavier hydrocarbons (e.g., ethane,
propane, butane, pentane-plus) in feed natural gas stream).
* * * * *
Desiccant means a material used in solid-bed dehydrators to remove
water from raw natural gas by adsorption. Desiccants include activated
alumina, palletized calcium chloride, lithium chloride and granular
silica gel material. Wet natural gas is passed through a bed of the
granular or pelletized solid adsorbent in these dehydrators. As the wet
gas contacts the surface of the particles of desiccant material, water
is adsorbed on the surface of these desiccant particles. Passing
through the entire desiccant bed, almost all of the water is adsorbed
onto the desiccant material, leaving the dry gas to exit the contactor.
* * * * *
E&P Tank means the most current version of an exploration and
production field tank emissions equilibrium program that estimates
flashing, working and standing losses of hydrocarbons, including
methane, from produced crude oil and gas condensate. Equal or
successors to E&P Tank Version 2.0 for Windows Software. Copyright (C)
1996-1999 by The American Petroleum Institute and The Gas Research
Institute.
* * * * *
Engineering estimation, for purposes of subpart W, means an
estimate of emissions based on engineering principles applied to
measured and/or approximated physical parameters such as dimensions of
containment, actual pressures, actual temperatures, and compositions.
Enhanced Oil Recovery (EOR) means the use of certain methods such
as water flooding or gas injection into existing wells to increase the
recovery of crude oil from a reservoir. In the context of this rule,
EOR applies to injection of critical phase carbon dioxide into a crude
oil reservoir to enhance the recovery of oil.
* * * * *
Field means standardized field names and codes of all oil and gas
fields identified in the United States as defined by the Energy
Information Administration Oil and Gas Field Code Master List.
* * * * *
Flare combustion means unburned hydrocarbons including
CH4, CO2, N2O emissions resulting from
the incomplete combustion of gas in flares.
Flare combustion efficiency means the fraction of natural gas, on a
volume or mole basis, that is combusted at the flare burner tip.
* * * * *
Fugitive emissions means those emissions which are unintentional
and could not reasonably pass through a stack, chimney, vent, or other
functionally-equivalent opening.
Fugitive emissions detection means the process of identifying
emissions from equipment, components, and other point sources.
Gas conditions mean the actual temperature, volume, and pressure of
a gas sample.
* * * * *
Gas gathering/booster stations mean centralized stations where
produced natural gas from individual wells is co-mingled, compressed
for transport to processing plants, transmission and distribution
systems, and other gathering/booster stations which co-mingle gas from
multiple production gathering/booster stations. Such stations may
include gas dehydration, gravity separation of liquids (both
hydrocarbon and water), pipeline pig launchers and receivers, and gas
powered pneumatic devices.
* * * * *
Gas to oil ratio (GOR) means the ratio of the volume of gas at
standard
[[Page 18635]]
temperature and pressure that is produced from a volume of oil when
depressurized to standard temperature and pressure.
* * * * *
High-Bleed Pneumatic Devices are automated flow control devices
powered by pressurized natural gas and used for maintaining a process
condition such as liquid level, pressure, delta-pressure and
temperature. Part of the gas power stream which is regulated by the
process condition flows to a valve actuator controller where it vents
(bleeds) to the atmosphere at a rate in excess of six standard cubic
feet per hour.
* * * * *
Liquefied natural gas (LNG) means natural gas (primarily methane)
that has been liquefied by reducing its temperature to -260 degrees
Fahrenheit at atmospheric pressure.
LNG boiloff gas means natural gas in the gaseous phase that vents
from LNG storage tanks due to ambient heat leakage through the tank
insulation and heat energy dissipated in the LNG by internal pumps.
Low-Bleed Pneumatic Devices mean automated flow control devices
powered by pressurized natural gas and used for maintaining a process
condition such as liquid level, pressure, delta-pressure and
temperature. Part of the gas power stream which is regulated by the
process condition flows to a valve actuator controller where it vents
(bleeds) to the atmosphere at a rate equal to or less than six standard
cubic feet per hour.
* * * * *
Natural gas driven pneumatic pump means a pump that uses
pressurized natural gas to move a piston or diaphragm, which pumps
liquids on the opposite side of the piston or diaphragm.
* * * * *
Offshore means seaward of the terrestrial borders of the United
States, including waters subject to the ebb and flow of the tide, as
well as adjacent bays, lakes or other normally standing waters, and
extending to the outer boundaries of the jurisdiction and control of
the United States under the Outer Continental Shelf Lands Act.
* * * * *
Onshore petroleum and natural gas production owner or operator
means the entity who is the permitee to operate petroleum and natural
gas wells on the state drilling permit or a state operating permit
where no drilling permit is issued by the state, which operates an
onshore petroleum and/or natural gas production facility (as described
in Sec. 98.230(b)(2). Where more than one entity are permitees on the
state drilling permit, or operating permit where no drilling permit is
issued by the state, the permitted entities for the joint facility must
designate one entity to report all emissions from the joint facility.
* * * * *
Operating pressure means the containment pressure that
characterizes the normal state of gas or liquid inside a particular
process, pipeline, vessel or tank.
* * * * *
Outer Continental Shelf means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in 43
U.S.C. Sec. 1301, and of which the subsoil and seabed appertain to the
United States and are subject to its jurisdiction and control.
* * * * *
Pump means a device used to raise pressure, drive, or increase flow
of liquid streams in closed or open conduits.
Pump seals means any seal on a pump drive shaft used to keep
methane and/or carbon dioxide containing light liquids from escaping
the inside of a pump case to the atmosphere.
Pump seal emissions means hydrocarbon gas released from the seal
face between the pump internal chamber and the atmosphere.
* * * * *
Reciprocating compressor means a piece of equipment that increases
the pressure of a process natural gas by positive displacement,
employing linear movement of a shaft driving a piston in a cylinder.
Reciprocating compressor rod packing means a series of flexible
rings in machined metal cups that fit around the reciprocating
compressor piston rod to create a seal limiting the amount of
compressed natural gas that escapes to the atmosphere.
Re-condenser means heat exchangers that cool compressed boil-off
gas to a temperature that will condense natural gas to a liquid.
* * * * *
Reservoir means a porous and permeable underground natural
formation containing significant quantities of hydrocarbon liquids and/
or gases. A reservoir is characterized by a single natural pressure
system.
* * * * *
Sales oil means produced crude oil or condensate measured at the
production lease automatic custody transfer (LACT) meter or custody
transfer meter tank gauge.
* * * * *
Sour natural gas means natural gas that contains significant
concentrations of hydrogen sulfide and/or carbon dioxide that exceed
the concentrations specified for commercially saleable natural gas
delivered from transmission and distribution pipelines.
* * * * *
Sweet Gas is natural gas with low concentrations of hydrogen
sulfide (H2S) and/or carbon dioxide (CO2) that
does not require (or has already had) acid gas treatment to meet
pipeline corrosion-prevention specifications for transmission and
distribution.
* * * * *
Transmission pipeline means high pressure cross country pipeline
transporting sellable quality natural gas from production or natural
gas processing to natural gas distribution pressure let-down, metering,
regulating stations where the natural gas is typically odorized before
delivery to customers.
* * * * *
Turbine meter means a flow meter in which a gas or liquid flow rate
through the calibrated tube spins a turbine from which the spin rate is
detected and calibrated to measure the fluid flow rate.
* * * * *
Unconventional wells means gas well in producing fields that employ
hydraulic fracturing to enhance gas production volumes.
* * * * *
United States means the 50 States, the District of Columbia, the
Commonwealth of Puerto Rico, American Samoa, the Virgin Islands, Guam,
and any other Commonwealth, territory or possession of the United
States, as well as the territorial sea as defined by Presidential
Proclamation No. 5928.
* * * * *
Vapor recovery system means any equipment located at the source of
potential gas emissions to the atmosphere or to a flare, that is
composed of piping, connections, and, if necessary, flow-inducing
devices, and that is used for routing the gas back into the process as
a product and/or fuel.
Vaporization unit means a process unit that performs controlled
heat input to vaporize LNG to supply transmission and distribution
pipelines or consumers with natural gas.
* * * * *
Vented emissions means intentional or designed releases of
CH4 or CO2 containing natural gas or hydrocarbon
gas (not including stationary combustion flue gas), including but not
limited to process designed flow to the
[[Page 18636]]
atmosphere through seals or vent pipes, equipment blowdown for
maintenance, and direct venting of gas used to power equipment (such as
pneumatic devices).
* * * * *
Well completions means a process that allows for the flow of
petroleum or natural gas from newly drilled wells to expel drilling and
reservoir fluids and test the reservoir flow characteristics. This
process includes high-rate back-flow of injected water and sand used to
fracture and prop-open fractures in low permeability gas reservoirs.
Well workover means the performance of one or more of a variety of
remedial operations on producing oil and gas wells to try to increase
production. This process also includes high-rate back-flow of injected
water and sand used to re-fracture and prop-open new fractures in
existing low permeability gas reservoirs.
Wellhead means the piping, casing, tubing and connected valves
protruding above the Earth's surface for an oil and/or natural gas
well. The wellhead ends where the flow line connects to a wellhead
valve.
Wet natural gas means natural gas in which water vapor exceeds the
concentration specified for commercially saleable natural gas delivered
from transmission and distribution pipelines. This input stream to a
natural gas dehydrator is referred to as ``wet gas''.
4. Section 98.7 is amended by adding paragraphs (k), (l), and (m)
to read as follows:
Sec. 98.7 What standardized methods are incorporated by reference
into this part?
* * * * *
(k) The following material is available for purchase from the Gas
Technology Institute, 1700 South Mount Prospect Road, Des Plaines,
Illinois 60018, http://www.gastechnology.org.
(1) GRI-GLYCalc Version 4.0, IBR approved for Sec. 98.233(e).
(2) [Reserved]
(l) The following material is available for purchase from IHS
Standards Store, Jane's Information Group, Inc., 110 North Royal
Street, Suite 200, Alexandria, Virginia 22314, http://www.ihs.com.
(1) E&P Tank Version 2.0, IBR approved for Sec. 98.233(j) and
Sec. 98.236(c).
(2) [Reserved]
(m) The following material is available for purchase from the
American Association of Petroleum Geologists, 1444 South Boulder
Avenue, Tulsa, Oklahoma 74119, www.aapg.org.
(1) AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Volume 75,
Number 10 (October 1991), pages 1644-1651, IBR approved for Sec.
98.230(b).
(2) [Reserved]
5. Add subpart W to read as follows:
Subpart W--Petroleum and Natural Gas Systems
Sec.
98.230 Definition of the source category.
98.231 Reporting threshold.
98.232 GHGs to report.
98.233 Calculating GHG emissions.
98.234 Monitoring and QA/QC requirements.
98.235 Procedures for estimating missing data.
98.236 Data reporting requirements.
98.237 Records that must be retained.
98.238 Definitions.
Subpart W--Petroleum and Natural Gas Systems
Sec. 98.230 Definition of the source category.
(a) This source category consists of the following:
(1) Offshore petroleum and natural gas production. Offshore
petroleum and natural gas production is any platform structure, affixed
temporarily or permanently to offshore submerged lands, that houses
equipment to extract hydrocarbons from the ocean or lake floor and that
transfers such hydrocarbons to storage, transport vessels, or onshore.
In addition, offshore production includes secondary platform structures
and storage tanks associated with the platform structure.
(2) Onshore petroleum and natural gas production. Onshore petroleum
and natural gas production equipment means all structures associated
with wells (including but not limited to compressors, generators, or
storage facilities), piping (including but not limited to flowlines or
intra-facility gathering lines), and portable non-self-propelled
equipment (including but not limited to 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 also includes associated storage or
measurement and all systems engaged in gathering produced gas from
multiple wells, all EOR operations using CO2, and all
petroleum and natural gas production located on islands, artificial
islands or structures connected by a causeway to land, an island, or
artificial island.
(3) Onshore natural gas processing plants. Natural gas processing
plants are designed to separate and recover natural gas liquids (NGLs)
or other non-methane gases and liquids from a stream of produced
natural gas to meet onshore natural gas transmission pipeline quality
specifications through equipment performing one or more of the
following processes: oil and condensate removal, water removal,
separation of natural gas liquids, sulfur and carbon dioxide removal,
fractionation of NGLs, or other processes, and also the capture of
CO2 separated from natural gas streams for delivery outside
the facility. In addition, field gathering and/or boosting stations
that gather and process natural gas from multiple wellheads, and
compress and transport natural gas (including but not limited to
flowlines or intra-facility gathering lines or compressors) as feed to
the natural gas processing plants are considered a part of the
processing plant. Gathering and boosting stations that send the natural
gas to an onshore natural gas transmission compression facility, or
natural gas distribution facility, or to an end user are considered
stand alone natural gas processing facilities. All residue gas
compression equipment operated by a processing plant, whether inside or
outside the processing plant fence, are considered part of natural gas
processing plant.
(4) Onshore natural gas transmission compression. Onshore natural
gas transmission compression means any fixed combination of compressors
that move natural gas at elevated pressure from production fields or
natural gas processing facilities, in transmission pipelines, to
natural gas distribution pipelines, or into storage. In addition,
transmission compressor station includes equipment for liquids
separation, natural gas dehydration, and tanks for the storage of water
and hydrocarbon liquids.
(5) Underground natural gas storage. Underground natural gas
storage means subsurface storage, including but not limited to,
depleted gas or oil reservoirs and salt dome caverns utilized for
storing natural gas that has been transferred from its original
location for the primary purpose of load balancing (the process of
equalizing the receipt and delivery of natural gas); natural gas
underground storage processes and operations (including, but not
limited to, compression, dehydration and flow measurement); and all the
wellheads connected to the compression units located at the facility.
(6) Liquefied natural gas (LNG) storage. LNG storage means onshore
LNG storage vessels located above ground, equipment for liquefying
natural gas, compressors to capture and re-liquefy boil-off-gas, re-
condensers,
[[Page 18637]]
and vaporization units for re-gasification of the liquefied natural
gas.
(7) LNG import and export equipment. LNG import equipment means all
onshore or offshore equipment that receives imported LNG via ocean
transport, stores LNG, re-gasifies LNG, and delivers re-gasified
natural gas to a natural gas transmission or distribution system. LNG
export equipment means all onshore or offshore equipment that receives
natural gas, liquefies natural gas, stores LNG, and transfers the LNG
via ocean transportation to any location, including locations in the
United States.
(8) Natural Gas Distribution. Natural gas distribution means
distribution pipelines (not interstate pipelines or intrastate
pipelines) and metering and regulating stations, that physically
deliver natural gas to end users.
(b) [Reserved]
Sec. 98.231 Reporting threshold.
(a) You must report GHG emissions from petroleum and natural gas
systems if your facility as defined in Sec. 98.230 meets the
requirements of Sec. 98.2(a)(2).
(b) For applying the threshold defined in Sec. 98.2(a)(2), you
must include combustion emissions from portable equipment that cannot
move on roadways under its own power and drive train and that is
stationed at a wellhead for more than 30 days in a reporting year,
including drilling rigs, dehydrators, compressors, electrical
generators, steam boilers, and heaters.
Sec. 98.232 GHGs to report.
(a) You must report CO2 and CH4 emissions
from each industry segment specified in paragraph (b) through (i) of
this section.
(b) For offshore petroleum and natural gas production, report
emissions from all ``stationary fugitive'' and ``stationary vented''
sources as identified in the Minerals Management Service (MMS) Gulfwide
Offshore Activity Data System (GOADS) study (2005 Gulfwide Emission
Inventory Study MMS 2007-067).
(c) For onshore petroleum and natural gas production, report
emissions from the following source types:
(1) Natural gas pneumatic high bleed device venting.
(2) Natural gas pneumatic low bleed device venting.
(3) Natural gas driven pneumatic pump venting.
(4) Well venting for liquids unloading.
(5) Gas well venting during conventional well completions.
(6) Gas well venting during unconventional well completions.
(7) Gas well venting during conventional well workovers.
(8) Gas well venting during unconventional well workovers.
(9) Gathering pipeline fugitives.
(10) Storage tanks.
(11) Reciprocating compressor rod packing venting.
(12) Well testing venting and flaring.
(13) Associated gas venting and flaring.
(14) Dehydrator vent stacks.
(15) Coal bed methane produced water emissions.
(16) EOR injection pump blowdown.
(17) Acid gas removal vent stack.
(18) Hydrocarbon liquids dissolved CO2.
(19) Centrifugal compressor wet seal degassing venting.
(20) Produced water dissolved CO2.
(21) Fugitive emissions from valves, connectors, open ended lines,
pressure relief valves, compressor starter gas vents, pumps, flanges,
and other fugitive sources (such as instruments, loading arms, pressure
relief valves, stuffing boxes, compressor seals, dump lever arms, and
breather caps for crude services).
(d) For onshore natural gas processing, report emissions from the
following sources:
(1) Reciprocating compressor rod packing venting.
(2) Centrifugal compressor wet seal degassing venting.
(3) Storage tanks.
(4) Blowdown vent stacks.
(5) Dehydrator vent stacks.
(6) Acid gas removal vent stack.
(7) Flare stacks.
(8) Gathering pipeline fugitives.
(9) Fugitive emissions from: valves, connectors, open ended lines,
pressure relief valves, meters, and centrifugal compressor dry seals.
(e) For onshore natural gas transmission compression, report
emissions from the following sources:
(1) Reciprocating compressor rod packing venting.
(2) Centrifugal compressor wet seal degassing venting.
(3) Transmission storage tanks.
(4) Blowdown vent stacks.
(5) Natural gas pneumatic high bleed device venting.
(6) Natural gas pneumatic low bleed device venting.
(7) Fugitive emissions from connectors, block valves, control
valves, compressor blowdown valves, pressure relief valves, orifice
meters, other meters, regulators, and open ended lines.
(f) For underground natural gas storage, report emissions from the
following sources:
(1) Reciprocating compressor rod packing venting.
(2) Centrifugal compressor wet seal degassing venting.
(3) Natural gas pneumatic high bleed device venting.
(4) Natural gas pneumatic low bleed device venting.
(5) Fugitive emissions from connectors, block valves, control
valves, compressor blowdown valves, pressure relief valves, orifice
meters, other meters, regulators, and open ended lines.
(g) For LNG storage, report emissions from the following sources:
(1) Reciprocating compressor rod packing venting.
(2) Centrifugal compressor wet seal degassing venting.
(3) Fugitive emissions from valves; pump seals; connectors; vapor
recovery compressors, and other fugitive sources.
(h) LNG import and export equipment, report emissions from the
following sources:
(1) Reciprocating compressor rod packing venting.
(2) Centrifugal compressor wet seal degassing venting.
(3) Blowdown vent stacks.
(4) Fugitive emissions from valves, pump seals, connectors, vapor
recovery compressors, and other fugitive sources.
(i) For natural gas distribution, report emissions from the
following sources:
(1) Above ground meter regulators and gate station fugitive
emissions from connectors, block valves, control valves, pressure
relief valves, orifice meters, other meters, regulators, and open ended
lines.
(2) Below ground meter regulators and vault fugitives.
(3) Pipeline main fugitives.
(4) Service line fugitives.
(j) You must report the CO2, CH4, and
N2O emissions from each flare.
(k) You must 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.
(l) You must report under subpart PP of this part (Suppliers of
Carbon Dioxide), CO2 emissions captured and transferred off
site by following the requirements of subpart PP.
Sec. 98.233 Calculating GHG emissions.
(a) Natural gas pneumatic high bleed device venting. Calculate
emissions from a natural gas pneumatic high bleed flow control device
venting as follows:
(1) Calculate vented emissions using manufacturer data.
(i) Obtain from the manufacturer specific pneumatic device model
natural gas bleed rate during normal operation.
[[Page 18638]]
(ii) Calculate the natural gas emissions for each continuous bleed
device using Equation W-1 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.082
Where:
Es,n = Annual natural gas emissions at standard
conditions, in cubic feet.
Bs = Natural gas driven pneumatic device bleed rate
volume at standard conditions in cubic feet per minute, as provided
by the manufacturer.
T = Amount of time in minutes that the pneumatic device has been
operational through the reporting period.
(iii) 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.
(2) If manufacturer data for a specific device is not available,
then use data for a similar device model, size and operational
characteristics to estimate emissions.
(b) Natural gas pneumatic low bleed device venting. Calculate
emissions from natural gas pneumatic low continuous bleed device
venting using Equation W-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.000
Where:
Masss,i = Annual total mass GHG emissions in metric tons
per year at standard conditions from all natural gas pneumatic low
bleed device venting, for GHG i.
Count = Total number of natural gas pneumatic low bleed devices.
EF = Population emission factors for natural gas pneumatic low bleed
device venting listed in Tables W-1, W-3, and W-4 of this subpart
for onshore petroleum and natural gas production, onshore natural
gas transmission, and underground natural gas storage facilities,
respectively.
GHG i = For onshore petroleum and natural gas production facilities,
concentration of GHG i, CH4 or CO2, in
produced natural gas; for facilities listed in Sec. 98.230(a)(3)
through (a)(8), GHGi equals 1.
Convi = Conversion from standard cubic feet to metric tons
CO2e; 0.000404 for CH4, and 0.00005189 for
CO2.
24 * 365 = Conversion to yearly emissions estimate.
(c) Natural gas driven pneumatic pump venting. Calculate emissions
from natural gas driven pneumatic pump venting as follows:
(1) Calculate emissions using manufacturer data.
(i) Obtain from the manufacturer specific pump model natural gas
emission (or manufacturer ``gas consumption'') per unit volume of
liquid circulation rate at pump speeds and operating pressures.
(ii) Maintain a log of the amount of liquid pumped annually from
individual pumps.
(iii) Calculate the natural gas emissions for each pump using
Equation W-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.001
Where:
Es,n = Annual natural gas emissions at standard
conditions in cubic feet per year.
Fs = Natural gas driven pneumatic pump gas emission
in ``emission per volume of liquid pumped at operating pressure'' in
scf/gallon at standard conditions, as provided by the manufacturer.
V = Volume of liquid pumped annually in gallons/year.
(iv) 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.
(2) If manufacturer data for a specific pump in Equation W-3 is not
available, then use data for a similar pump model, size and operational
characteristics to estimate emissions.
(d) Acid gas removal (AGR) vent stacks. For AGR (including but not
limited to processes such as amine, membrane, molecular sieve or other
absorbents and adsorbents), calculate emissions for CO2 only
(not CH4) using Equation W-4 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.002
Where:
Ea,CO2 = Annual volumetric CO2 emissions at
ambient condition, in cubic feet per year.
V1 = Metered total annual volume of natural gas flow into
AGR unit in cubic feet per year at ambient condition.
%Vol1 = Volume weighted CO2 content of natural
gas into the AGR unit.
V2 = Metered total annual volume of natural gas flow out
of the AGR unit in cubic feet per year at ambient condition.
%Vol2 = Volume weighted CO2 content of natural
gas out of the AGR unit.
(1) If a continuous gas analyzer is installed, then the continuous
gas analyzer results must be used. If continuous gas analyzer is not
available, quarterly gas samples must be taken to determine
%Vol1 and %Vol2 according to methods set forth in
Sec. 98.234(b).
(2) Calculate CO2 volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
(3) Mass CO2 emissions shall be calculated from
volumetric CO2 emissions using calculations in paragraphs
(u) and (v) of this section.
(e) Dehydrator vent stacks. For dehydrator vent stacks without
vapor recovery or thermal control devices, calculate annual mass
CH4 and CO2 emissions at standard temperature and
pressure (STP) conditions using the simulation software package GRI-
GLYCalc Version 4.0 (incorporated by reference, see Sec. 98.7).
(1) A minimum of the following parameters must be used for
characterizing emissions from dehydrators:
(i) Feed natural gas flow rate.
(ii) Feed natural gas water content.
(iii) Outlet natural gas water content.
(iv) Absorbent circulation pump type (natural gas pneumatic/air
pneumatic/electric).
(v) Absorbent circulation rate.
(vi) Absorbent type: Including, but not limited to, triethylene
glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG).
(vii) Use of stripping natural gas.
(viii) Use of flash tank separator (and disposition of recovered
gas).
(ix) Hours operated.
(x) Wet natural gas temperature, pressure, and composition.
(2) Calculate annual emissions from dehydrator vent stacks to
flares or regenerator fire-box/fire tubes as follows:
(i) Use the dehydrator vent stack volume and gas composition as
determined in paragraph (e)(1) of this section.
[[Page 18639]]
(ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine dehydrator vent stack emissions from
the flare or regenerator combustion gas vent.
(3) Dehydrators that use desiccant shall calculate emissions from
the amount of gas vented from the vessel every time it is depressurized
for the desiccant refilling process using Equation W-5 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.003
Where:
Es,n = Annual natural gas emissions at standard
conditions.
H = Height of the dehydrator vessel (ft).
D = Inside diameter of the vessel (ft).
P1 = Atmospheric pressure (psia).
P2 = Pressure of the gas (psia).
P = pi (3.14).
%G = Percent of packed vessel volume that is gas.
T = Time between refilling (days).
(i) 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.
(1) The emissions for well venting for liquids unloading shall be
determined using either of the calculation methodologies described in
paragraph (f)(1) of this section. The same calculation methodology must
be used for the entire volume for the reporting year.
(i) Calculation Methodology 1. For each unique well tubing diameter
and producing horizon/formation combination in each gas producing field
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-6 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.004
Where:
Ea,n = Annual natural gas emissions at ambient conditions
in cubic feet.
T = Cumulative amount of time in hours of well venting during the
year.
FR = Flow Rate in cubic feet per hour, under ambient conditions as
required in paragraph (f)(1)(i)(A), (f)(1)(i)(B) and (f)(1)(i)(C) of
this section.
Calculate natural gas volumetric emissions at standard conditions
using calculations in paragraph (t) of this section. 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.
(A) The average flow rate per minute of venting is calculated for
each unique tubing diameter and producing horizon/formation combination
in each producing field.
(B) This factor is applied to all wells in the field that have the
same tubing diameter and producing horizon/formation combination,
multiplied by the number of minutes of venting from all wells of the
same tubing diameter and producing horizon/formation combination in
that field.
(C) A new emission factor is calculated every other year for each
reporting field and horizon.
(ii) Calculation Methodology 2. Calculate emissions from each well
venting for liquids unloading using Equation W-7 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.005
Where:
Es,n = Annual natural gas emissions at standard
conditions, in cubic feet/year.
0.37 x 10-3 = {pi(3.14)/4{time} /{(14.7*144) psia
converted to pounds per square feet{time}
CD = Casing diameter (inches).
WD = Well depth (feet).
SP = Shut-in pressure (psig).
V = Number of vents per year.
SFR = Sales flow rate of gas well in cubic feet per hour.
HR = Hours that the well was left open to the atmosphere during
unloading.
(A) 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.
(B) [Reserved]
(g) Gas well venting during unconventional well completions and
workovers. Calculate emissions from gas unconventional well venting
during well completions and workovers from hydraulic fracturing using
Equation W-8 of this section. Calculate natural gas volumetric
emissions at standard conditions using calculations in paragraph (t) of
this section. 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.
[GRAPHIC] [TIFF OMITTED] TP12AP10.006
Where:
Ea,n = Annual natural gas vented emissions at ambient
conditions in cubic feet.
T = Cumulative amount of time in hours of well venting during the
year.
FR = Flow Rate in cubic feet per hour, under ambient conditions, as
required in paragraph (g)(1) of this section.
(1) The flow rate for gas well venting during well completions and
workovers from hydraulic fracturing shall be determined using either of
the calculation methodologies described in this paragraph (g)(1). The
same calculation methodology must be used for the entire volume for the
reporting year.
(i) Calculation methodology 1. For one well completion in each gas
producing field and for one well workover in each gas producing field,
a recording flow meter shall be installed on the vent line during each
well unloading event according to methods set forth in Sec. 98.234(b).
(A) The average flow rate in cubic feet per minute of venting is
calculated for one well completion in each field and for one well
workover in each field.
(B) The respective flow rates are applied to all well completions
in the field and to all well workovers in the field, multiplied by the
number of minutes of venting of all well completions and workovers,
respectively, in that field.
[[Page 18640]]
(C) New flow rates for completions and workovers are calculated
every other year for each reporting field and horizon.
(ii) Calculation Methodology 2. For one well completion in each gas
producing field and for one well workover in each gas producing field,
record the pressures measured before and after the well choke according
to methods set forth in Sec. 98.234(b).
(A) The average flow rate in cubic feet per minute of venting
across the choke is calculated for one well completion in each field
and for one well workover in each field.
(B) The respective flow rates are applied to all well completions
in the field and to all well workovers in the field, multiplied by the
number of minutes of venting of all well completions and workovers in
that field.
(C) New flow rates for completions and workovers are calculated
every other year for each reporting field and horizon.
(iii) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
(iv) 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.
(2) Calculate annual emissions from gas well venting during well
completions and workovers to flares as follows:
(i) Use the gas well venting volume during well completions and
workovers as determined in paragraph (g)(1) of this section.
(ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine gas well venting during well
completions and workovers emissions from the flare.
(h) Gas well venting during conventional well completions and
workovers. Calculate emissions from each gas well venting during
conventional well completions and workovers using Equation W-9 of this
section:
[GRAPHIC] [TIFF OMITTED] TP12AP10.007
Where:
Ea,n = Annual emissions in cubic feet at ambient
conditions from gas well venting during conventional well
completions or workovers.
V = Daily gas production rate in cubic feet per minute.
T = Cumulative amount of time of well venting in minutes during the
year.
(i) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
(ii) 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.
(iii) Blowdown vent stacks. Calculate blowdown vent stack emissions
as follows:
(1) Calculate the total volume (including, but not limited to,
pipelines, compressor case or cylinders, manifolds, suction and
discharge bottles and vessels) between isolation valves.
(2) Retain logs of the number of blowdowns for each equipment type.
(3) Calculate the total annual venting emissions using Equation W-
10 of this section:
[GRAPHIC] [TIFF OMITTED] TP12AP10.008
Where:
Ea,n = Annual natural gas venting emissions at ambient
conditions from blowdowns in cubic feet.
N = Number of blowdowns for the equipment in reporting year.
Vv = Total volume of blowdown equipment chambers
(including, but not limited to, pipelines, compressors and vessels)
between isolation valves in cubic feet.
(4) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
(5) Calculate both CH4 and CO2 volumetric and
mass emissions from volumetric natural gas emissions using calculations
in paragraphs (u) and (v) of this section.
(j) Onshore production and processing storage tanks. For emissions
from atmospheric pressure storage tanks receiving produced liquids from
onshore petroleum and natural gas production facilities (including
stationary liquid storage not owned or operated by the reporter) and
onshore natural gas processing facilities, calculate annual
CH4 and CO2 emissions using the latest software
package for E&P Tank (incorporated by reference, see Sec. 98.7).
(1) A minimum of the following parameters must be used to
characterize emissions from liquid transfer to atmospheric pressure
storage tanks.
(i) Separator oil composition.
(ii) Separator temperature.
(iii) Separator pressure.
(iv) Sales oil API gravity.
(v) Sales oil production rate.
(vi) Sales oil Reid vapor pressure.
(vii) Ambient air temperature.
(viii) Ambient air pressure.
(2) Determine if the storage tank has vapor recovery or thermal
control devices.
(i) Adjust the emissions estimated using E&P Tank (incorporated by
reference, see Sec. 98.7) downward by the magnitude of emissions
captured using a vapor recovery system for beneficial use.
(ii) [Reserved]
(3) Calculate emissions from liquids sent to atmospheric storage
tanks vented to flares as follows:
(i) Use the storage tank emissions volume and gas composition as
determined in this section.
(ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine storage tank emissions from the flare.
(4) If liquids are sent to atmospheric storage tanks where the tank
emissions are not represented by the equilibrium conditions of the
liquid in a gas-liquid separator and calculated by E&P Tank
(incorporate by reference, see Sec. 98.7), then emissions shall be
calculated as follows:
(i) Use the storage tank emissions as determined in this section.
(ii) Multiply the emissions by 3.87 for sales oil less than 45 API
gravity.
(iii) Multiply the emissions by 5.37 for sales oil equal to or
greater than 45 API gravity.
(k) Transmission storage tanks. For storage tanks without vapor
recovery or thermal control devices in onshore natural gas transmission
compression facilities calculate annual emissions as follows:
(1) Monitor tank vapor vent stack for emissions using an optical
gas imaging instrument according to methods set forth in Sec.
98.234(a)(1) for a duration of 5 minutes.
(2) If the tank vapors are continuous then use a meter to measure
tank vapors.
(i) Use a meter, such as, but not limited to a turbine meter, to
estimate tank vapor volumes according to methods set forth in Sec.
98.234(b).
(ii) Use the appropriate gas composition in paragraph (u)(2)(iii)
of this section.
(3) Calculate emissions from storage tanks to flares as follows:
(i) Use the storage tank emissions volume and gas composition as
determined in paragraph (j)(1) of this section.
(ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine storage tank emissions from the flare.
(l) Well testing venting and flaring. Calculate well testing
venting and flaring emissions as follows:
(1) Determine the gas to oil ratio (GOR) of the hydrocarbon
production from each well tested.
[[Page 18641]]
(i) If GOR is not available then use an appropriate standard method
published by a consensus-based standards organization to determine GOR.
(ii) [Reserved]
(2) Estimate venting emissions using Equation W-11 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.009
Where:
Ea,n = Annual volumetric natural gas emissions from well
testing in cubic feet under ambient conditions.
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil
here refers to hydrocarbon liquids produced of all API gravities.
FR = Flow rate in barrels of oil per day for the well being tested.
D = Number of days during the year, the well is tested.
(3) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
(4) Calculate both CH4 and CO2 volumetric and
mass emissions from volumetric natural gas emissions using calculations
in paragraphs (u) and (v) of this section.
(5) Calculate emissions from well testing to flares as follows:
(i) Use the well testing emissions volume and gas composition as
determined in paragraphs (l)(1) through (3) of this section.
(ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine well testing emissions from the flare.
(m) Associated gas venting and flaring. Calculate associated gas
venting and flaring emissions as follows:
(1) Determine the GOR ratio of the hydrocarbon production from each
well whose associated natural gas is vented or flared.
(i) If GOR is not available then use an appropriate standard method
published by a consensus-based standards organization to determine GOR.
(i) [Reserved]
(2) Estimate venting emissions using the Equation W-12 of this
section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.010
Where:
Ea,n = Annual volumetric natural gas emissions from
associated gas venting under ambient conditions, in cubic feet.
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil
here refers to hydrocarbon liquids produced of all API gravities.
V = Total volume of oil produced in barrels in the reporting year.
(3) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
(4) Calculate both CH4 and CO2 volumetric and
mass emissions from volumetric natural gas emissions using calculations
in paragraphs (u) and (v) of this section.
(5) Calculate emissions from associated natural gas to flares as
follows:
(i) Use the associated natural gas volume and gas composition as
determined in paragraphs (m)(1) through (3) of this section.
(ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine associated gas emissions from the
flare.
(n) Flare stacks. Calculate emissions from a flare stack as
follows:
(1) If you have a continuous flow measurement device on the flare,
you must use the measured flow volumes to calculate the flare gas
emissions. If you do not have a continuous flow measurement device on
the flare, you can install a flow measuring device on the flare or use
engineering calculations, company records, or similar estimates of
volumetric flare gas flow.
(2) If you have a continuous gas composition analyzer on gas to the
flare, you must use these compositions in calculating emissions. If you
do not have a continuous gas composition analyzer on gas to the flare,
you must use the appropriate gas compositions for each stream of
hydrocarbons going to the flare as follows:
(i) When the stream going to the flare is natural gas, use the GHG
mole percent in feed natural gas for all streams upstream of the de-
methanizer and GHG mole percent in facility specific residue gas to
transmission pipeline systems for all emissions sources downstream of
the de-methanizer overhead for onshore natural gas processing
facilities.
(ii) When the stream going to the flare is a hydrocarbon product
stream, such as ethane or butane, then use a representative composition
from the source for the stream.
(3) Determine flare combustion efficiency from manufacturer. If not
available, assume that flare combustion efficiency is 98 percent.
(4) Calculate GHG volumetric emissions at actual conditions using
Equations W-13, W-14, and W-15 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.011
[GRAPHIC] [TIFF OMITTED] TP12AP10.012
[GRAPHIC] [TIFF OMITTED] TP12AP10.013
Where:
Ea,i (un-combusted) = Contribution of annual uncombusted
GHG i emissions from flare stack in cubic feet, under ambient
conditions.
Ea,CO2 (combusted) = Contribution of annual emissions
from combustion from flare stack in cubic feet, under ambient
conditions.
Ea,I (total) = Total annual emissions from flare stack in
cubic feet, under ambient conditions.
Va = Volume of natural gas sent to flare in cubic feet,
during the year.
[eta] = Percent of natural gas combusted by flare (default is 98
percent).
Xi = Concentration of GHG i in gas to the flare.
Yj = Concentration of natural gas hydrocarbon
constituents j (such as methane, ethane, propane, butane, and
pentanes plus).
Rj = Number of carbon atoms in the natural gas
hydrocarbon constituent j; 1 for methane, 2 for ethane, 3 for
propane, 4 for butane, and 5 for pentanes plus).
(5) Calculate GHG volumetric emissions at standard conditions using
calculations in paragraph (t) of this section.
(6) Calculate both CH4 and CO2 mass emissions
from volumetric CH4 and CO2 emissions using
calculation in paragraph (v) of this section.
[[Page 18642]]
(7) Calculate N2O emissions using the emission factors
for Gas Flares listed in Table W-8 of this subpart.
(8) This emissions source excludes any emissions calculated under
other emissions sources in Sec. 98.233.
(o) Centrifugal compressor wet seal degassing vents. Calculate
emissions from centrifugal compressor wet seal degassing vents as
follows:
(1) For each centrifugal compressor determine the volume of vapors
from wet seal oil degassing tank sent to an atmospheric vent or flare
using a temporary or permanent flow measurement meter such as, but not
limited to, a vane anemometer according to methods set forth in Sec.
98.234(b).
(2) Estimate annual emissions using meter flow measurement using
Equation W-16 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.014
Where:
Ea,i = Annual GHG i (either CH4 or
CO2) volumetric emissions at ambient conditions.
MT = Meter reading of gas emissions per unit time.
T = Total time the compressor associated with the wet seal(s) is
operational in the reporting year.
Mi = Mole percent of GHG i in the degassing vent gas; use
the appropriate gas compositions in paragraph (u)(2) of this
section.
B = Percentage of centrifugal compressor wet seal degassing vent gas
sent to vapor recovery or fuel gas or other beneficial use as
determined by keeping logs of the number of operating hours for the
vapor recovery system and the amount of vent gas that is directed to
the fuel gas system.
(3) Calculate CH4 and CO2 volumetric
emissions at standard conditions using paragraph (t) of this section.
(4) Calculate both CH4 and CO2 mass emissions
from volumetric emissions using calculations in paragraph (v) of this
section.
(5) Calculate emissions from degassing vent vapors to flares as
follows:
(i) Use the degassing vent vapor volume and gas composition as
determined in paragraphs (o)(1) through (3) of this section.
(ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine degassing vent vapor emissions from
the flare.
(p) Reciprocating compressor rod packing venting. Calculate annual
CH4 and CO2 emissions from each reciprocating
compressor rod packing venting as follows:
(1) Estimate annual emissions using a meter flow measurement using
Equation W-17 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.015
Where:
Ea,i = Annual GHG i (either CH4 or
CO2) volumetric emissions at ambient conditions.
MT = Meter volumetric reading of gas emissions per unit time, under
ambient conditions.
T = Total time the compressor associated with the venting is
operational in the reporting year.
Mi = Mole percent of GHG i in the vent gas; use the
appropriate gas compositions in paragraph (u)(2) of this section.
(2) If the rod packing case is connected to an open ended vent line
then use one of the following two methods to calculate emissions.
(i) Measure emissions from all vents (including emissions
manifolded to common vents) including rod packing, unit isolation
valves, and blowdown valves using bagging according to methods set
forth in Sec. 98.234(c).
(ii) Use a temporary meter such as, but not limited to, a vane
anemometer or a permanent meter such as, but not limited to, an orifice
meter to measure emissions from all vents (including emissions
manifolded to a common vent) including rod packing vents, unit
isolation valves, and blowdown valves according to methods set forth in
Sec. 98.234(b).
(3) If the rod packing case is not equipped with a vent line use
the following method to estimate emissions:
(i) You must use the methods described in Sec. 98.234(a) to
conduct annual leak detection of fugitive emissions from the packing
case into an open distance piece, or from the compressor crank case
breather cap or vent with a closed distance piece.
(ii) Measure emissions using a high flow sampler, or calibrated
bag, or appropriate meter according to methods set forth in Sec.
98.234(d).
(4) Conduct one measurement for each compressor in each of the
operational modes that occurs during a reporting period:
(i) Operating.
(ii) Standby pressurized.
(iii) Not operating, depressurized.
(5) Calculate CH4 and CO2 volumetric
emissions at standard conditions using calculations in paragraph (t) of
this section.
(6) Estimate CH4 and CO2 volumetric and mass
emissions from volumetric natural gas emissions using the calculations
in paragraphs (u) and (v) of this section.
(q) Leak detection and leaker emission factors. You must use the
methods described in Sec. 98.234(a) to conduct an annual leak
detection of fugitive emissions from all sources listed in Sec.
98.232(d)(9), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). This
paragraph (q) applies to emissions sources in streams with gas content
greater than 10 percent CH4 plus CO2 by weight.
Emissions sources in streams with gas content less than 10 percent
CH4 plus CO2 by weight do not need to be
reported. If fugitive emissions are detected for sources listed in this
paragraph, calculate emissions using Equation W-18 of this section for
each source with fugitive emissions.
[GRAPHIC] [TIFF OMITTED] TP12AP10.016
Where:
Es,i = Annual total volumetric GHG emissions at standard
conditions from each fugitive source.
Count = Total number of this type of emission source found to be
leaking.
EF = Leaker emission factor for specific sources listed in Table W-2
through Table W-7 of this subpart.
GHGi = For onshore natural gas processing facilities,
concentration of GHGi, CH4 or CO2, in the
total hydrocarbon of the feed natural gas; for other facilities
listed in Sec. 98.230(a)(3) through (a)(8), GHGi equals
1.
T = Total time the specific source associated with the fugitive
emission was operational in the reporting year, in hours.
[[Page 18643]]
(1) Calculate GHG mass emissions in carbon dioxide equivalent at
standard conditions using calculations in paragraph (v) of this
section.
(2) Onshore natural gas processing facilities shall use the
appropriate default leaker emission factors listed in Table W-2 of this
subpart for fugitive emissions detected from valves; connectors; open
ended lines; pressure relief valves; meters; and centrifugal compressor
dry seals.
(3) Onshore natural gas transmission compression facilities shall
use the appropriate default leaker emission factors listed in Table W-3
of this subpart for fugitive emissions detected from connectors; block
valves; control valves; compressor blowdown valves; pressure relief
valves; orifice meters; other meters; regulators; and open ended lines.
(4) Underground natural gas storage facilities for storage stations
shall use the appropriate default leaker emission factors listed in
Table W-4 of this subpart for fugitive emissions detected from
connectors; block valves; control valves; compressor blowdown valves;
pressure relief valves; orifice meters; other meters; regulators; and
open ended lines.
(5) LNG storage facilities shall use the appropriate default leaker
emission factors listed in Table W-5 of this subpart for fugitive
emissions detected from valves; pump seals; connectors; and other.
(6) LNG import and export facilities shall use the appropriate
default leaker emission factors listed in Table W-6 of this subpart for
fugitive emissions detected from valves; pump seals; connectors; and
other.
(7) Natural gas distribution facilities for above ground meter
regulator and gate stations shall use the appropriate default leaker
emission factors listed in Table W-7 of this subpart for fugitive
emissions detected from connectors; block valves; control valves;
pressure relief valves; orifice meters; other meters; regulators; and
open ended lines.
(r) Population count and emission factors. This paragraph applies
to emissions sources listed in Sec. 98.232(c)(2), (c)(9), (c)(15),
(c)(21), (d)(8), (e)(6), (f)(4), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3)
and (i)(4), on streams with gas content greater than 10 percent
CH4 plus CO2 by weight. Emissions sources in
streams with gas content less than 10 percent CH4 plus
CO2 by weight do not need to be reported. Calculate
emissions from all sources listed in this paragraph using Equation W-19
of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.017
Where:Es,i = Annual total volumetric GHG emissions at
standard conditions from each fugitive source.
Count = Total number of this type of emission source at the
facility.
EF = Population emission factor for specific sources listed in
Table W-1 through Table W-7 of this subpart.
GHGi = for onshore petroleum and natural gas
production facilities and onshore natural gas processing facilities,
concentration of GHG i, CH4 or CO2, in
produced natural gas or feed natural gas; for other facilities
listed in Sec. 98.230 (b)(3) through (b)(8),GHGi equals
1.
T = Total time the specific source associated with the fugitive
emission was operational in the reporting year, in hours.
(1) Calculate both CH4 and CO2 mass emissions
from volumetric emissions using calculations in paragraph (v) of this
section.
(2) Onshore petroleum and natural gas production facilities shall
use the appropriate default population emission factors listed in Table
W-1 of this subpart for fugitive emissions from valves; connectors;
open ended lines; pressure relief valves; compressor starter gas vent;
pump; flanges; other; and CBM well water production. Where facilities
conduct EOR operations the emissions factor listed in Table W-1 shall
be used to estimate all streams of gases, including recycle
CO2 stream. In cases where the stream is almost all
CO2, the emissions factors in Table W-1 shall be assumed to
be for CO2 instead of natural gas.
(3) Onshore natural gas processing facilities shall use the
appropriate default population emission factor listed in Table W-2 of
this subpart for fugitive emissions from gathering pipelines.
(4) Underground natural gas storage facilities for storage
wellheads shall use the appropriate default population emission factors
listed in Table W-4 of this subpart for fugitive emissions from
connectors; valves; pressure relief valves; and open ended lines.
(5) LNG storage facilities shall use the appropriate default
population emission factors listed in Table W-5 of this subpart for
fugitive emissions from vapor recovery compressors.
(6) LNG import and export facilities shall use the appropriate
default population emission factor listed in Table W-6 of this subpart
for fugitive emissions from vapor recovery compressors.
(7) Natural gas distribution facilities shall use the appropriate
default population emission factors listed in Table W-7 of this subpart
for fugitive emissions from below grade M&R stations; gathering
pipelines; mains; and services.
(s) Offshore petroleum and natural gas production facilities in
both state and federal waters. Report GHG emissions from all
``stationary fugitive'' and ``stationary vented'' sources as identified
in the Minerals Management Service (MMS) Gulfwide Offshore Activity
Data System (GOADS) study (2005 Gulfwide Emission Inventory Study MMS
2007-067) for each platform.
(1) MMS GOADS Reporters. Offshore production facilities currently
reporting under the MMS GOADS program will report the same annual
emissions as calculated by GOADS under paragraph (s) of this section.
(i) For the first reporting year, report the latest available
emissions from GOADS.
(ii) In subsequent reporting years when GOADS is updated reporters
shall report the new emissions that are made available from the latest
GOADS software.
(ii) For each reporting year that does not overlap with the GOADS
reporting year, report the last reported GOADS emissions with emissions
adjusted based on the operating time for each platform.
(iii) If MMS discontinues or delays their GOADS survey by more than
4 years, then Platform operators shall collect monthly activity data
every 4 years from platform sources in accordance with the latest
version of the MMS GOADS program instructions, beginning in the year
that the GOADS survey would have been conducted, and annual emissions
shall be calculated using the latest available MMS GOADS emission
factors and methods.
(2) Non-MMS GOADS Reporters. Offshore production facilities not
reporting under the MMS GOADS program shall collect monthly activity
data from platform sources for the first reporting year in accordance
with the latest MMS GOADS program instructions. Annual emissions shall
be calculated using the latest MMS GOADS emission factors and methods.
[[Page 18644]]
(i) In subsequent reporting years, facilities not reporting under
GOADS shall follow the data collection cycle as GOADS in collecting new
activity data monthly to estimate emissions and report emissions.
(ii) For each reporting year that does not overlap with the GOADS
reporting year, report the last reported emissions data with emissions
adjusted based on the operating time for each platform.
(iii) If MMS discontinues or delays their GOADS survey by more than
4 years, then Platform operators shall collect monthly activity data
every 4 years from platform sources in accordance with the latest
version of the MMS GOADS program instructions, and annual emissions
shall be calculated using currently available MMS GOADS emission
factors and methods.
(t) Volumetric emissions. Calculate volumetric emissions at
standard conditions as specified in paragraphs (t)(1) or (2) of this
section.
(1) Calculate natural gas volumetric emissions at standard
conditions by converting ambient temperature and pressure of natural
gas emissions to standard temperature and pressure natural gas using
Equation W-20 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.018
Where:
Es,n = Natural gas volumetric emissions at standard
temperature and pressure (STP) conditions.
Ea,n = Natural gas volumetric emissions at ambient
conditions.
Ts = Temperature at standard conditions. ([deg]F).
Ta = Temperature at actual emission conditions. ([deg]F).
Ps = Absolute pressure at standard conditions (inches of
Hg).
Pa = Absolute pressure at ambient conditions (inches of
Hg).
(2) Calculate GHG volumetric emissions at standard conditions by
converting ambient temperature and pressure of GHG emissions to
standard temperature and pressure using Equation W-21 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.019
Where:
Es,i = GHG i volumetric emissions at standard
temperature and pressure (STP) conditions.
Ea,i = GHG i volumetric emissions at actual
conditions.
Ts = Temperature at standard conditions. ([deg]F).
Ta = Temperature at actual emission conditions.
([deg]F).
Ps = Absolute pressure at standard conditions (inches
of Hg).
Pa = Absolute pressure at ambient conditions (inches
of Hg).
(u) GHG volumetric emissions. Calculate GHG volumetric emissions at
standard conditions as specified in paragraphs (u)(1) and (2) of this
section.
(1) Estimate CH4 and CO2 emissions from
natural gas emissions using Equation W-22 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.020
Where:
Es,i = GHG i (either CH4 or CO2)
volumetric emissions at standard conditions.
Es,n = Natural gas volumetric emissions at standard
conditions.
Mi = Mole percent of GHG i in the natural gas.
(2) For Equation W-22 of this section, the mole percent,
Mi, shall be the annual average mole percent for each
facility, as specified in paragraphs (u)(2)(i) through (vii) of this
section.
(i) GHG mole percent 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 these
values in calculating emissions. If you do not have a continuous gas
composition analyzer, then quarterly samples must be taken according to
methods set forth in Sec. 98.234(b).
(ii) GHG mole percent in feed natural gas for all emissions sources
upstream of the de-methanizer and GHG mole percent in facility specific
residue gas to transmission pipeline systems for all emissions sources
downstream of the de-methanizer overhead for onshore natural gas
processing facilities. If you have a continuous gas composition
analyzer on feed natural gas, you must use these values in calculating
emissions. If you do not have a continuous gas composition analyzer,
then quarterly samples must be taken according to methods set forth in
Sec. 98.234(b).
(iii) GHG mole percent in transmission pipeline natural gas that
passes through the facility for onshore natural gas transmission
compression facilities.
(iv) GHG mole percent in natural gas stored in underground natural
gas storage facilities.
(v) GHG mole percent in natural gas stored in LNG storage
facilities.
(vi) GHG mole percent in natural gas stored in LNG import and
export facilities.
(vii) GHG mole percent in local distribution pipeline natural gas
that passes through the facility for natural gas distribution
facilities.
(v) GHG mass emissions. Calculate GHG mass emissions in carbon
dioxide equivalent at standard conditions by converting the GHG
volumetric emissions into mass emissions using Equation W-23 of this
section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.021
Where:
Masss,i = GHG i (either CH4 or CO2)
mass emissions at standard conditions in metric tons
CO2e.
Es,i = GHG i (either CH4 or CO2)
volumetric emissions at standard conditions, in cubic feet.
[rho]i = Density of GHG i, 0.053 kg/ft\3\ for
CO2 and 0.0193 kg/ft\3\ for CH4.
GWP = Global warming potential, 1 for CO2 and 21 for
CH4.
(w) EOR injection pump blowdown. Calculate pump blowdown emissions
as follows:
(1) Calculate the total volume in cubic feet (including, but not
limited to, pipelines, compressors and vessels) between isolation
valves.
(2) Retain logs of the number of blowdowns per reporting period.
(3) Calculate the total annual venting emissions using Equation W-
24 of this section:
[GRAPHIC] [TIFF OMITTED] TP12AP10.022
[[Page 18645]]
Where:
Massc,i = Annual EOR injection gas venting emissions in
metric tons at critical conditions ``c'' from blowdowns.
N = Number of blowdowns for the equipment in reporting year.
Vv = Total volume in cubic feet of blowdown equipment
chambers (including, but not limited to, pipelines, compressors,
manifolds and vessels) between isolation valves.
Rc = Density of critical phase EOR injection gas in kg/
ft\3\. Use an appropriate standard method published by a consensus-
based standards organization to determine density of super critical
EOR injection gas.
GHGi = Mass fraction of GHGi in critical phase
injection gas.
(x) Hydrocarbon liquids dissolved CO2. Calculate
dissolved CO2 in hydrocarbon liquids as follows:
(1) Determine the amount of CO2 retained in hydrocarbon
liquids after flashing in tankage at STP conditions. Quarterly samples
must be taken according to methods set forth in Sec. 98.234(b) to
determine retention of CO2 in hydrocarbon liquids
immediately downstream of the storage tank. Use the average of the
quarterly analysis for the reporting period.
(2) Estimate emissions using Equation W-25 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.023
Where:
Masss, CO2 = Annual CO2 emissions from
CO2 retained in hydrocarbon liquids beyond tankage, in
metric tons.
Shl = Amount of CO2 retained in hydrocarbon
liquids in metric tons per barrel, under standard conditions.
Vhl = Total volume of hydrocarbon liquids produced in
barrels in the reporting year.
(y) Produced water dissolved CO2. Calculate dissolved
CO2 in produced water as follows:
(1) Determine the amount of CO2 retained in produced
water at STP conditions. Quarterly samples must be taken according to
methods set forth in Sec. 98.234(b) to determine retention of
CO2 in produced water immediately downstream of the
separator where hydrocarbon liquids and produced water are separated.
Use the average of the quarterly analysis for the reporting period.
(2) Estimate emissions using the Equation W-26 of this section.
[GRAPHIC] [TIFF OMITTED] TP12AP10.024
Where:
Masss, CO2 = Annual CO2 emissions from
CO2 retained in produced water beyond tankage, in metric
tons.
Spw = Amount of CO2 retained in produced water
in metric tons per barrel, under standard conditions.
Vpw = Total volume of produced water produced in barrels
in the reporting year.
(3) EOR operations that route produced water from separation
directly to re-injection into the hydrocarbon reservoir in a closed
loop system without any leakage to the atmosphere are exempt from
paragraph (y) of this section.
(z) Portable equipment combustion emissions. Calculate emissions
from portable equipment using the Tier 1 methodology described in
subpart C of this part (General Stationary Fuel Combustion Sources).
Sec. 98.234 Monitoring and QA/QC requirements.
(a) You must use the method described as follows to conduct annual
leak detection of fugitive emissions from all source types listed in
Sec. 98.233(p)(3)(i) and (q) in operation or on standby mode that
occur during a reporting period.
(1) Optical gas imaging instrument. Use an optical gas imaging
instrument for fugitive emissions detection in accordance with 40 CFR
part 60, subpart A, Sec. 60.18(i)(1) and (2) Alternative work practice
for monitoring equipment leaks. In addition, you must operate the
optical gas imaging instrument to image the source types required by
this proposed reporting rule in accordance with the instrument
manufacturer's operating parameters.
(2) [Reserved]
(b) All flow meters, composition analyzers and pressure gauges that
are used to provide data for the GHG emissions calculations shall use
measurement methods, maintenance practices, and calibration methods,
prior to the first reporting year and in each subsequent reporting year
using an appropriate standard method published by a consensus standards
organization such as, but not limited to, ASTM International, American
National Standards Institute (ANSI), and American Petroleum Institute
(API). If a consensus based standard is not available, you must use
manufacturer instructions to calibrate the meters, analyzers, and
pressure gauges.
(c) Use calibrated bags (also known as vent bags) only where the
emissions are at near-atmospheric pressures such that it is safe to
handle and can capture all the emissions, below the maximum temperature
specified by the vent bag manufacturer, and the entire emissions volume
can be encompassed for measurement.
(1) Hold the bag in place enclosing the emissions source to capture
the entire emissions and record the time required for completely
filling the bag. If the bag inflates in less than one second, assume
one second inflation time.
(2) Perform three measurements of the time required to fill the
bag, report the emissions as the average of the three readings.
(3) Estimate natural gas volumetric emissions at standard
conditions using calculations in Sec. 98.233(t).
(4) Estimate CH4 and CO2 volumetric and mass
emissions from volumetric natural gas emissions using the calculations
in Sec. 98.233(u) and (v).
(d) Use a high volume sampler to measure emissions within the
capacity of the instrument.
(1) A technician following manufacturer instructions shall conduct
measurements, including equipment manufacturer operating procedures and
measurement methodologies relevant to using a high volume sampler,
including, but not limited to, positioning the instrument for complete
capture of the fugitive emissions without creating backpressure on the
source.
(2) If the high volume sampler, along with all attachments
available from the manufacturer, is not able to capture all the
emissions from the source then you shall use anti-static wraps or other
aids to capture all emissions without violating operating requirements
as provided in the instrument manufacturer's manual.
(3) Estimate CH4 and CO2 volumetric and mass
emissions from volumetric natural gas emissions using the calculations
in Sec. 98.233(u) and (v).
(4) Calibrate the instrument at 2.5 percent methane with 97.5
percent air and 100 percent CH4 by using calibrated gas
samples and by following manufacturer's instructions for calibration.
Sec. 98.235 Procedures for estimating missing data.
A complete record of all estimated and/or measured parameters used
in the GHG emissions calculations is required. If data are lost or an
error occurs during annual emissions estimation or measurements, you
must repeat the estimation or measurement activity for those sources as
soon as possible, including in the subsequent reporting year if missing
data are not discovered until after December 31 of the reporting year,
until valid data for reporting is obtained. Data developed and/or
collected in a subsequent reporting year to substitute for missing data
cannot be used for that subsequent year's emissions estimation. Where
missing
[[Page 18646]]
data procedures are used for the previous year, at least 30 days must
separate emissions estimation or measurements for the previous year and
emissions estimation or measurements for the current year of data
collection.
Sec. 98.236 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain reported emissions as specified in this
section.
(a) Report annual emissions separately for each of the industry
segment listed in paragraphs (a) (1) through (8) of this section. For
each segment, report emissions from each source type in the aggregate,
unless specified otherwise. For example, an underground natural gas
storage operation with multiple reciprocating compressors must report
emissions from all reciprocating compressors as an aggregate number.
(1) Onshore petroleum and natural gas production.
(2) Offshore petroleum and natural gas production.
(3) Onshore natural gas processing.
(4) Onshore natural gas transmission compression.
(5) Underground natural gas storage.
(6) LNG storage.
(7) LNG import and export.
(8) Natural gas distribution. Report each source in the aggregate
for pipelines and for Metering and Regulating (M&R) stations.
(b) Report emissions separately for standby equipment.
(c) Report activity data for each aggregated source type as
follows:
(1) Count of natural gas pneumatic high bleed devices.
(2) Count of natural gas pneumatic low bleed devices.
(3) Count of natural gas driven pneumatic pumps.
(4) For each acid gas removal unit report the following:
(i) Total volume of natural gas flow into the acid gas removal
unit.
(ii) Total volume of natural gas flow out of the acid gas removal
unit.
(iii) Volume weighted CO2 content of natural gas into
the acid gas removal unit.
(5) For each dehydrator unit report the following:
(i) Glycol dehydrators:
(A) Glycol dehydrator feed natural gas flow rate.
(B) Glycol dehydrator absorbent circulation pump type.
(C) Glycol dehydrator absorbent circulation rate.
(D) Whether stripper gas is used in glycol dehydrator.
(E) Whether a flash tank separator is used in glycol dehydrator.
(ii) Desiccant dehydrators:
(A) The number of desiccant dehydrators operated.
(B) [Reserved]
(6) Count of wells vented to the atmosphere for liquids unloading
for each field in the basin.
(7) Count of wells venting during well completions for each field
in the basin.
(i) Number of conventional completions.
(ii) Number of completions involving hydraulic fracturing.
(8) Count of wells venting during well workovers for each field in
the basin.
(i) Number of conventional well workovers involving well venting to
the atmosphere.
(ii) Number of unconventional well workovers involving well venting
to the atmosphere.
(9) For each compressor blowdown vent stack report the following
for each compressor:
(i) Type of compressor whether reciprocating or centrifugal.
(ii) Compressor capacity in horse powers.
(iii) Volume of gas between isolation valves.
(iv) Number of blowdowns per year.
(10) For each estimate of gas emitted from liquids sent to
atmospheric tank using E&P Tank report the following:
(i) Immediate upstream separator temperature and pressure.
(ii) Sales oil API gravity.
(iii) Estimate of individual tank or tank battery capacity in
barrels.
(iv) Oil, hydrocarbon condensate and water sent to tank(s) in
barrels.
(v) Control measure: Either vapor recovery system or flaring of
tank vapors.
(11) For tank emissions identified using optical gas imaging
instrument per Sec. 98.234(a), report the following for each tank:
(i) Immediate upstream separator temperature and pressure.
(ii) Sales oil API gravity.
(iii) Tank capacity in barrels.
(iv) Tank throughput in barrels.
(v) Control measure: Either vapor recovery system or flaring of
tank vapors.
(vi) Optical gas imagining instrument used.
(vii) Meter used for measuring emissions.
(viii) List of emissions sources routed to the tank.
(12) For well testing report the following for each field in the
basin:
(i) Number of wells tested in reporting period.
(ii) Average gas to oil ratio for each field.
(iii) Average flow rate during testing for each field.
(iv) Average number of days the well is tested.
(v) Whether the hydrocarbons produced during testing are vented or
flared.
(13) For associated natural gas venting report the following for
each field in the basin:
(i) Number of wells venting or flaring associated natural gas in
reporting period.
(ii) Average gas to oil ratio for each field.
(iii) Average volume of oil produced per well per field.
(iv) Whether the associated natural gas is vented or flared.
(14) For flare stacks report the following for each flare:
(i) Whether flare has a continuous flow monitor.
(ii) If using engineering estimation methods, identify sources of
emissions going to the flare.
(iii) Whether flare has a continuous gas analyzer.
(iv) Identify proportion of total natural gas to pure hydrocarbon
stream being sent to the flare annually for the reporting period.
(v) Flare combustion efficiency.
(15) For well venting for liquids unloading report the following by
field, basin, and well tubing size:
(i) Number of wells being unloaded for liquids in reporting year.
(ii) Average number of unloading(s) per well per reporting year.
(iii) Average volume of natural gas produced per well per reporting
year during liquids unloading.
(16) For well completions and workovers report the following for
each field in the basin:
(i) Number of wells completed (worked over) in reporting year.
(ii) Average number of days required for completion (workover).
(iii) Average volume of natural gas produced per well per reporting
year during well completion (workover).
(17) For compressor wet seal degassing vents report the following
for each degassing vent:
(i) Number of wet seals connected to the degassing vent.
(ii) Number of compressors whose wet seals are connected to the
degassing vent.
(iii) Total throughput of compressors whose wet seals are connected
to the degassing vent.
(iv) Type of meter used for making measurements.
(v) Whether emissions estimate is based on a continuous or one time
measurement.
(vi) Total time the compressor(s) associated with the degassing
vent stack
[[Page 18647]]
is operating. Sum the hours of operation if multiple compressors are
connected to the vent stack.
(vii) Proportion of vent gas recovered for fuel gas or sent to a
flare.
(18) For reciprocating compressor rod packing report the following
per rod packing:
(i) Total throughput of the reciprocating compressor whose rod
packing emissions is being reported.
(ii) Total time in hours the reciprocating compressor is in
operating mode.
(iii) Whether or not the rod packing case is connected to an open
ended line.
(iv) If rod packing is connected to an open ended line, report type
of device used for measurement emissions.
(v) If rod packing is not connected to an open ended vent line,
report the locations from where the emissions from the rod packing are
detected.
(19) For fugitive emissions sources using emission factors for
estimating emissions report the following:
(i) Component count for each fugitive emissions source.
(ii) CH4 and CO2 in produced natural gas for
onshore petroleum and natural gas production.
(20) For EOR injection pump blowdown report the following per pump:
(i) Pump capacity.
(ii) Volume of gas between isolation valves.
(iii) Number of blowdowns per year.
(iv) Supercritical phase EOR injection gas density.
(21) For hydrocarbon liquids dissolved CO2 report the
following for each field in the basin:
(i) Volume of crude oil produced.
(ii) [Reserved]
(22) For produced water dissolved CO2 report the
following for each field in the basin:
(i) Volume of produced water produced.
(ii) [Reserved]
(d) Minimum, maximum and average throughput for each operation
listed in paragraphs (a)(1) through (a)(8) of this section.
(e) For offshore petroleum and natural gas production facilities,
the number of connected wells, and whether the wells are producing oil,
gas, or both.
(f) Report emissions separately for portable equipment for the
following source types: drilling rigs, dehydrators, compressors,
electrical generators, steam boilers, and heaters.
(1) Aggregate emissions by source type.
(2) Report count of each source type.
Sec. 98.237 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the following records:
(a) Dates on which measurements were conducted.
(b) Results of all emissions detected and measurements.
(c) Calibration reports for detection and measurement instruments
used.
(d) Inputs and outputs of calculations or emissions computer model
runs used for engineering estimation of emissions.
Sec. 98.238 Definitions.
Except as provided below, all terms used in this subpart have the
same meaning given in the Clean Air Act and subpart A of this part.
Natural gas distribution facility means the distribution pipelines,
metering stations, and regulating stations that are operated by a Local
Distribution Company (LDC) that is regulated as a separate operating
company by a public utility commission or that are operated as an
independent municipally-owned distribution system.
Offshore petroleum and natural gas production facility means each
platform structure and all associated equipment as defined in paragraph
(a)(1) of this section. All production equipment that is connected via
causeways or walkways are one facility.
Onshore petroleum and natural gas production facility means all
petroleum or natural gas equipment associated with all petroleum or
natural gas production wells under common ownership or common control
by an onshore petroleum and natural gas production owner or operator
located in a single hydrocarbon basin as defined by the American
Association of Petroleum Geologists which is assigned a three digit
Geologic Province Code. Where an operating entity holds more than one
permit in a basin, then all onshore petroleum and natural gas
production equipment relating to all permits in their name in the basin
is one onshore petroleum and natural gas production facility.
Separator means a vessel in which streams of multiple phases are
gravity separated into individual streams of single phase.
Table W-1 of Subpart W--Default Whole Gas Emission Factors for Onshore
Production
------------------------------------------------------------------------
Emission Factor
Onshore production (scf/hour/
component)
------------------------------------------------------------------------
Population Emission Factors--All Components, Gas
Service
Valve............................................ 0.08
Connector........................................ 0.01
Open-ended Line.................................. 0.04
Pressure Relief Valve............................ 0.17
Low-Bleed Pneumatic Device Vents................. 2.75
Gathering Pipelines 1............................ 2.81
CBM Well Water Production 2...................... 0.11
Population Emission Factors--All Components, Light
Crude Service 3
Valve............................................ 0.04
Connector........................................ 0.01
Open-ended Line.................................. 0.04
Pump............................................. 0.01
Other 5.......................................... 0.24
Population Emission Factors--All Components, Heavy
Crude Service 4
Valve............................................ 0.001
Flange........................................... 0.001
Connector (other)................................ 0.0004
Open-ended Line.................................. 0.01
Other 5.......................................... 0.003
------------------------------------------------------------------------
\1\ Emission Factor is in units of ``scf/hour/mile``.
\2\ Emission Factor is in units of ``scf methane/gallon``, in this case
the operating factor is ``gallons/year'' and do not multiply by
methane content.
[[Page 18648]]
\3\ Hydrocarbon liquids greater than or equal to 20*API are considered
``light crude``.
\4\ Hydrocarbon liquids less than 20*API are considered ``heavy crude``.
\5\ ``Others'' category includes instruments, loading arms, pressure
relief valves, stuffing boxes, compressor seals, dump lever arms, and
vents.
Table W-2 of Subpart W--Default Total Hydrocarbon Emission Factors for
Processing
------------------------------------------------------------------------
Before de- After de-
methanizer methanizer
Processing emission factor emission factor
(scf/hour/ (scf/hour/
component) component)
------------------------------------------------------------------------
Leaker Emission Factors--Reciprocating Compressor Components, Gas
Service
------------------------------------------------------------------------
Valve............................. 15.88 18.09
Connector......................... 4.31 9.10
Open-ended Line................... 17.90 10.29
Pressure Relief Valve............. 2.01 30.46
Meter............................. 0.02 48.29
------------------------------------------------------------------------
Leaker Emission Factors--Centrifugal Compressor Components, Gas Service
------------------------------------------------------------------------
Valve............................. 0.67 2.51
Connector......................... 2.33 3.14
Open-ended Line................... 17.90 16.17
Dry Seal.......................... 105 105
------------------------------------------------------------------------
Leaker Emission Factors--Other Components, Gas Service
------------------------------------------------------------------------
Valve............................. 6.42
Connector......................... 5.71
Open-ended Line................... 11.27
Pressure Relief Valve............. 2.01
Meter............................. 2.93
------------------------------------------------------------------------
Population Emission Factors--Other Components, Gas Service
------------------------------------------------------------------------
Gathering Pipelines \1\........... 2.81
------------------------------------------------------------------------
\1\ Emission Factor is in units of ``scf/hour/mile''.
Table W-3 of Subpart W--Default Methane Emission Factors for
Transmission
------------------------------------------------------------------------
Emission Factor
Transmission (scf/hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--All Components, Gas Service
------------------------------------------------------------------------
Connector............................................ 2.7
Block Valve.......................................... 10.4
Control Valve........................................ 3.4
Compressor Blowdown Valve............................ 543.5
Pressure Relief Valve................................ 37.2
Orifice Meter........................................ 14.3
Other Meter.......................................... 0.1
Regulator............................................ 9.8
Open-ended Line...................................... 21.5
------------------------------------------------------------------------
Population Emission Factors--Other Components, Gas Service
------------------------------------------------------------------------
Low-Bleed Pneumatic Device Vents..................... 2.57
------------------------------------------------------------------------
Table W-4 of Subpart W--Default Methane Emission Factors for Underground
Storage
------------------------------------------------------------------------
Emission Factor
Underground storage (scf/hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--Storage Station, Gas Service
------------------------------------------------------------------------
Connector............................................ 0.96
Block Valve.......................................... 2.02
Control Valve........................................ 3.94
Compressor Blowdown Valve............................ 66.15
Pressure Relief Valve................................ 19.80
Orifice Meter........................................ 0.46
[[Page 18649]]
Other Meter.......................................... 0.01
Regulator............................................ 1.03
Open-ended Line...................................... 6.01
------------------------------------------------------------------------
Population Emission Factors--Storage Wellheads, Gas Service
------------------------------------------------------------------------
Connector............................................ 0.01
Valve................................................ 0.10
Pressure Relief Valve................................ 0.17
Open-ended Line...................................... 0.03
------------------------------------------------------------------------
Population Emission Factors--Other Components, Gas Service
------------------------------------------------------------------------
Low-Bleed Pneumatic Device Vents..................... 2.57
------------------------------------------------------------------------
Table W-5 of Subpart W--Default Methane Emission Factors for Liquefied
Natural Gas (LNG) Storage
------------------------------------------------------------------------
Emission Factor
LNG storage (scf/hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--LNG Storage Components, LNG Service
------------------------------------------------------------------------
Valve................................................ 1.19
Pump Seal............................................ 4.00
Connector............................................ 0.34
Other\1\............................................. 1.77
------------------------------------------------------------------------
Population Emission Factors--LNG Storage Compressor, Gas Service
------------------------------------------------------------------------
Vapor Recovery Compressor............................ 6.81
------------------------------------------------------------------------
\1\ ``other'' equipment type should be applied for any equipment type
other than connectors, pumps, or valves.
Table W-6 of Subpart W--Default Methane Emission Factors for LNG
Terminals
------------------------------------------------------------------------
Emission Factor
LNG terminals (scf/hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--LNG Terminals Components, LNG Service
------------------------------------------------------------------------
Valve................................................ 1.19
Pump Seal............................................ 4.00
Connector............................................ 0.34
Other................................................ 1.77
------------------------------------------------------------------------
Population Emission Factors--LNG Terminals Compressor, Gas Service
------------------------------------------------------------------------
Vapor Recovery Compressor............................ 6.81
------------------------------------------------------------------------
Table W-7 of Subpart W--Default Methane Emission Factors for
Distribution
------------------------------------------------------------------------
Emission Factor
Distribution (scf/hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--Above Grade M&R Stations Components, Gas
Service
------------------------------------------------------------------------
Connector............................................ 1.69
Block Valve.......................................... 0.557
Control Valve........................................ 9.34
Pressure Relief Valve................................ 0.270
Orifice Meter........................................ 0.212
Regulator............................................ 0.772
Open-ended Line...................................... 26.131
------------------------------------------------------------------------
Population Emission Factors--Below Grade M&R Stations Components, Gas
Service \1\
------------------------------------------------------------------------
Below Grade M&R Station, Inlet Pressure > 300 psig... 1.30
[[Page 18650]]
Below Grade M&R Station, Inlet Pressure 100 to 300 0.20
psig................................................
Below Grade M&R Station, Inlet Pressure < 100 psig... 0.10
------------------------------------------------------------------------
Population Emission Factors--Distribution Mains, Gas Service \2\
------------------------------------------------------------------------
Unprotected Steel.................................... 12.58
Protected Steel...................................... 0.35
Plastic.............................................. 1.13
Cast Iron............................................ 27.25
------------------------------------------------------------------------
Population Emission Factors--Distribution Services, Gas Service \2\
------------------------------------------------------------------------
Unprotected Steel.................................... 0.19
Protected Steel...................................... 0.02
Plastic.............................................. 0.001
Copper............................................... 0.03
------------------------------------------------------------------------
\1\ Emission Factor is in units of ``scf/hour/station``
\2\ Emission Factor is in units of ``scf/hour/service``
Table W-8 of Subpart W--Default Nitrous Oxide Emission Factors for Gas
Flaring
------------------------------------------------------------------------
Emission Factor
(metric tons/
Gas Flaring MMscf gas
production or
receipts)
------------------------------------------------------------------------
Population Emission Factors--Gas Flaring
------------------------------------------------------------------------
Gas Production....................................... 5.90E-07
Sweet Gas Processing................................. 7.10E-07
Sour Gas Processing.................................. 1.50E-06
Conventional Oil Production \1\...................... 1.00E-04
Heavy Oil Production \2\............................. 7.30E-05
------------------------------------------------------------------------
\1\ Emission Factor is in units of ``metric tons/barrel conventional oil
production``
\2\ Emission Factor is in units of ``metric tons/barrel heavy oil
production``
[FR Doc. 2010-6767 Filed 4-9-10; 8:45 am]
BILLING CODE 6560-50-P