[Federal Register Volume 75, Number 229 (Tuesday, November 30, 2010)]
[Rules and Regulations]
[Pages 74458-74515]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-28655]
[[Page 74457]]
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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; Final Rule
Federal Register / Vol. 75 , No. 229 / Tuesday, November 30, 2010 /
Rules and Regulations
[[Page 74458]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 98
[EPA-HQ-OAR-2009-0923; FRL-9226-1]
RIN 2060-AP99
Mandatory Reporting of Greenhouse Gases: Petroleum and Natural
Gas Systems
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: EPA is promulgating a regulation to require monitoring and
reporting of greenhouse gas emissions from petroleum and natural gas
systems. This action adds this source category to the list of source
categories already required to report greenhouse gas emissions. This
action applies to sources with carbon dioxide equivalent emissions
above certain threshold levels as described in this regulation. This
action does not require control of greenhouse gases.
DATES: The final rule is effective on December 30, 2010. The
incorporation by reference of certain publications listed in the rule
is approved by the Director of the Federal Register as of December 30,
2010.
ADDRESSES: EPA established a single docket under Docket ID No. EPA-HQ-
OAR-2009-0923 for this action. All documents in the docket are listed
on the http://www.regulations.gov Web site. Although listed in the
index, some information is not publicly available, e.g., confidential
business information (CBI) or other information whose disclosure is
restricted by statute. Certain other material, such as copyrighted
material, is not placed on the Internet and will be publicly available
only in hard copy form. Publicly available docket materials are
available either electronically through http://www.regulations.gov or
in hard copy at EPA's Docket Center, Public Reading Room, EPA West
Building, Room 3334, 1301 Constitution Avenue, 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) 566-1741.
FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division,
Office of Atmospheric Programs (MC-6207J), Environmental Protection
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone
number: (202) 343-9263; fax number: (202) 343-2342; e-mail address:
[email protected]. For technical information and implementation
materials, please go to the Web site http://www.epa.gov/climatechange/emissions/ghgrulemaking.html. To submit a question, select Rule Help
Center, followed by Contact Us.
SUPPLEMENTARY INFORMATION:
Regulated Entities. The Administrator determined that this action
is subject to the provisions of Clean Air Act (CAA) section 307(d). See
CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to
``such other actions as the Administrator may determine''). This final
rule affects owners or operators of petroleum and natural gas systems.
Regulated categories and entities may include those listed in Table 1
of this preamble:
Table 1--Examples of Affected Entities by Category
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Examples of affected
Source category NAICS 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. Although Table 1 of this preamble lists the
types of facilities of which EPA is aware that could be potentially
affected by this action, other types of facilities not listed in the
table could also be subject to reporting requirements. To determine
whether you are affected by this action, you should carefully examine
the applicability criteria found in 40 CFR part 98, subpart A as
amended by this action. 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 final rule have GHG
emissions from multiple source categories listed in 40 CFR part 98.
Table 2 of this preamble has been developed as a guide to help
potential reporters in the petroleum and natural gas industry affected
by this action identify other source categories (by subpart) that they
may need to: (1) Consider in their facility applicability
determination, and (2) include in their reporting. Table 2 of this
preamble identifies the subparts that are likely to be relevant to
sources with petroleum and natural gas systems. 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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Other subparts recommended for
Source category review to determine applicability
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Petroleum and Natural Gas Systems. 40 CFR part 98, subpart C: General
Stationary Fuel Combustion Sources.
40 CFR part 98, subpart Y: Petroleum
Refineries.
40 CFR part 98, subpart MM:
Suppliers of Petroleum Products.
40 CFR part 98, subpart NN:
Suppliers of Natural Gas and
Natural Gas Liquids.
40 CFR part 98, subpart PP:
Suppliers of Carbon Dioxide
40 CFR part 98, subpart RR:
Injection and Geologic
Sequestration of Carbon Dioxide
(proposed).
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[[Page 74459]]
What is the effective date? The final rule is effective on December
30, 2010. Section 553(d) of the Administrative Procedure Act (APA), 5
U.S.C. Chapter 5, generally provides that rules may not take effect
earlier than 30 days after they are published in the Federal Register.
EPA is issuing this final rule under section 307(d)(1) of the Clean Air
Act, which states: ``The provisions of section 553 through 557 * * * of
Title 5 shall not, except as expressly provided in this section, apply
to actions to which this subsection applies.'' Thus, section 553(d) of
the APA does not apply to this rule. EPA is nevertheless acting
consistently with the purposes underlying APA section 553(d) in making
this rule effective on December 30, 2010. Section 5 U.S.C. 553(d)(3)
allows an effective date less than 30 days after publication ``as
otherwise provided by the agency for good cause found and published
with the rule.'' As explained below, EPA finds that there is good cause
for this rule to become effective on or before December 31, 2010, even
if this results in an effective date fewer than 30 days from date of
publication in the Federal Register.
While this action is being signed prior to December 1, 2010, there
is likely to be a significant delay in the publication of this rule as
it contains complex diagrams, equations, and charts, and is relatively
long in length. As an example, EPA signed a shorter technical
amendments package related to the same underlying reporting rule on
October 7, 2010, and it was not published until October 28, 2010, 75 FR
66434, three weeks later.
The purpose of the 30-day waiting period prescribed in 5 U.S.C.
553(d) is to give affected parties a reasonable time to adjust their
behavior and prepare before the final rule takes effect. Where, as
here, the final rule will be signed and made available on the EPA Web
site more than 30 days before the effective date, but where the
publication is likely to be delayed due to the complexity and length of
the rule, that purpose is still met. Moreover, for specified emission
sources for certain industry segments, EPA has made available the
optional use of best available monitoring methods (BAMM) during the
2011 calendar year. For these circumstances, facilities covered by this
rule may use BAMM for any parameter for which it is not reasonably
feasible to acquire, install, or operate a required piece of monitoring
equipment in a facility, or to procure measurement services from
necessary providers. This will provide facilities a substantial
additional period to adjust their behavior to the requirements of the
final rule. Accordingly, we find good cause exists to make this rule
effective on or before December 31, 2010, consistent with the purposes
of 5 U.S.C. 553(d)(3).\1\
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\1\ We recognize that this rule could be published at least 30
days before December 31, 2010, which would negate the need for this
good cause finding, and we plan to request expedited publication of
this rule in order to decrease the likelihood of a printing delay.
However, as we cannot know the date of publication in advance of
signing this rule, we are proceeding with this good cause finding
for an effective date on or before December 31, 2010.
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Judicial Review
Under CAA section 307(b)(1), judicial review of this final rule is
available only by filing a petition for review in the U.S. Court of
Appeals for the District of Columbia Circuit by January 31, 2011. Under
CAA section 307(d)(7)(B), only an objection to this final rule that was
raised with reasonable specificity during the period for public comment
can be raised during judicial review. This section also provides a
mechanism for us to convene a proceeding for reconsideration, ``[i]f
the person raising an objection can demonstrate to EPA that it was
impracticable to raise such objection within [the period for public
comment] or if the grounds for such objection arose after the period
for public comment (but within the time specified for judicial review)
and if such objection is of central relevance to the outcome of this
rule.'' Any person seeking to make such a demonstration to us should
submit a Petition for Reconsideration to the Office of the
Administrator, Environmental Protection Agency, Room 3000, Ariel Rios
Building, 1200 Pennsylvania Ave., NW., Washington, DC 20004, with a
copy to the person listed in the preceding FOR FURTHER INFORMATION
CONTACT section, and the Associate General Counsel for the Air and
Radiation Law Office, Office of General Counsel (Mail Code 2344A),
Environmental Protection Agency, 1200 Pennsylvania Ave., NW.,
Washington, DC 20004. Note, under CAA section 307(b)(2), the
requirements established by this final rule may not be challenged
separately in any civil or criminal proceedings brought by EPA to
enforce these requirements.
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
AAPG American Association of Petroleum Geologists
AGA American Gas Association
AGR Acid gas removal
ANSI American National Standards Institute
API American Petroleum Institute
ASME American Society of Mechanical Engineers
ASTM American Society for Testing and Materials
BLS Bureau of Labor Statistics
BOEMRE Bureau of Ocean Energy Management, Regulation and Enforcement
CAA Clean Air Act
CBI Confidential business information
CBM Coal bed methane
CEMS Continuous emission monitoring systems
cf cubic feet
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e CO2-equivalent
DOE Department of Energy
E&P exploration and production
EIA Economic Impact Analysis
EO Executive Order
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
ESD emergency shutdown
FPSO floating production and storage offloading
FR Federal Register
GHG greenhouse gas
GOR gas to oil ratio
GRI Gas Research Institute
GWP global warming potential
HHV high heat value
IBR incorporation by reference
ICR information collection request
IPCC Intergovernmental Panel on Climate Change
IR infrared
ISO International Organization for Standardization
kg kilograms
LACT lease automatic custody transfer
LDCs local natural gas distribution companies
LNG liquefied natural gas
LPG liquefied petroleum gas
M&R meters and regulators
mmBtu million British thermal units
MMS Minerals Management Service
MMscfd million standard cubic feet per day
MMTCO2e million metric tons carbon dioxide equivalent
MRR mandatory GHG reporting rule
N2O nitrous oxide
NAESB North American Energy Standards Board
NAICS North American Industry Classification System
NGLs natural gas liquids
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality, Planning and Standards
OMB Office of Management and Budget
OVA organic vapor analyzer
ppm parts per million
QA quality assurance
QA/QC quality assurance/quality control
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
RIA Regulatory Impact Analysis
SBA Small Business Administration
SBREFA Small Business Regulatory Enforcement and Fairness Act
SSM startup, shutdown, and malfunction
STP standard temperature and pressure
TCR The Climate Registry
TSD technical support document
TVA toxic vapor analyzer
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U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
U.S.C. United States Code
USGS United States Geologic Society
VOC volatile organic compound(s)
WCI Western Climate Initiative
Table of Contents
I. Background
A. Organization of this Preamble
B. Background on the Final Rule
C. Legal Authority
II. Reporting Requirements for Petroleum and Natural Gas Systems
A. Overview of Greenhouse Gas Reporting Program
B. Overview of Confidentiality Determination for Data Elements
in the Greenhouse Gas Reporting Program
C. Summary of Changes to the General Provisions of the
Greenhouse Gas Reporting Program
D. Summary of the Requirements for Petroleum and Natural Gas
Systems (Subpart W)
E. Summary of Major Changes and Clarifications Since Proposal
F. Summary of Comments and Responses
III. Economic Impacts of the Rule
A. How were compliance costs estimated?
B. What are the costs of the rule?
C. What are the economic impacts of the rule?
D. What are the Impacts of the Rule on Small Businesses?
E. What are the Benefits of the 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
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act
I. Background
A. Organization of This Preamble
This preamble consists of four sections. The first section provides
a brief history of 40 CFR part 98 and describes the purpose and legal
authority for this action.
The second section of this preamble summarizes the revisions made
to the general provisions in 40 CFR part 98, subpart A and outlines the
specific requirements for subpart W being incorporated into 40 CFR part
98 by this action. It also describes the major changes made to this
source category since proposal and provides a brief summary of
significant public comments and EPA's responses on issues specific to
each industry segment. Additional responses to significant comments can
be found in the document Mandatory Greenhouse Gas Reporting Rule: EPA's
Response to Public Comments, Subpart W: Petroleum and Natural Gas
Systems.
The third section of this preamble provides the summary of the cost
impacts, economic impacts, and benefits of the final rule and discusses
comments on the economic impact analyses for subpart W.
Finally, the last section discusses the various statutory and
executive order requirements applicable to this rulemaking.
B. Background on the Final Rule
This action finalizes monitoring and reporting requirements for
petroleum and natural gas systems.
On April 12, 2010, EPA proposed subpart W--Petroleum and Natural
Gas Systems, amending 40 CFR part 98 (i.e., the regulatory requirements
for the Greenhouse Gas Reporting Program). The GHG Reporting Program
requires reporting of GHG emissions and other relevant information from
certain source categories in the United States. The GHG Reporting
Program, which became effective on December 29, 2009, includes
reporting requirements for facilities and suppliers in 32 source
categories. EPA established this program in response to the fiscal year
2008 Consolidated Appropriations Act.\2\ This Act authorized funding
for EPA to develop and publish a rule ``* * * to require the mandatory
reporting of greenhouse gas emissions above appropriate thresholds in
all sectors of the economy of the United States.'' An accompanying
joint explanatory statement directed EPA to ``use its existing
authority under the Clean Air Act'' to develop a mandatory GHG
reporting rule. For more detailed background information on the GHG
Reporting Program, see the preamble to the final rule establishing the
GHG Reporting Program (74 FR 56260, October 30, 2009).
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\2\ Consolidated Appropriations Act, 2008, Public Law 110-161,
121 Stat. 1844, 2128. Congress reaffirmed interest in a GHG
reporting rule, and provided additional funding in the 2009 and 2010
Appropriations Acts (Consolidated Appropriations Act, 2009, Pub. L.
110-329, 122 Stat. 3574-3716 and Consolidated Appropriations Act,
2010, Pub. L. 111-117, Stat. 3034-3408).
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This final action adds requirements for facilities that contain
petroleum and natural gas systems to report equipment leaks and vented
GHG emissions (subpart W) to the GHG Reporting Program. The 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. These data will inform EPA's
implementation of CAA section 103(g) regarding improvements in sector
based non-regulatory strategies and technologies for preventing or
reducing air pollutants, and inform policy on possible regulatory
actions to address GHG emissions. As stated earlier in this section,
this rule was proposed by EPA on April 12, 2010. One public hearing was
held in April 2010, and the 60-day public comment period ended June 11,
2010.
C. Legal Authority
EPA is promulgating 40 CFR part 98, subpart W under the existing
CAA authorities provided in CAA section 114. As discussed in detail in
Sections I.C and II.Q of the preamble to the 2009 final rule (74 FR
56260), CAA section 114(a)(1) provides EPA with broad authority to
require emissions sources, persons subject to the CAA, manufacturers of
process or control equipment, or persons whom the Administrator
believes may have necessary information to monitor and report emissions
and provide such other information as the Administrator requests for
the purposes of carrying out any provision of the CAA. EPA may gather
information for a variety of purposes, including for the purpose of
assisting in the development of emissions reduction regulations in the
petroleum and natural gas industry, determining compliance with
implementation plans or standards, or more broadly for ``carrying out
any provision'' of the CAA. Section 103 of the CAA authorizes EPA to
establish a national research and development program, including non-
regulatory approaches and technologies, for the prevention and control
of air pollution, including GHGs. As discussed in the petroleum and
natural gas systems proposal (75 FR 18608, April 12, 2010), among other
things, data from petroleum and natural gas systems will inform
decisions about possible emissions reduction regulations in the
petroleum and natural gas industry. The data collected will also inform
EPA's implementation of CAA section 103(g) regarding improvements in
sector-based
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non-regulatory strategies and technologies for preventing or reducing
air pollutants.
EPA has the authority under the CAA to collect emissions
information from offshore petroleum and natural gas platforms including
those located in areas of the Central and Western Gulf of Mexico as
identified in CAA section 328(b). This final action 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 offshore platforms will
inform our analyses, including options applicable to emissions of any
offshore platforms that EPA is authorized to regulate under the CAA.
II. Reporting Requirements for Petroleum and Natural Gas Systems
A. Overview of Greenhouse Gas Reporting Program
The GHG Reporting Program requires reporting of GHG emissions and
other relevant information from certain source categories in the United
States, as discussed in Section I.B. of this preamble. The rule
requires annual reporting of GHGs including carbon dioxide
(CO2), methane (CH4), nitrous oxide
(N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs),
sulfur hexafluoride (SF6), and other fluorinated compounds
(e.g., hydrofluoroethers (HFEs)).
The GHG Reporting Program requires that source categories subject
to 40 CFR part 98 monitor and report GHGs in accordance with the
methods specified in the individual subparts. For a list of the
specific GHGs to be reported and the GHG calculation procedures,
monitoring, missing data procedures, recordkeeping, and reporting
required by facilities subject to subpart W included in this action,
see Section II.D of this preamble.
B. Overview of Confidentiality Determination for Data Elements in the
Greenhouse Gas Reporting Program
This final rule does not address whether data reported under
subpart W will be released to the public or will be treated as
confidential business information. EPA published a proposed rule and
confidentiality determination on July 7, 2010 (75 FR 39094) that
addressed this issue. In that action, EPA proposed which specific data
elements would be released to the public and which would be treated as
confidential business information. EPA received comments on the
proposal, and is in the process of considering these comments. A final
rule and determination will be issued before any data are released, and
the final determination will include all of the data elements under
subpart W.
C. Summary of Changes to the General Provisions of the Greenhouse Gas
Reporting Program
This final action amends certain requirements in 40 CFR part 98,
subpart A (General Provisions). These amendments are summarized in this
section of the preamble.
Changes to Applicability. In this final action, EPA is amending
Table A-4 of subpart A, referenced in 40 CFR 98.2(a)(2), to add the
petroleum and natural gas systems source category. In addition, EPA is
amending 40 CFR 98.2(a) so that 40 CFR part 98 applies to facilities
located in the United States and on or under the Outer Continental
Shelf. This revision is necessary to ensure that any petroleum or
natural gas platforms located on or under the Outer Continental Shelf
of the United States are required to report under 40 CFR part 98,
subpart W.
Changes to Definitions. In this final action, EPA is also amending
40 CFR 98.6 (definitions). EPA is revising the definition of United
States as applied under part 98 to clarify that it includes the
territorial seas. Other facilities located offshore of the United
States covered by the GHG Reporting Program at 40 CFR part 98 may also
be affected by this change in the definition of United States. In
addition to the change to the definition of United States, EPA has
amended 40 CFR 98.6 by adding a definition of ``Outer Continental
Shelf.'' This definition is drawn from the definition in the U.S. Code
and the Clean Air Act, 328(a)(4)(A). These revisions are necessary to
ensure that facilities on land, in the territorial seas, or on or under
the Outer Continental Shelf, as defined in 43 U.S.C. 1331, and that
otherwise meet the applicability criteria of the rule are required to
report.
Incorporation by Reference (IBR). In the April 2010 proposal, EPA
proposed to amend 40 CFR 98.7 by including the following standard
methods: GRI GlyCalc software, the E&P Tank software, and the American
Association of Petroleum Geologist (AAPG) Geologic Provinces Code Map.
EPA has revised the listing of proposed methods for incorporation by
reference. Hence, in this final action EPA is finalizing amendments to
40 CFR 98.7 (incorporation by reference) to include standard methods
referenced in 40 CFR part 98, subpart W. Those include: American
Association of Petroleum Geologists Geologic Provinces Code Map
including the Alaska Geological Province Boundary Map; and the Energy
Information Administration Oil and Gas Field Code Master List.
D. Summary of the Requirements for Petroleum and Natural Gas Systems
(Subpart W)
1. Summary of the Final Rule
Source Category Definition. This source category consists of the
following segments of the petroleum and natural gas systems source
category:
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 processes and/or transfers such hydrocarbons to
storage, transport vessels, or onshore. In addition, offshore
production includes secondary platform structures connected to the
platform structure via walkways, storage tanks associated with the
platform structure, and floating production and storage offloading
equipment (FPSO). This source category does not include reporting of
emissions from offshore drilling and, exploration that is not
conducted on production platforms.
Onshore petroleum and natural gas production. Onshore
petroleum and natural gas production means all equipment on a well
pad or associated with a well pad (including compressors,
generators, or storage facilities), and portable non-self-propelled
equipment on a well pad or associated with a well pad (including
well drilling and completion equipment, workover equipment, gravity
separation equipment, auxiliary non-transportation-related
equipment, and leased, rented or contracted equipment) used in the
production, extraction, recovery, lifting, stabilization, separation
or treating of petroleum and/or natural gas (including condensate).
This equipment also includes associated storage or measurement
vessels and all enhanced oil recovery (EOR) operations using
CO2, 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.
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Onshore natural gas processing. Natural gas processing
means facilities that separate and recovers natural gas liquids
(NGLs) and/or other non-methane gases and liquids from a stream of
produced natural gas using 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. This
segment also includes all residue gas compression equipment owned or
operated by the natural gas processing facility, whether inside or
outside the processing facility fence. This source category does not
include reporting of emissions from gathering lines and boosting
stations. This source category includes: (1) all processing
facilities that fractionate and (2) those that do not fractionate
with throughput of 25 MMscf per day or greater.
Onshore natural gas transmission compression. Onshore
natural gas transmission compression includes any stationary
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
stations may include equipment for liquids separation, natural gas
dehydration, and tanks for the storage of water and hydrocarbon
liquids. Residue (sales) gas compression operated by natural gas
processing facilities are included in the onshore natural gas
processing segment and are excluded from this segment. This source
category also does not include reporting of emissions from gathering
lines and boosting stations--these sources are currently not covered
by subpart W.
Underground natural gas storage. Underground natural
gas storage includes subsurface storage, including depleted gas or
oil reservoirs and salt dome caverns that store 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 compression, dehydration and flow
measurement, and excluding transmission pipelines); and all the
wellheads connected to the compression units located at the facility
that inject natural gas into and remove natural gas from the
underground reservoirs.
Liquefied natural gas (LNG) storage. LNG storage
includes onshore LNG storage vessels located above ground, equipment
for liquefying natural gas, compressors to capture and re-liquefy
boil-off-gas, re-condensers, and vaporization units for re-
gasification of the liquefied natural gas.
LNG import and export facilities. LNG import equipment
includes 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.
Natural gas distribution. Natural gas distribution
includes the distribution pipelines (not interstate transmission
pipelines or intrastate transmission pipelines) and metering and
regulating equipment at city gate stations, and excluding customer
meters, that physically deliver natural gas to end users and is
operated by a Local Distribution Company (LDC) that is regulated as
a separate operating company by a public utility commission or that
is operated as an independent municipally-owned distribution system.
This segment excludes customer meters and infrastructure and
pipelines (both interstate and intrastate) delivering natural gas
directly to major industrial users and ``farm taps'' upstream of the
local distribution company inlet--these sources are not covered by
subpart W.
Facilities from the following segments: (1) Offshore petroleum and
natural gas production, (2) onshore natural gas processing, (3) onshore
natural gas transmission compression, (4) underground natural gas
storage, (5) LNG storage, and (6) LNG import and export equipment, that
meet the applicability criteria in the General Provisions (40 CFR
98.2(a)(2)) and summarized in Section II.C of this preamble must report
GHG emissions. Facilities assessing their applicability in the onshore
petroleum and natural gas production segment (as defined in 40 CFR
98.238), must include only emissions from equipment, as specified in 40
CFR 98.232(c) to determine if they exceed the 25,000 metric ton
CO2e threshold and thus are required to report their GHG
emissions. Facilities assessing their applicability in the onshore
natural gas distribution industry segment (as defined in 40 CFR
98.238), must include only emissions from equipment as specified 40 CFR
98.232(i) to determine if they exceed the 25,000 metric ton
CO2e threshold and thus are required to report their GHG
emissions. For other segments, facilities must assess applicability
based on all source categories for which methods are provided in the
GHG Reporting Program.
GHGs to Report. Facilities must report:
Carbon dioxide (CO2) and methane
(CH4) emissions from equipment leaks and vents.
CO2, CH4, and nitrous oxide
(N2O) from combustion.
CO2, CH4, and nitrous oxide
(N2O) emissions from combustion at flares.
Reporting Threshold. Facilities that contain petroleum and natural
gas systems that meet the requirements of 40 CFR 98.2(a)(2) are to
report GHG emissions under subpart W. For applying the threshold
defined in 40 CFR 98.2(a)(2), an onshore petroleum and natural gas
production facility will consider emissions only from equipment
specified in 40 CFR 98.232(c). For applying the threshold defined in 40
CFR 98.2(a)(2), a natural gas distribution facility shall consider
emissions only from equipment specified in 40 CFR 98.232(i).
GHG Emissions Calculation and Monitoring. The petroleum and natural
gas source category consists of several segments (e.g., onshore
petroleum and natural gas production, natural gas processing). Within
those segments, there are different types of emissions sources, some of
which appear in multiple segments (e.g., pneumatic devices, blowdown
vents, etc.). Subpart W provides methodologies for calculating
emissions from each source type. Although the rule, in some cases,
allows reporters the flexibility to choose from more than one method
for calculating emissions from a specific source type, reporters must
keep record in their monitoring plans as outlined in 40 CFR 98.3(g) of
this chapter. Table 3 of this preamble summarizes those source types
and indicates their applicable segments. Reporters of an industry
segment as defined by 40 CFR 98.230 would report emissions under
subpart W only from the corresponding source types listed for that
particular industry segment as defined in 40 CFR 98.232. For example,
an onshore natural gas transmission compression reporter as defined by
40 CFR 98.230(a)(4) would report emissions under subpart W only for
sources defined in 40 CFR 98.232(e). The text following the table
summarizes the different methodologies reporters must use to monitor
and calculate their GHG emissions from each emissions source.
It is important to note, as detailed in Section II.F of this
preamble, that for specified time periods during the 2011 data
collection year, reporters may use best available monitoring methods
for certain emissions sources in lieu of the methods prescribed for
specific sources below. This is intended to give reporters flexibility
as they revise procedures and contractual arrangements during early
implementation of the rule.
[[Page 74463]]
Table 3--Summary of Source Types in Each Industry Segment
--------------------------------------------------------------------------------------------------------------------------------------------------------
LNG
Natural Natural gas Import
Source type Offshore Onshore gas transmission Underground LNG and Distribution
production production processing compression storage Storage export
equipment
--------------------------------------------------------------------------------------------------------------------------------------------------------
Natural gas pneumatic device venting................. X X X
Natural gas driven pneumatic pump venting............ X
Acid gas removal vent stack.......................... X X
Dehydrator vent stacks............................... X X
Well venting for liquids unloading................... X
Gas well venting during well completions and X
workovers with hydraulic fracturing.................
Gas well venting during well completions and X
workovers without hydraulic fracturing..............
Blowdown vent stacks................................. X X X X
Onshore production storage tanks..................... X
Transmission storage tanks........................... X
Well testing venting and flaring..................... X
Associated gas venting and flaring................... X
Flare stacks......................................... X X
Centrifugal compressor venting....................... X X X X X X
Reciprocating compressor rod packing venting......... X X X X X X
Other emissions from equipment leaks................. X X X X X X X
Population Count and Emissions Factor................ X X X X X
Vented, Equipment Leaks and Flare Emissions X
Identified in BOEMRE GOADS Study....................
Enhanced Oil Recovery hydrocarbon liquids dissolved X
CO2.................................................
Enhanced Oil Recovery injection pump blowdown........ X
Onshore Petroleum and Natural Gas Production and X X
Natural Gas Distribution Combustion Emissions.......
--------------------------------------------------------------------------------------------------------------------------------------------------------
2. Summary of Methodologies for Each Source Type in Table 3 of this
preamble.
Natural gas pneumatic device venting: Calculate
CO2 and CH4 emissions from natural gas
pneumatic devices using component count for each type (i.e.,
continuous high bleed, continuous low bleed, and intermittent bleed)
together with a population emission factor for each type from Tables
W-1A, W-3, and W-4 of subpart W. Onshore petroleum and natural gas
production reporters must complete a total count of pneumatic
devices any time within the first three calendar years. A reporter
must report pneumatic device emissions annually. For any years where
activity data (count of pneumatic devices) is incomplete, use best
available data or engineering estimates to calculate pneumatic
device emissions.
Natural gas driven pneumatic pump venting: Calculate
CO2 and CH4 emissions using component count of
natural gas pneumatic pumps together with a population emission
factor from Table W-1A of subpart W.
Acid gas removal (AGR) vents: Calculate CO2
emissions using one of the following calculation methodologies:
--Use CEMS as specified under subpart C of this section. If CEMS is
not operated or maintained, a CEMS may be installed.
--Use metered flow and volume weighted CO2 content of the
vent stack gas. The approaches available to measure the volume
weighted CO2 content include using a continuous gas
analyzer or sampling the gas quarterly.
--Use metered flow of the inlet natural gas and volume weighted
CO2 content of the natural gas flowing into and out of
the AGR unit. The approaches available to measure the volume
weighted CO2 content include using a continuous gas
analyzer or sampling the gas quarterly.
--Use a process simulator that uses the Peng-Robinson equation of
state and speciates CO2 emissions.
Dehydrator vents. Calculate CH4 and
CO2 emissions using the following calculation
methodologies:
--For glycol dehydrators with a throughput greater than or equal to
0.4 million standard cubic feet per day, use a software program such
as GRI GlyCalc or AspenTech HYSYS[reg] for example, to calculate
emissions. The software program must determine the equilibrium
coefficient using the Peng-Robinson equation of state, speciates
CH4 and CO2 emissions from dehydrators, and
have provisions to include regenerator control devices, a separator
flash tank, stripping gas, and gas injection pump or gas assist
pump.
--For glycol dehydrators with a throughput less than 0.4 million
standard cubic feet per day, use daily flow rate of wet natural gas
together with an emission factor to calculate CO2 and
CH4 emissions. There are separate emission factors for
dehydrator units with a gas assist pump.
--For desiccant dehydrators, calculate the amount of gas vented from
the vessel every time it is depressurized for desiccant replacement.
This involves knowing the dimensions of the dehydrator and percent
of the vessel that is packed with desiccant, and the time between
desiccant refilling.
Well venting for liquids unloading: Calculate
CO2 and CH4 emissions using either of the
following calculation methodologies (the same methodology must be
used for the entire duration of the calendar year).
--Determine the average gas flow for the duration of the liquids
unloading using a meter on the vent line. A new average flow rate
must be calculated every other year starting in the first calendar
year of reporting. Use the total venting time during the year
together with the gas flow rate to determine the gas vented during
liquid unloading.
--Determine the casing dimension, the shut-in pressure, sales flow
rate and hours that the well was left open to the atmosphere to
calculate the volume of gas emitted during liquid unloading.
Gas well venting during well completions and workovers
from hydraulic fracturing: Calculate CO2 and
CH4 emissions using the cumulative vent time during the
year and the flow rate of gas vented, separately for both
completions and workovers. Use either of the following methodologies
to determine the flow rate of the gas.
--Determine the flow rate of vented gas from one well during a well
completion, and also one well workover event, using a meter
installed on the vent line. A flow rate determined from a well
during a well completion can be applied to all wells in
[[Page 74464]]
the same field that undergo a completion. A flow rate determined
from a well during a well workover can be applied to all wells in
the same field that undergo a workover. A field-level emissions
factor must be developed every 2 years starting in the first
calendar year of reporting.
--Measure the pressure before and after the well choke for both one
well during a well completion, and also one well workover event. A
flow rate determined from a well during a well completion can be
applied to all wells in the same field that undergo a completion. A
flow rate determined from a well during a well workover can be
applied to all wells in the same field that undergo a workover. The
flow rate must be determined in the first year of every 2-year
period. Separate equations are provided for sonic and sub-sonic
flow.
Gas well venting during well completions and workovers
without hydraulic fracturing: Calculate CO2 and
CH4 emissions using the cumulative vent time during the
year and average daily gas production for each well.
Blowdown vent stacks. Calculate CH4 and
CO2 emissions from blowdown vent stacks by calculating
the total volume of equipment and vessels blown down between
isolation valves. This includes the volume of all piping, compressor
cases or cylinders, manifolds, suction and discharge bottles or any
other gas-containing volume contained between the isolation valves.
Total physical volume of less than 50 cubic feet between isolation
valves of process vessels, piping, and equipment do not have to be
reported. The total volume contained between isolation valves, which
can be determined using an engineering equation based on best
available data, for each process vessel and the number of times it
was blowndown in the calendar year equals the actual volume of
emissions, which are then converted to GHG volumes at standard
conditions and GHG emissions using the concentration of
CH4 and CO2 in the applicable stream.
Reporters may use the same calculated volumes in subsequent years if
the hardware has not changed. For process vessels blowndown to a
flare, calculate the volume of emissions the same as if they were
not flared, then use that volume as an input parameter in the flare
stacks section to estimate combustion emissions.
Onshore production storage tanks: Calculate
CH4 and CO2 emissions using one of the
following calculation methodologies:
--For tanks with separator throughput greater than or equal to 10
barrels per day, use a software program, such as AspenTECH[reg] or
API 4697 E&P Tank for example, that uses the Peng-Robinson equation
of state, models flashing emissions, and speciates CH4
and CO2 emissions from tanks. The low pressure separator
oil composition and Reid vapor pressure can be determined using the
default values within the software program, or using a
representative sample analysis.
--Alternatively, for tanks with separator throughput greater than or
equal to 10 barrels per day, you may assume all of the
CH4 and CO2 in the low pressure separator oil
is emitted. The low pressure separator oil composition shall be
determined using an appropriate sample analysis, or default oil
compositions in software programs.
--For wells with oil production greater than or equal to 10 barrels
per day that flow directly to a tank without going through a
separator, calculate emissions by using an appropriate sample
analysis and assuming all of the CH4 and CO2
are emitted.
--For separator throughput or wells flowing directly to tanks with
throughput less than 10 barrels per day, use a population emission
factor together with the flow rate.
--Account for occurrences when the separator dump valve is
improperly open and bypassing gas to the tank through the liquid, by
determining the number of hours the dump valve is open and scaling
the emissions upwards using the correction factor. The number of
hours the dump valve is open can be determined using the maintenance
or operations records as follows: (1) Assume that if a dump valve is
found open, that it was open from either the beginning of the
calendar year, or since the most recent maintenance or operations
record confirming proper closure of the dump valve and (2) Assume
that a dump valve is improperly open until there is a maintenance or
operations record showing that the dump valve is closed or to the
end of the calendar year.
Transmission storage tanks. For transmission storage
tanks, once per calendar year reporters must monitor the tank vapor
vent stack using an optical gas imaging instrument, to view the
emissions for 5 minutes. Alternatively, the scrubber dump valves can
be monitored with an acoustic leak detector. If the vent stack emits
continuously over that time period, then the reporter must use
either a meter or an acoustic leak detection device to measure the
flow rate of the vent to determine emissions. This will quantify
tank emissions resulting from malfunctioning scrubber dump valves.
If a tank is vented to a flare, then use the onshore petroleum and
natural gas production storage tanks methodology option 1
(simulation) to estimate the volume and composition of vapors
flared. Then use the flare stacks methodology to estimate the
emissions.
Well testing venting and flaring. Calculate
CH4, CO2, and N2O emissions from
well testing venting and flaring by multiplying available data from
production records on the gas-to-oil ratio for produced hydrocarbon
liquids, by the flow rate (in barrels of oil per day) of the well
being tested, by the number of days in the calendar year the well is
tested. If gas-to-oil ratios are not available, use a sample
analysis to determine gas-to-oil ratios. For the calculated testing
gas volume that is flared, use the method set forth for flare stacks
to estimate the emissions.
Associated gas venting and flaring. Calculate
CH4, CO2, and N2O emissions from
associated gas venting and flaring by multiplying available data
from production records on the gas-to-oil ratio for produced
hydrocarbon liquids, by the volume of liquids produced in the
calendar year. The gas-to-oil ratios can be determined by the use of
a representative gas-to-oil ratio of wells in the same field. If
gas-to-oil ratios are not readily available, use a sample analysis
to determine gas-oil ratios. For the calculated associated gas
volume that is flared, use the method set forth for flare stacks to
estimate the emissions.
Flare stacks. Calculate CH4, CO2,
and N2O emissions from flare stacks by metering or using
engineering estimation to determine the volume of gas sent to the
flare, and the gas composition to then estimate the portion that is
combusted and the portion that is not combusted, using the flare
efficiency. Where methodologies for other sources in subpart W refer
to this methodology in order to estimate flaring emissions, use the
estimated volume of flared gas from those sources as the gas to
flare volume in this methodology, and report those emissions under
those sources. Calculate N2O from flare stacks using the
methodology set forth for in 40 CFR 98.233(z).
Centrifugal compressor venting.
--Calculate CH4 and CO2 emissions from wet
seal oil degassing vents in onshore petroleum and natural gas
production by counting the total population of centrifugal
compressors and multiplying it by the appropriate emission factors.
--Calculate CH4 and CO2 emissions from wet
seal and dry seal centrifugal compressor blowdown vents, wet seal
degassing, and unit isolation valves for wet seal and dry seal
compressors (see Table 4 of this preamble) found in onshore natural
gas processing, onshore natural gas transmission compression,
underground natural gas storage, LNG storage, and LNG import and
export equipment by:
--Measuring venting from blowdown vents when the compressor is found
in the operating mode using a meter.
- Measuring wet seal degassing venting when the compressor is
found in the operating mode using a meter.
--Measuring venting from unit isolation valves when the compressor
is found in not operating, depressurized mode using a meter. If
these sources are vented through a common manifold, you must measure
each vent source separately. Determine average emissions from each
mode of operation by summing the emissions from each source in each
mode and dividing it by the total population measured. The result
will be an emission factor per compressor per hour for each mode of
operation. Multiply each emission factor by the total number of
compressor-hours in each mode of operation. Reporters are not
required to shutdown compressors to conduct measurements. The owner
or operator must schedule an annual measurement of each compressor
and the owner or operator can take the measurement in the mode in
which the compressor is found during the annual measurement.
However, the owner or operator must conduct a measurement of each
compressor in the not operating, depressurized mode at least once
every three calendar years. Please see Compressor Modes and
Threshold, Docket EPA-HQ-OAR-2009-0923.
[[Page 74465]]
Table 4--Summary of Emission Factor Categories for Centrifugal
Compressor Venting
------------------------------------------------------------------------
Operating mode
------------------------------------------
Component Not operating--
Operating depressurized
------------------------------------------------------------------------
Blowdown Vent................ Individual Not Applicable.
Factor.
Wet Seal Oil Degassing Vent.. Individual Not Applicable.
Factor.
Unit Isolation Valve......... Not Applicable. Individual Factor.
------------------------------------------------------------------------
Reciprocating compressor rod packing venting. Calculate
CH4 and CO2 emissions from reciprocating
compressor rod packing venting in onshore petroleum and natural gas
production by counting the total population of reciprocating
compressors and multiplying it by the emission factors provided in
40 CFR 98.233(p)(10). Calculate CH4 and CO2
emissions for reciprocating compressor blowdown valves, rod packing,
and unit isolation valves (see Table 5 of this preamble) from
onshore natural gas processing, onshore natural gas transmission
compression, underground natural gas storage, LNG storage, and LNG
import and export equipment by:
--Measuring venting from blowdown vents when the compressor is found
in operating and standby pressurized modes using a meter.
--Measuring rod packing vents when the compressor is found in
operating and standby pressurized modes using a meter. If there is
not a vent line, a rigorous approach of scanning for all potential
leakage paths for the gas must be used and quantified with a meter,
high volume sampler, or calibrated bag as appropriate.
--Measuring venting from unit isolation valves using a meter when
the compressor is found in not operating, depressurized mode. For
through-valve leakage to open ended vents, such as unit isolation
valves on not operating depressurized compressors, acoustic leak
detection devices may also be used.
If these sources are vented through a common manifold, you must
measure each vent source separately. Determine average emissions
from each mode of operation by summing the emissions from each
source in each mode and dividing it by the total population
measured. The result will be an emission factor per compressor per
hour for each mode of operation. Multiply each emission factor by
the total number of compressor-hours in each mode of operation.
Reporters are not required to shut down compressors to conduct
measurements. The owner or operator must conduct a measurement of
each compressor, and measure the compressor in the mode as it is
found during the annual measurement. However, the owner or operator
must conduct at least one measurement of each compressor in the not
operating, depressurized mode at least one time every 3 calendar
years. Please see ``Compressor Modes and Threshold'' Docket EPA-HQ-
OAR-2009-0923.
Table 5--Summary of Emission Factor Categories for Reciprocating Compressor Venting
----------------------------------------------------------------------------------------------------------------
Operating mode
Component -----------------------------------------------------------------------------
Operating Standby pressurized Not operating--depressurized
----------------------------------------------------------------------------------------------------------------
Blowdown Vent..................... Use measurements in either mode to develop Not Applicable.
combined factor.
----------------------------------------------------------------------------------------------------------------
Rod Packing Seals................. Individual Factor.... Individual Factor.... Not Applicable.
----------------------------------------------------------------------------------------------------------------
Unit Isolation Valve.............. Not Applicable....... Not Applicable....... Individual Factor.
----------------------------------------------------------------------------------------------------------------
Leak detection and leaker factors (onshore natural gas
processing, onshore natural gas transmission compression,
underground natural gas storage, LNG storage, LNG import export,
natural gas distribution). Perform a leak detection survey using one
of the three following methods:
--Use an optical gas imaging instrument. The method must be used for
all sources that cannot be monitored without elevating personnel
more than 2 meters above a support surface.
--Use an infrared laser beam illuminated instrument.
--Use Method 21.
--Multiply the count of each type of leaking component by the
appropriate leaker factors in Tables W-2, W-3, W-4, W-5, W-6, and W-
7 of subpart W. Tubing systems less than 0.5 inch are exempt from
reporting.
--For natural gas distribution, leak detection is required only for
above ground metering and regulating stations (also called ``gate
stations'') at which custody transfer occurs. The leak detection and
monitoring requirements prescribed in subpart W do not include
customer meters. All facilities under this source must conduct at
least one leak survey each calendar year. Multiple leak surveys may
be conducted in order to account for leak repairs. If multiple
surveys are chosen by the owner or operator and performed, each
survey must be facility wide.
--If only one leak survey is conducted in the calendar year, assume
that all leaks found emit for the entire year.
--If multiple leak surveys are conducted, assume that each leak that
is found has been emitting since the last survey; or since the
beginning of the calendar year. Assume that each leak found during
the last leak survey in a calendar year continues to emit until the
end of the calendar year.
Population count and emission factor. Calculate
CH4 and CO2 emissions from the sources listed
in 40 CFR 98.233(r).
--For onshore petroleum and natural gas production, each component
must either be counted individually; or major equipment pieces must
be counted and then the appropriate average component counts should
be applied using Tables W-1B, W-1C, and W-1D of subpart W. The most
recent gas composition that is representative of the field must be
used to determine the percent of the leaked gas that is
CH4 and CO2.
--For underground natural gas storage, the emission factors in Table
W-4 of subpart W must be applied to population counts of components
on storage wellheads.
--For LNG storage, the emission factor for vapor recovery
compressors, must be applied to the total population count.
--For LNG import and export equipment, the emission factor for vapor
recovery compressors must be applied to the total population count.
--For natural gas distribution, all emissions from above ground
custody transfer metering and regulating stations as determined by
leak detection surveys must be totaled and then divided by the total
number of surveyed meter runs to develop an average emission factor
for above grade metering and regulating stations. This average
emission factor will be multiplied by the total number of above
ground metering and regulating stations meter runs at which custody
transfer does not occur to estimate emissions from those stations.
Emission factors in Table W-7 of subpart W will be used to account
for equipment leaks in underground meter and regulation stations,
pipelines, and service lines.
Offshore production. Calculate CO2 and
CH4 emissions from offshore petroleum and
[[Page 74466]]
natural gas production facilities using the methods outlined by
BOEMRE \3\ Gulfwide Emissions Inventory Study, herein after referred
to as ``GOADS.'' Offshore production facilities are not required to
report portable emissions to EPA.
---------------------------------------------------------------------------
\3\ The Bureau of Ocean Energy Management, Regulation, and
Enforcement (BOEMRE) was formerly known as Minerals Management
Service (MMS).
--Offshore production facilities reporting under the BOEMRE GOADS
program must report where available the same annual emissions as
calculated by BOEMRE using activity data submitted by platform
operators in the latest GOADS study calculated by BOEMRE's data base
management system. For the 2011 calendar year, offshore production
facilities currently under the GOADS program must report the latest
published emissions from the GOADS study for platforms in service in
the GOADS study year. In subsequent calendar years when BOEMRE
publishes an updated GOADS study, reporters shall report emissions
based on that latest GOADS study. For each calendar year that does
not overlap with the GOADS publication of a new study, reports for
platforms operating in the current year that were also operating in
the last published GOADS study should be adjusted based on the
operating time for each platform relative to the operating time in
the previous reporting period.
--For offshore production facilities that do not report under the
BOEMRE GOADS program (non-GOADS reporters), monthly activity data
from applicable offshore production facilities must be collected for
the first calendar year in accordance with the latest GOADS program
instructions. Calculation of GHG emissions must be performed using
the latest GOADS program emission factors and methodologies as
outlined in the latest published GOADS study. In subsequent calendar
years, facilities not under GOADS jurisdiction must follow the data
collection cycle as required in the GOADS program by collecting new
monthly activity data, estimating GHG emissions using the latest
GOADS program emission factors and methodologies and report those
emissions to EPA. For each calendar year that does not overlap with
a new GOADS study publication, offshore production facilities not
reporting under the BOEMRE GOADS program must report the last
reported emissions data with emissions adjusted based on the
operating time for each platform relative to operating time in the
previous reporting period. Thus, these facilities will gather data
and estimate updated emissions on the same cycle as facilities
reporting to the GOADS program.
--For either first or subsequent year reporting, platforms either
within or outside of GOADS jurisdiction that were not covered in the
previous GOADS data collection cycle shall collect monthly activity
data from platform sources in accordance with the latest GOADS
program instructions and calculate GHG emissions using the latest
GOADS program emission factors and methodologies.
--If BOEMRE discontinues or delays their GOADS survey by more than 4
years, then offshore production facilities shall collect monthly
activity data every 4 years from platform sources in accordance with
the latest published version of the GOADS program instructions, and
annual GHG emissions shall be calculated using latest GOADS program
emission factors and methodologies.
--Offshore production facilities subject to subpart W must report
stationary combustion emissions under subpart C of part 98.
--All Offshore production facilities, whether out of or under the
jurisdiction of BOEMRE GOADS program are to adhere to the monitoring
and QA/QC requirements in the applicable BOEMRE regulations.
EOR Hydrocarbon liquids dissolved CO2.
Calculate CO2 emissions downstream of storage tanks from
hydrocarbon liquids produced as a result of enhanced oil recovery
operations by conducting annual composition sampling of the produced
hydrocarbon liquids by taking samples downstream of the storage
tank. Use the mass of CO2 from the sample to determine
the mass of CO2 dissolved in hydrocarbons beyond storage
per barrel of produced liquid hydrocarbons.
EOR injection pump blowdown. Calculate CO2
emissions from enhanced oil recovery critical phase CO2
injection pump blowdowns by calculating the volume of gas-containing
structures between isolation valves, including piping. Use
engineering estimates and best available data to determine the
volume of gas-containing structures between isolation valves. The
volumes calculated may be used in subsequent years if the hardware
has not changed. Maintain logs of the number of blowdowns in the
calendar year for each EOR pump. Using an appropriate standard
method published by a consensus-based standards organization or, if
no such standard exists, an industry standard practice, determine
the density of the supercritical EOR injection gas. Calculate
emissions using the number of blowdowns, the volume of the blown
down equipment, the mass fraction of CO2 in the injection
gas, the density of the injection gas, and a conversion factor.
Onshore petroleum and natural gas production and
natural gas distribution combustion emissions. Calculate
CO2, CH4 and N2O combustion
emissions from stationary and portable combustion equipment in
onshore petroleum and natural gas production and stationary
combustion equipment in natural gas distribution using the following
methods:
--If the fuel combusted is listed in Table C-1 of subpart C, or any
blend of the fuels listed, use the Tier 1 methodology of subpart C.
--Following the methodologies in 40 CFR 98.233(z), if the fuel
combusted is field gas or a combination of field gas or process vent
gas and one or more fuels listed in Table C-1 of subpart C, then use
the volume of fuel and the composition of the fuel to calculate
CO2 emissions. If meters are installed on the fuel
stream, the meter must be used to determine the volume of fuel
combusted; otherwise the reporter can estimate that volume by
installing a permanent flow meter or use engineering calculations.
If a continuous gas analyzer is installed on the fuel stream, the
composition reading must be used; otherwise another accepted method
to estimate the composition may be used.
--Emissions from external fuel combustion sources with a rated heat
capacity less than or equal to 5 mmBtu/hour do not have to be
reported. Only activity data (unit count by type of unit) for such
sources is to be reported.
--Calculate N2O emissions from combustion equipment using
emission factors and the fuel volume consumed. The high heat value
of the fuel can be estimated using Table C-1 of subpart C if
possible. If the fuel is field gas or process vent gas, a default
high heat value is provided. If another fuel, not covered by Table
C-1 of subpart C or field gas or process vent gas, is used; then the
appropriate methodology from subpart C to estimate high heat value
must be used.
Data Reporting Requirements. In addition to the information
required to be reported by the General Provisions (40 CFR 98.3(c)),
reporters must submit additional data that are needed for EPA
verification of the reported GHG emissions from petroleum and natural
gas systems. The specific data to be reported are found in 40 CFR part
98, subpart W.
Recordkeeping. In addition to the records required by the General
Provisions (40 CFR 98.3(g)), reporters must keep records of additional
data used to calculate GHG emissions. These records are described in 40
CFR part 98, subpart W.
Definitions. EPA added definitions that are specific to subpart W
to 40 CFR 98.238 to avoid any confusion with the definitions found in
40 CFR 98.6. For compliance with subpart W, the subpart W specific
definitions apply instead of any of the same definitions also found in
subpart A.
We are including a definition of the term ``Offshore'' in 40 CFR
98.238 to fully identify those petroleum and natural gas production
platforms, secondary platforms and associated storage tanks covered by
this rule.
We are also including two distinctive definitions of facility for
onshore petroleum and natural gas production and for natural gas
distribution. Defining a facility in these cases is not as
straightforward as other industry segments covered under subpart W. For
some segments of the industry (e.g., onshore natural gas processing,
onshore natural gas transmission compression, and offshore petroleum
and natural gas production), identifying the facility is clear since
there are physical boundaries and ownership structures
[[Page 74467]]
that lend themselves to identifying the scope of reporting and
responsible reporting entities. However, in onshore petroleum and
natural gas production and natural gas distribution such distinctions
are more challenging. As explained in the April 2010 proposal, EPA
evaluated existing definitions used under current regulations and
determined that it was necessary to provide a unique definition of
facility for each of these two segments in order to ensure that the
reporting delineation is clear, avoid double counting, and ensure
appropriate emissions coverage. For more information please see the
preamble for the April 2010 proposal (75 FR 18608) and the Greenhouse
Gas Emissions from Petroleum and Natural Gas Industry: Background
Technical Support Document (EPA-HQ-OAR-2009-0923).
These definitions are intended only for purposes of subpart W and
are not intended to affect to definition of a facility as it might be
applied in any other context of the Clean Air Act.
First, as proposed in April 2010, the definition of natural gas
distribution facility for this subpart is 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. This facility
definition provides clear reporting delineation because the equipment
that they operate is clearly known, the ownership is clear to one
company, and reporting at this level is consistent with 40 CFR part 98.
In this action, EPA is finalizing this definition for the natural gas
distribution industry segment. This facility definition for natural gas
distribution will result in 90 percent GHG emissions coverage of this
industry segment.
Second, as proposed in April 2010, the definition of an onshore
petroleum and natural gas production facility for this subpart is all
petroleum or natural gas equipment associated with all petroleum or
natural gas production wells and CO2 EOR operations that are
under common ownership or common control including leased, rented, and
contracted activities by an onshore petroleum and natural gas
production owner or operator and that are located in a single
hydrocarbon basin as defined in 40 CFR 98.238. Where a person or entity
owns or operates more than one well in a basin, then all onshore
petroleum and natural gas production equipment associated with all
wells that the person or entity owns or operates in the basin would be
considered one facility. In the April 2010 proposal, EPA evaluated at
least two available industry recognized definitions that identify
hydrocarbon basins: One from the United States Geological Survey (USGS)
and the other from the American Association of Petroleum Geologists.
Basins are mapped to county boundaries only to give a surface
manifestation to the underground geologic boundaries. EPA decided to
use the AAPG geologic definition of basin because it 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. Hence, in this
action, EPA is finalizing the facility definition at the basin level
for the onshore petroleum and natural gas production industry segment
because the operational boundaries and basin demarcations are clearly
defined and are widely known, and reporting at this level would provide
the necessary coverage of GHG emissions to inform policy. In addition,
EPA has clarified its intent by stating that onshore petroleum and
natural gas production equipment associated with all petroleum or
natural gas production wells and CO2 EOR operations continue
to include any leased, rented or contracted activities by the owner or
operator of those wells in that basin. This facility definition for
onshore petroleum and natural gas production will result in 85 percent
GHG emissions coverage of this industry segment.
Finally, in this final action, EPA has replaced the term ``fugitive
emissions'' with ``equipment leaks.'' This change was made to ensure
consistency with the terminology in the Alternative Work Practice to
Detect Leaks from Equipment for 40 CFR parts 60, 63, and 65.
E. Summary of Major Changes and Clarifications Since Proposal
The major changes and clarifications in subpart W since the April
2010 proposal are identified in the following list. For a full
description of the rationale for these and any other significant
changes to 40 CFR part 98, subpart W, see the Mandatory Greenhouse Gas
Reporting Rule: EPA's Response to Public Comments, Subpart W: Petroleum
and Natural Gas Systems. The changes are organized following the
different sections of the subpart W regulatory text.
1. Definition of the Source Category
EPA revised the definition for onshore natural gas
processing and onshore petroleum and natural gas production to exclude
gathering lines and boosting stations from the source category.
EPA revised the definition of onshore petroleum and
natural gas production to include equipment on a well pad or associated
with a well pad, due to the growing industry practice of multi-well
pads, where equipment may serve one well on a pad or several wells on a
pad.
EPA has revised the definition of natural gas processing
to clarify that this industry segment includes (1) all processing
facilities that fractionate and (2) those that do not fractionate with
throughput of 25 MMscf per day or greater.
EPA has revised the definition for the natural gas
processing industry segment by removing the term ``plant'' from the
segment name to ensure consistency with terminology used by other
industry segment definitions.
EPA clarified that meters and regulators in the natural
gas distribution industry segment do not include customer meters.
2. Reporting Threshold
EPA is amending the reporting threshold language in
subpart W to clarify that onshore petroleum and natural gas production
facilities and onshore natural gas distribution facilities must report
emissions only from sources specified in subpart W. This amendment was
necessary to clearly define what emissions sources are to be included
for considering the threshold in determining applicability for these
two industry segments because they each have a different definition of
the term ``facility'' than what is defined in the general provisions of
part 98.
3. GHGs To Report
EPA removed the reporting requirements for produced water
from coal bed methane (CBM) and enhanced oil recovery (EOR) operations.
4. Monitoring, QA/QC, and Calculating Emissions
For industry segments where equipment leak detection is
required (onshore natural gas processing, onshore natural gas
transmission compression, underground natural gas storage, LNG storage
and LNG import and export equipment, and natural gas distribution
facilities) EPA is including the option to use Method 21 and infrared
laser beam illuminated instruments to detect leaks for sources that are
accessible. Inaccessible equipment leaks and vented emissions are still
required to be monitored using an optical gas imaging instrument.
[[Page 74468]]
For applicable industry segments (onshore natural gas
processing, onshore natural gas transmission compression, underground
natural gas storage, LNG storage and LNG import and export equipment),
EPA clarified the monitoring and reporting requirements for centrifugal
and reciprocating compressors. Reporters are required to conduct an
annual measurement of each compressor in the mode in which it is found
at the time of the annual measurement. However, EPA requires reporters
to conduct at least one measurement of each compressor in the not
operating, depressurized mode during every 3-year period. Commenters
suggested to EPA that based on their operational experience, 3 years is
an appropriate maximum time period during which compressors will be
shutdown at least once for routine maintenance, such that operators
would not need to shutdown compressors specifically for the purposes of
monitoring. For more detail, please see EPA-HQ-OAR-2009-0923-1011
excerpt 44. Also see ``Compressor Modes and Threshold'' Docket EPA-HQ-
OAR-2009-0923.
EPA clarified reporting requirements and in some cases
included alternative data collection methodologies for certain sources
to balance burden with data quality and emissions coverage:
--For onshore petroleum and natural gas production, EPA is allowing
the use of major equipment counts and default average counts for
associated components rather than requiring individual counts for all
components to determine populations to which to apply component
emission factors.
--As compressors in onshore petroleum and natural gas production
are small in size, EPA is allowing the use of emission factors for
calculating GHG emissions from centrifugal and reciprocating
compressors in onshore petroleum and natural gas production rather than
conducting an annual measurement of each compressor in the mode in
which it is found.
--EPA is allowing onshore petroleum and natural gas production
reporters to complete a total count of pneumatic devices any time
within the first three calendar years. A reporter must report pneumatic
device emissions annually. For any years where activity data (count of
pneumatic devices) is incomplete, use best available data or
engineering estimates to calculate pneumatic device emissions.
--For collecting gas composition data for produced natural gas, EPA
is allowing reporters to use existing sampling data (e.g., composition
analysis of gas sold) if reporters do not have a continuous gas
composition analyzer already installed.
--EPA is including emission factors for calculating GHG emissions
from the following sources: vented GHG emissions from onshore petroleum
and natural gas production tanks receiving oil from separators or
directly from wells with less than 10 barrels per day throughput;
onshore petroleum and natural gas production and onshore natural gas
processing dehydrators with less than 0.4 million standard cubic feet
per day throughput; vented GHG emissions from all onshore petroleum and
natural gas production pneumatic devices and pneumatic pumps, and
pneumatic devices in onshore natural gas transmission compression
facilities and underground natural gas storage facilities.
--For both the onshore petroleum and natural gas production
industry segment and the natural gas distribution industry segment,
external fuel combustion emissions from portable or stationary
equipment with rated heat capacity less than or equal to 5 mmBtu/hr,
only activity data must be reported.
--Blowdown emissions from equipment vessel chambers totaling less
than 50 cubic feet are not required to be reported.
--For reciprocating and centrifugal compressor measurement
requirements, EPA clarified that the installation of permanent meters
is an option but is not required; temporary meters are acceptable. In
addition, through-valve leakage to open ended vents, such as unit
isolation valves on not operating depressurized compressors and
blowdown valves on pressurized compressors, may be measured using
acoustic leak detection devices.
EPA is allowing Best Available Monitoring Methods for
certain sources and time periods (for more detailed information, refer
to Section II.F of this preamble).
For transmission storage tanks, EPA is allowing reporters
to use an acoustic leak detection device to monitor leakage through
compressor scrubber dump valves into the tank.
5. Applicability
To assist reporters in determining applicability, EPA is planning
to develop screening tools to assist in the determination of which
entities may potentially be required to report under subpart W of 40
CFR part 98.
F. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. EPA received many comments on this subpart covering numerous
topics. EPA's responses to all comments, including those below, can be
found in the comment response document for petroleum and natural gas
systems in Mandatory Greenhouse Gas Reporting Rule: EPA's Response to
Public Comments, Subpart W: Petroleum and Natural Gas Systems.
Additional comments and responses related to cost issues on the
proposed rule can be located in Section III.B.2 of this preamble.
1. Definition of the Source Category
Comment: Numerous commenters objected to the inclusion of gathering
lines and booster stations in the natural gas processing industry
segment definition. Commenters specifically stated that including
gathering lines and booster stations would result in undue burden on
reporters stemming from (1) The additional cost to include gathering
lines and boosting stations that typically are associated with a single
natural gas processing facility, and (2) the numerous complexities and
variations of ownership that currently exist with gathering lines and
boosting stations. One commenter further detailed that there are at
least three different owner/operator variations that exist ranging from
a scenario where a single company owns and/or operates the wells,
gathering lines, and natural gas processing facility, to a scenario
where a single company owns the wells, a second distinct company (or
multiple companies) own the gathering lines, and a third distinct
company may own the natural gas processing facility. The commenter
further explained that these scenarios are further complicated because
the variations in gas flow fluctuate daily due to the need to balance
production demands for natural gas against the capacity of the
gathering lines and the natural gas processing facility.
Finally, a number of commenters requested that the gathering lines
and boosting stations be excluded from the natural gas processing
industry segment definition or be defined as a separate industry
segment.
Response: EPA has decided not to include gathering lines and
boosting stations as an emissions source in subpart W at this time. The
primary reason for excluding gathering lines and boosting stations at
this time is that emissions coverage from gathering lines and boosting
stations within the natural gas processing industry segment requires
further analysis to ensure an effective coverage of emissions from this
source in order to appropriately inform
[[Page 74469]]
future policy decisions. As a result, EPA is continuing to review the
comments received and similar comments raised to ensure an effective
coverage of emissions from this source, and is considering the most
appropriate mechanism for future actions to address the collection of
appropriate data on gathering lines and boosting stations while
minimizing industry burden.
Comment: Several commenters stated that meters and regulators (M&R)
were not clearly defined and could result in the inclusion of customer
meters in the reporting requirements for the natural gas distribution
industry segment.
Response: EPA did not intend to require reporting of GHG emissions
from customer meters in subpart W. In this final action, EPA has
clarified its intent to not require reporting of GHG emissions from
customer meters. The definition of the natural gas distribution
industry segment and the listing of GHGs to report under this industry
segment have been refined to make clear what emissions are to be
reported for this industry segment.
Comment: Commenters noted that many facilities would fall under
more than one industry segment in a calendar year and requested
clarification as to which industry segment such a facility would be
required to report under. In addition some commenters noted that they
have equipment from multiple industry segments located in the same
physical space.
Response: EPA has reviewed these comments and has addressed them.
Please see response to comment EPA-HQ-OAR-2009-0923-1024-14 in the
Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public
Comments.
2. GHGs To Report
Comment: Numerous commenters argued against the reporting of
emissions, specifically combustion emissions, from portable equipment
for the onshore petroleum and natural gas industry segment. Commenters
noted that tracking emissions from portable non-self propelled
equipment would result in heavy burden due to the fact that the
majority of portable equipment are operated by an entity that is
separate from the owner. Further, commenters stated that the reporting
of emissions from portable equipment will only marginally increase
coverage of the proposed rule. Some commenters argued that subpart C
excludes portable equipment from combustion emissions reporting, and
questioned why it was required for subpart W.
Response: EPA disagrees with commenters and has finalized the
reporting requirements for GHG emissions from portable non-self
propelled equipment in subpart W, including emissions from drilling
rigs, dehydrators, compressors, electrical generators, steam boilers,
and heaters with external combustion rated heat capacity above 5 mmBtu/
hour.
In order to manage the burden, the emissions estimation methods for
portable equipment require the use of existing data, for the most part.
Moreover, the allowance of Best Available Monitoring Methods (described
later in this preamble) would provide reporters additional time to
modify contractual arrangements with service providers. The decision to
retain the reporting requirements for portable equipment GHG emissions
was based on EPA's analysis of the contribution to GHG emissions, both
combustion and process, from portable equipment in onshore production.
It is estimated that portable non self-propelled equipment is
responsible for over 45 percent of total emissions from onshore
petroleum and natural gas production. Please see ``Portable Combustion
Emissions'' Docket EPA-HQ-OAR-2009-0923 for the complete analysis.
While EPA is not excluding portable equipment, for certain emissions
sources, EPA agrees with comments that alternative methodologies are
appropriate and viable for collecting these data. EPA has conducted an
extensive review of the emissions contribution relative to reporting
burden and modified the final rule to simplify the requirements for
external combustion equipment that fall below a rated heat capacity of
5 mmBtu/hr for the onshore petroleum and natural gas industry segment
and the natural gas distribution industry segment. Please see
``Portable Combustion Emissions'' Docket EPA-HQ-OAR-2009-0923 and
``Equipment Threshold for Small Combustion Units'' Docket EPA-HQ-OAR-
2009-0923 for the analysis. Equipment that fall below the specified
mmBtu level for the applicable industry segments would not have to
conduct monitoring for combustion emissions, and would only be required
to report activity data which would be total number of external fuel
combustion units with a rated heat capacity of equal to or less than 5
mmBtu/hr by type of unit.
3. Monitoring, QA/QC, and Calculating Emissions
Comment: EPA received numerous comments on the use of the optical
gas imaging instrument for detecting GHG emissions from equipment
leaks. Several commenters expressed support for the use of optical gas
imaging instruments prescribed in the rule, stating that using this
equipment would result in cost savings to industry as it would reduce
burden and time by quick survey of all emissions sources at one time.
In addition, several commenters specifically requested that EPA also
allow the use of organic vapor analyzers (OVA), toxic vapor analyzers
(TVA) and infrared laser beam illuminated instruments as alternative
technologies to the optical gas imaging instruments proposed for
emissions detection.
Response: EPA has evaluated alternative methods for detection of
equipment leaks for their viability and comparative accuracy to the
optical gas imaging instrument in the proposed rule. EPA agrees with
commenters and has modified the final rule to include the options to
use OVA/TVA devices or infrared laser beam illuminated instruments for
leak detection for all emissions sources across all industry segments
with the exception of inaccessible sources. EPA is still requiring that
reporters use optical gas imaging instruments for inaccessible sources
due to potential safety and cost concerns related to leak detection of
sources that cannot be physically accessed from a fixed, supportive
surface with a hand held leak detection device such as OVA/TVA, or
which do not have a reflective background for an IR laser detection
device. While EPA has determined that the methodologies in this rule
are viable and appropriate for collecting this type of GHG data, EPA
will continue to evaluate other potential methods for detecting methane
emissions in the petroleum and natural gas sector.\4\
---------------------------------------------------------------------------
\4\ While this activity is in a nascent stage, EPA is conducting
ongoing research on experimental mobile monitoring methods to locate
and quantify equipment leak emissions from petroleum and natural gas
fields. In addition to increasing our knowledge about emissions from
equipment leaks from petroleum and natural gas fields, if this
proves to be a robust approach, it could be one viable alternative
for measuring emissions and EPA would consider a rulemaking to add
it as an acceptable method to this subpart.
---------------------------------------------------------------------------
Comment: Numerous commenters disagreed with EPA's assessment of the
feasibility of conducting one measurement for each reciprocating or
centrifugal compressor in each of the operational modes (operating,
standby pressurized, not operating/depressurized) that would occur
during a calendar year. Commenters specifically stated that common
industry practice is to have a compressor in operating mode for several
years before it is taken offline for routine maintenance and servicing,
thereby taking a compressor offline for the sole purpose of measurement
as
[[Page 74470]]
prescribed in the rule would result in undue burden to the industry and
result in additional GHG emissions.
Response: EPA did not intend for compressors to be taken offline in
order for reporters to collect the data required under subpart W and
has clarified the final rule to allow reporters to conduct an annual
measurement of each compressor in the mode as it exists at the time the
annual measurement is taken. EPA requires the development of emission
factors from these measurements that reporters must apply appropriately
to all compressors for the total time each compressor is operated in
each mode. However, EPA requires that each compressor must be measured
at least once during every 3-year period in the ``not operating and
depressurized'' mode without blind flanges in place. Blind flanges are
flat plates inserted between flanges on a valve or piping connection to
assure absolute isolation of the equipment from process fluids, and
hence, compromise through valve leakage measurement. Isolation valve
leakage through the compressor blowdown vent, when the compressor is in
the not operating and depressurized mode, must be measured before blind
flanges are installed.
Commenters suggested to EPA that based on their operational
experience, 3 years is an appropriate maximum operational time period
during which compressors will be shutdown for maintenance at least
once, and therefore operators would not need to shutdown compressors
specifically for the purposes of monitoring to gather measurements at
this frequency. Accordingly, EPA is requiring reporters to schedule the
measurement of compressors in the not operating and depressurized mode
at least once during each consecutive 3-year time period.
Comment: EPA received a broad range of comments that the
methodologies for calculating GHG emissions in subpart W for specific
emissions sources were too burdensome. Some commenters stated that
quarterly sampling of produced natural gas to determine gas composition
was overly burdensome and not necessary since produced gas composition
does not change significantly from one quarter to the next. Other
commenters suggested that requiring component counts for calculating
equipment leaks for the onshore petroleum and natural gas industry
segment was too onerous and time intensive since a reporter may have
hundreds of wells across a large geographical area, and they currently
do not have an inventory of all the components, such as valves,
connectors and flanges, associated with their equipment. Several
commenters stated that the number of tanks and dehydrators in the
onshore petroleum and natural gas industry segment would be very
burdensome to estimate emissions from using engineering equations. For
example each tank would be required to obtain a sample analysis of low
pressure separator oil for doing the engineering calculations. Finally,
several commenters stated that the number of pneumatic devices and
pneumatic pumps would require extensive time to determine the
manufacturer model of each device in their facilities, and then
estimate emissions based on manufacturer data.
Lastly, commenters noted that compressor emissions measurement and
compressor throughput flow was too burdensome, since many compressors
would require the installation of expensive permanent meters.
Response: EPA considered all of these comments, and performed
extensive evaluation of the methodologies for calculating GHG emissions
for each emissions source under each industry segment. EPA compared
alternative methodologies that, when performed, would result in reduced
burden on industry while maintaining the necessary quality of data to
inform policy. Please see ``Alternative Methodologies'' Docket EPA-HQ-
OAR-2009-0923 for a full report of the analysis. Specifically, certain
methodologies for specific emissions sources allowed for alternative
methods that would reduce burden and maintain data quality. As a
result, EPA determined that the following rule modifications would
reduce burden while sustaining the necessary quality of data:
Individual component counts and population based
emissions factors for onshore petroleum and natural gas production
have been replaced with major equipment counts and default average
component counts per primary equipment. Identification of primary
equipment (dehydrators, compressors, heaters, etc.) will result in
significantly less burden to reporters than counting each component
(valve, flange, open-ended line, etc.).
Quarterly sampling of gas composition has been replaced
with using your most recent representative gas analysis. Most
onshore petroleum and natural gas producers would have this
information already for transaction processing.
For onshore petroleum and natural gas production, for
separators and well production with less than 10 barrels per day
throughput and glycol dehydrators with less than 0.4 million
standard cubic feet per day throughput, reporters will use emissions
factors to determine emissions. Blowdown emissions from equipment
vessel chambers totaling less than 50 cubic feet are not required to
be reported. For more information, the following documents;
``Equipment Threshold for Tanks,'' ``Equipment Threshold for
Dehydrators,'' and ``Equipment Threshold for Blowdowns'' can be
found in docket EPA-HQ-OAR-2009-0923.
For all pneumatic devices and pneumatic pumps in
onshore petroleum and natural gas production and all pneumatic
devices in onshore natural gas transmission compression facilities
and underground natural gas storage facilities, reporters will
utilize component counts and population emissions factors instead of
engineering estimates. Note that onshore petroleum and natural gas
production reporters must complete a total count of pneumatic
devices any time within the first three calendar years. A reporter
must report pneumatic device emissions annually. For any years where
activity data (count of pneumatic devices) is incomplete, use best
available data or engineering estimates to calculate pneumatic
device emissions.
The final rule has clarified that emissions from
centrifugal and reciprocating compressors do not require the
installation of a permanent flow meter; use of a portable meter and
port are acceptable. In addition, through-valve leakage to open
ended vents, such as unit isolation valves on not operating
depressurized compressors and blowdown valves on pressurized
compressors, may be measured using acoustic leak detection devices.
In addition, compressor throughput flow meters are not required;
estimates of compressor flow will be sufficient for EPA's
requirements.
4. Data Reporting Requirements
Comment: Numerous commenters stated that there would be
insufficient time, leak detection and measurement equipment, or service
providers available to fully comply with subpart W reporting
requirements. In particular, numerous onshore petroleum and natural gas
production commenters expressed concern with the ability to gather data
from geographically dispersed emissions sources starting January 1,
2011. Also numerous commenters from the onshore natural gas processing
and onshore natural gas transmission industry segments expressed their
concern with their ability to comply with monitoring requirements, such
as installing necessary measurement ports or meters for measurement.
Response: As described below, EPA determined that for specified
emissions sources for certain industry segments, some reporters may
need more time to comply with the monitoring and QA/QC requirements of
this subpart than by January 1, 2011. EPA carefully considered each
source and the reporting compliance requirements and determined for
which monitoring requirements it is appropriate to allow the use of
best available monitoring
[[Page 74471]]
methods, for how long the use of best available monitoring methods will
be applicable, and under what circumstances these methods are
reasonable. EPA has extensively detailed when and how reporters may use
best available monitoring methods specified in the following sections
and in 40 CFR 98.234(f) of the rule.
Best available monitoring methods are any of the following methods:
monitoring methods currently used by the facility that do not meet the
specifications of a relevant subpart; supplier data; engineering
calculations; or other company records. Best available monitoring
methods are available for three specific instances as well as providing
a catch-all provision in the case of unanticipated issues or
circumstances. In each category EPA determined the affected sources,
reporting requirements and the time period necessary for owners or
operators to implement the requirements of the rule. In all cases, the
owner or operator must use the equations and calculation methods set
forth in 40 CFR 98.233, but may use best available monitoring methods
to estimate the parameters in the equations as specified in the
following sections.
EPA also carefully considered the timing for allowing application
of best available monitoring methods. EPA determined the time duration
for specified sources for which reporting entities may apply best
available monitoring methods without a petition, and those for which
reporting entities must request the use of best available monitoring
methods. If the reporter anticipates the potential need for best
available monitoring for sources for which they need to petition EPA
and the situation is unresolved at the time of the deadline, reporters
should submit written notice of this potential situation to EPA by the
specified deadline for requests to be considered. EPA reserves the
right to review petitions after the deadline but will only consider and
approve late petitions which demonstrate extreme or unusual
circumstances. Based on EPA's experience in implementing the 2009 final
rule and those BAMM provisions, EPA made the source specific
determinations for subpart W as outlined in the following sections.
Well-Related Emissions Reporting. Subpart W requires the monitoring
of well-related emissions sources for which the owner or operator must
collect data during the actual event (for example, a well completion or
workover conducted on a specific day in January 2011) and for which it
may not be possible to collect or reproduce data after the event is
over. EPA recognizes that a significant portion of well-drilling
activities are conducted by third-party service providers and that in
these cases, owners or operators may need to coordinate and possibly
modify contracts, leases or other arrangements with service providers
in order to gather data and thus it may not be possible for owners or
operators to begin gathering well-related emissions data as of January
1, 2011. For these sources EPA will allow the use of best available
monitoring methods through June 30, 2011 to allow reporters sufficient
time to meet the requirements of the rule.
Eligible Sources. There are three well-related sources
for which subpart W requires emissions data collection at the time
of the emissions event rather than at the reporter's discretion
during a calendar year and for which use of best available
monitoring methods will be allowed. These sources are as follows:
--Gas well workovers using hydraulic fracture in paragraph 40 CFR
98.233(g)
--Gas well completions using hydraulic fracture in paragraph 40 CFR
98.233(g)
--Well testing/flaring in paragraph 40 CFR 98.233(l)
Reporting Requirements. For the eligible sources
listed, an owner or operator must use the equations prescribed in 40
CFR 98.233(g) and 40 CFR 98.233(l) but may use best available
monitoring methods to estimate any of the parameters. Best available
monitoring methods may be:
--Monitoring methods currently used by the facility that do not meet
the specifications of this subpart.
--Supplier data.
--Engineering calculations.
--Other owner or operator records.
Authorization to Use Best Available Monitoring Methods.
All owners or operators may use best available monitoring methods
for these sources between January 1, 2011 and June 30, 2011. Owners
or operators do not have to submit a request to EPA for the initial
six months. Owners or operators will have from the time this rule is
signed by the Administrator until June 30, 2011 to make any
necessary arrangements with service providers and other relevant
organizations in order for the owner or operator to gather all
necessary data to comply with subpart W. As this is approximately
eight months time, starting July 1, 2011, EPA expects that owners or
operators will have made arrangements or modified contracts with
service providers, such as drilling companies, as necessary to
comply fully with subpart W for these sources.
Requests for Extension in 2011. If additional time is
necessary beyond June 30, 2011, an owner or operator must request an
extension for use of best available monitoring methods by April 30,
2011. In order to receive an extension for a time period between
July 1, 2011 and December 31, 2011, owners and operators must
provide the following information for each source covered under 40
CFR 98.232(c)(6), 40 CFR 98.232(c)(8), and 40 CFR 98.232(c)(12):
--A list of the specific emissions sources within the owner or
operator's facility for which the owner or operator is requesting an
extension of best available monitoring methods.
--A description of the specific requirements in 40 CFR 98.233(g) and
40 CFR 98.233(l) that the owner or operator cannot meet in 2011,
including a detailed explanation as to why the requirements cannot
be met.
--Supporting documentation such as the date of and copies of
correspondence to service providers or other relevant entities
whereby the owner or operator clearly requests that said service
providers or other relevant entities provide required data.
--Demonstrate that it is not possible to obtain the necessary
information, service or hardware which may include providing
correspondence from specific service providers or other relevant
entities to the owner or operator, whereby the service provider
states that it is unable to provide the necessary data or services
requested by the owner or operator that would enable the owner or
operator to comply with subpart W reporting requirements.
--A detailed explanation and supporting documentation of how and
when the owner or operator will receive the required data and/or
services to comply with subpart W reporting requirements.
The Administrator reserves the right to require additional
documentation.
EPA does not anticipate extending the use of best available
monitoring methods beyond 2011 as approximately fourteen months will
have passed since the Administrator's signature; however, under extreme
and unique circumstances, which include safety, or a requirement being
technically infeasible or counter to other local, State or Federal
regulations, EPA may consider granting a further extension. Any such
request must be received by September 30, 2011. The owner or operator
must provide the following information in a request for the use of best
available monitoring methods beyond 2011 for sources covered under 40
CFR 98.232(c)(6), 40 CFR 98.232(c)(8), and 40 CFR 98.232(c)(12) for
beyond 2011:
--A list of the specific emissions sources within the owner or
operator's facility for which the owner or operator is requesting an
extension of best available monitoring methods.
--A description of the specific requirements in 40 CFR 98.233(g) and 40
CFR 98.233(l) that the owner or operator cannot meet, including a
detailed explanation as to why the requirements cannot be met.
--Detailed outline of the unique circumstances necessitating an
extension, including specific data collection issues that do not meet
safety regulations, technical
[[Page 74472]]
infeasibility or specific laws or regulations that conflict with data
collection for 40 CFR 98.232(c)(6), 40 CFR 98.232(c)(8), and 40 CFR
98.232(c)(12). The owner or operator must consider all data collection
options as outlined in the rule for a specific emissions source before
claiming that a specific safety, technical or legal barrier exists. For
example, if measuring an open-ended line on a rooftop does not meet
safety regulations, companies must consider the use of portable meters
using a port at ground-level.
--A detailed explanation and supporting documentation of how and when
the owner or operator will receive the required data and/or services to
comply with subpart W reporting requirements in the future.
The Administrator reserves the right to require additional
documentation.
It is the responsibility of the owner or operator to meet
the reporting requirements of this rule. Accordingly, it is up to the
owner or operator to best determine how they can obtain the necessary
data to timely and fully comply.
Stipulated Activity Data Collection. Several sources require the
collection of activity data such as cumulative run time or a cumulative
throughput volume to a piece of equipment starting January 1, 2011.
Based on industry comments, EPA recognizes that it may not be feasible
for an owner or operator to gather these data across all of their
facilities as data collection in some cases must begin on January 1,
2011. EPA has decided to allow reporters to use best available
monitoring methods to estimate specific activity parameters used in the
equations and methods outlined in 40 CFR 98.233 for the first six
months of 2011. EPA will allow the use of best available monitoring
methods for emissions sources for which the owner or operator must
collect activity data sometime between January 1, 2011 and June 30,
2011 and the owner or operator cannot reproduce or replicate the data
after this time period. As owners or operators will have approximately
eight months from the time of Administrator signature to June 30, 2011
to develop systems to collect these data, EPA does not anticipate
approving best available monitoring methods for collecting activity
data after June 30, 2011.
Eligible Sources. Owners and operators may use best
available monitoring methods only for the sources listed below:
--Cumulative hours of venting, days, or times of operation in
paragraphs Sec. 98.233(e), (f), (g), (h), (l), (o), (p), (q), (r)
of 40 CFR part 98.
--Number of blowdowns, completions, workovers, or other events in
paragraphs Sec. 98.233(f), (g), (h), (i), and (w) of 40 CFR part
98.
--Cumulative volume produced, volume input or output, or volume of
fuel used in paragraphs Sec. 98.233(d), (e), (j), (k), (l), (m),
(n), (x), (y), and (z) of 40 CFR part 98.
Reporting Requirements. For the sources eligible for
best available monitoring methods applicable to stipulated activity
data,, owners and operators must use the equations prescribed in 40
CFR 98.233 but may use best available monitoring methods to estimate
the stipulated activity parameters. Best available monitoring
methods are:
--Monitoring methods currently used by the facility that do not meet
the specifications of this subpart.
--Supplier data.
--Engineering calculations.
--Other owner or operator records.
Authorization to Use Best Available Monitoring Methods.
All owners and operators may use best available monitoring methods
for the sources eligible for best available monitoring methods
applicable to stipulated activity data between January 1, 2011 and
June 30, 2011. Owners or operators do not have to submit a request
to EPA for the initial six months. As owners and operators will have
approximately eight months from Administrator signature to June 30,
2011, to prepare for the data collection requirements for the
eligible sources, EPA expects that all owners or operators should
have had adequate time to comply with the data collection
requirements outlined in this subpart and therefore not need the use
of best available monitoring methods for this information after June
30, 2011.
Requests for Extension in 2011. Only under extreme
circumstances, which include safety, or a requirement being
technically infeasible or counter to other local, State, or Federal
regulations, will EPA consider extending the use of best available
monitoring methods for the collection of activity data through the
end of 2011.
Owners or operators may submit a request for an
extension through the end of 2011. These requests must be received
by April 30, 2011 and include the following:
--A list of specific source categories and parameters for which the
owner or operator is seeking use of best available monitoring
methods.
--A description of the specific requirements in paragraphs Sec.
98.233(e), (f), (g), (h), (i), (j), (k), (l), (m), (n), (o), (p),
(q), (r), (w), (x), (y), and (z) of 40 CFR Part 98 that the owner or
operator cannot meet, including a detailed explanation as to why the
requirements cannot be met.
--Detailed outline of the unique circumstances necessitating an
extension, including data collection methods that do not meet safety
regulations, technical infeasibility or specific laws or regulations
that conflict with the specific sources in this section of the
preamble. The owner or operator must consider all data collection
options as outlined in the rule for a specific emissions source
before claiming that a specific safety, technical or legal barrier
exists.
--A detailed explanation and supporting documentation of how and
when the owner or operator will receive, for example, the services
or equipment to comply with subpart W reporting requirements.
The Administrator reserves the right to require additional
documentation.
Requests for Extension beyond 2011. As approximately
fourteen months will have passed between the Administrator's signature
and December 31, 2011, EPA does not anticipate approving requests for
best available monitoring methods beyond 2011 for applicable stipulated
activity data sources eligible for best available monitoring methods;
however, under extreme and unique circumstances, which include safety,
a requirement being technically infeasible or counter to other local,
State, or Federal regulations, it may consider granting a further
extension. Any such requests for extensions beyond 2011 must be
received by September 30, 2011 and include the following:
--A list of specific source categories and parameters for which the
owner or operator is seeking use of best available monitoring methods.
--A description of the specific requirements in paragraphs Sec.
98.233(e), (f), (g), (h), (i), (j), (k), (l), (m), (n), (o), (p), (q),
(r), (w), (x), (y), and (z) of 40 CFR Part 98 that the owner or
operator cannot meet, including a detailed explanation as to why the
requirements cannot be met.
--Detailed outline of the unique circumstances necessitating an
extension, including data collection methodologies that do not meet
safety regulations, technical infeasibility or specific laws or
regulations that conflict with sources outlined in this section of the
preamble. The owner or operator must consider all data collection
options as outlined in the rule for a specific emissions source before
claiming that a specific safety, technical or legal barrier exists.
--A detailed explanation and supporting documentation of how and when
the owner or operator will receive, for example, the services or
equipment to comply with subpart W reporting requirements.
The Administrator reserves the right to require additional
documentation.
Acquisition and implementation of leak detection and monitoring
equipment or services. Based on industry comments, EPA understands that
it may not be feasible for all owners or operators to acquire required
leak detection and/or measurement equipment or hire a service provider
in time to conduct the activities necessary
[[Page 74473]]
to complete leak detection and measurement requirements under subpart W
within the 2011 calendar year. EPA will consider the use of best
available monitoring methods for sources requiring leak detection and/
or measurement based on evidence provided by the owners or operators
demonstrating that they have made all efforts but cannot obtain the
necessary equipment or services in time to complete subpart W reporting
in 2011.
Eligible Sources. With application approval from the
Administrator, owners and operators may use best available
monitoring methods only for the sources listed below:
--Reciprocating compressor rod packing vents for facilities
downstream of onshore petroleum and natural gas production (i.e.,
onshore natural gas processing, onshore natural gas transmission
compression, underground natural gas storage, LNG storage, and LNG
import and export equipment) in 40 CFR 98.233(p).
--Centrifugal compressor wet seal oil degassing venting for
facilities downstream of petroleum and natural gas production in 40
CFR 98.233(o).
--Acid gas removal vents in 40 CFR 98.233(d).
--Equipment leaks in facilities downstream of onshore petroleum and
natural gas production in 40 CFR 98.233(q).
--Transmission storage tanks in 40 CFR 98.233(k).
Reporting Requirements. For the sources eligible for
best available monitoring methods applicable to acquisition and
implementation of leak detection and monitoring equipment or
services,, if approved by the Administrator, the owner or operator
may use best available monitoring methods to estimate emissions and/
or the number of leaking components, and any throughputs, volumes,
or maintenance records in place of the required monitoring methods
outlined for parameters in 40 CFR 98.233. These best available
monitoring methods are:
--Monitoring methods currently used by the facility that do not meet
the specifications of this subpart.
--Supplier data.
--Engineering calculations.
--Other owner or operator records.
Authorization to Use Best Available Monitoring Methods.
Because leak detection and/or measurement surveys are one-time
actions that can be conducted at any time during the year, by April
30, 2011, reporters must submit an application seeking approval for
the use of best available monitoring methods. Upon approval by the
Administrator, EPA may allow the use of best available monitoring
methods for up to the entire 2011 calendar year. An owner or
operator must submit this request no later than April 30, 2011 and
include, at a minimum:
--A list of specific source categories and parameters for which the
owner or operator is seeking use of best available monitoring
methods.
--A description of the specific requirements in 40 CFR 98.233(d),
98.233(k), 98.233(o), 98.233(p), and 98.233(q) that the owner or
operator cannot meet and an explanation of how the owner or operator
has diligently tried and why it cannot meet the requirements.
--Certification that the owner or operator does not already own
relevant detection or measurement equipment.
--Documentation which demonstrates that the owner or operator made
all reasonable efforts to obtain the service necessary to comply
with subpart W reporting requirements in 2011, including evidence of
specific service or equipment providers contacted and why services
could not be obtained during 2011. EPA recognizes that some owners
or operators may choose to conduct their own leak detection and
measurement activities and therefore purchase equipment for that
purpose. It is the owner or operator's responsibility to purchase
all necessary equipment in time to meet 2011 reporting requirements.
If relevant equipment vendors cannot deliver hardware in time for an
owner or operator to meet subpart W requirements, the owner or
operator must attempt to use outside service providers, prior to
seeking a request for best available monitoring methodology
extension.
--A detailed explanation and supporting documentation of how and
when the owner or operator will receive the services or equipment to
comply with subpart W reporting requirements in 2012.
The Administrator reserves the right to require additional
documentation.
Requests for Extension. As owners and operators will have
had approximately fourteen months since the date of the Administrator's
signature and December 31, 2011, EPA does not anticipate extending best
available monitoring methods beyond 2011; however, under extreme and
unique circumstances, which include safety, or a requirement being
technically infeasible or counter to other local, State, or Federal
regulations, EPA may consider granting a further extension. Any such
request for extensions beyond 2011 must be received by September 30,
2011 and include the following:
--A list of specific source categories and parameters for which the
owner or operator is seeking use of best available monitoring methods.
--A description of the specific requirements in 40 CFR 98.233(d),
98.233(k), 98.233(o), 98.233(p), and 98.233(q) for which extension is
being requested and of the unique circumstances necessitating an
extension, including specific data collection methodologies that do not
meet safety regulations, technical infeasibility or specific laws or
regulations that conflict with sources outlined in this section of the
preamble. The owner or operator must consider all data collection
options as outlined in the rule for a specific emissions source before
claiming that a specific safety, technical or legal barrier exists.
--Detailed explanation and supporting documentation of how and when the
owner or operator will receive the services or equipment to comply with
subpart W reporting requirements.
The Administrator reserves the right to require additional
documentation.
Unique or Extreme Circumstances
Requests for 2011: Emissions sources not covered under the
previous three categories of BAMM are under operational control of the
owner or operator, require one time data collection at any point during
the calendar year and do not require leak detection or measurement
equipment. For these reasons, for the sources not covered under the
previous three categories of BAMM, EPA does not anticipate the need for
best available monitoring methods; however, EPA will review all
requests submitted by April 30, 2011 and consider approval of the use
of best available monitoring methods for 2011 under unique and extreme
circumstances, which include safety, or requirement being technically
infeasible or counter to other local, State, or Federal regulations.
Requests for the use of best available monitoring methods for sources
not covered under the previous three categories of BAMM must include:
--A list of specific source categories and parameters for which the
owner or operator is seeking use of best available monitoring methods.
--Detailed outline of the unique circumstances necessitating an
extension, which must include data collection methodologies that do not
meet safety regulations, technical infeasibility or specific laws or
regulations that conflict with specific sources for which owners or
operators are requesting best available monitoring methods. The owner
or operator must consider all data collection options as outlined in
the rule for a specific emissions source before claiming that a
specific safety, technical or legal barrier exists.
--A detailed explanation and supporting documentation of how and when
the owner or operator will receive the services or equipment to comply
with subpart W reporting requirements in 2012.
The Administrator reserves the right to require additional
documentation.
Requests beyond 2011: For sources not covered in the
previous three categories of BAMM, EPA does not anticipate the need for
best available monitoring methods beyond 2011;
[[Page 74474]]
however, EPA will review such requests submitted by September 30, 2011
and consider approval of the use of best available monitoring methods
for 2012 under unique and extreme circumstances, which include safety,
or a requirement being technically infeasible or counter to other
local, State, or Federal regulations. Requests for the use of best
available monitoring methods for sources not covered in the previous
three categories of BAMM, must include:
--A list of specific source categories and parameters for which the
owner or operator is seeking use of best available monitoring methods.
--Detailed outline of the unique circumstances necessitating an
extension, which must include data collection methodologies that do not
meet safety regulations, technical infeasibility or specific laws or
regulations that conflict with specific sources for which owners or
operators are requesting best available monitoring methods. The owner
or operator must consider all data collection options as outlined in
the rule for a specific emissions source before claiming that a
specific safety, technical or legal barrier exists.
--A detailed explanation and supporting documentation of how and when
the owner or operator will receive the services or equipment to comply
with subpart W reporting requirements.
The Administrator reserves the right to require additional
documentation.
5. Legal Authority
Comment: Several commenters asserted that EPA is over-reaching its
CAA 114 authority. These commenters specifically stated that CAA
section 114 does not authorize EPA to require indefinite and sweeping
monitoring, recordkeeping, and reporting from the facilities covered by
proposed subpart W. On the other hand, several commenters asserted that
the proposal was within EPA's authority under the CAA.
Response: As explained in Section I.C. of this preamble, Section
I.C and Q of the 2009 final Part 98 preamble (74 FR 56260), and the
document Mandatory Greenhouse Gas Reporting Rule: EPA's Response to
Public Comments, Volume 9, Legal Issues (EPA-HQ-OAR-2008-0508), EPA is
promulgating subpart W under its existing CAA authority provided in CAA
section 114. EPA disagrees with the commenters that it does not have
statutory authority to require monitoring, reporting and recordkeeping
from facilities in the petroleum and natural gas systems source
category. The Administrator may gather information under CAA section
114, as long as that information is for purposes of carrying out any
provision of the CAA. For example, CAA section 103 authorizes EPA to
establish a national research and development program, including non-
regulatory approaches and technologies, for the prevention and control
of air pollution, including GHGs. The data collected under this rule
will also inform EPA's implementation of CAA section 103(g) regarding
improvement in sector based non-regulatory strategies and technologies
for preventing or reducing air pollutants. For more information about
EPA's legal authority please see the related sections and documents in
the preamble for subpart W.
6. Designated Representative
Comment: Several commenters stated that EPA lacked the authority to
require facilities to collect data on equipment and activities that may
be operated or provided by a third party service provider and then
require a designated representative to certify those emissions data.
Other commenters supported the inclusion of emissions data from
equipment operated by third party service providers by stating that
these emissions are critical to ensuring that facilities with different
operational structures have equitable coverage in a reporting program
and that a complete profile of emissions from the production sector is
obtained.
Response: As explained in Section V of the preamble of the 2009
final part 98 (74 FR 56355), all reporters must select a designated
representative (DR) who is responsible for certifying, signing, and
submitting all submissions to EPA. This provision provides flexibility
to the owners and operators to choose any individual, employee or non-
employee, to represent them, while ensuring EPA has one accountable
point of contact. As explained in the preamble to the final part 98,
the high level of public interest in the data collected, as well as its
importance to future policy, warrants establishment of a high standard
for data quality and consistency and high level of accountability for
reported data. The DR provisions and certification requirements help
ensure the standard for high quality data and consistency is met. The
DR provisions are crafted similarly to the provisions of the Acid Rain
Program (ARP), 40 CFR part 72 and EPA has found that this approach
provides a high degree of both data quality and consistency and
accountability.
Similar comments were made about the data coming from multiple
owners and operators and the concerns about the certification of those
data upon promulgation of the ARP and the 2009 final GHG reporting rule
to which we responded, and for which responses are summarized. We have
attempted to provide maximum flexibility while ensuring accountability.
For integrity of the program, one representative of the owners and
operators must report for important reasons. Doing so ensures the
accountability of owners or operators by, inter alia, reducing the
likelihood of inconsistent submissions by a facility. Interposing
another person or party between the facility and the Agency would
dilute the DR's responsibility and in effect create multiple DRs for
the facility. Additionally, leaving the ultimate responsibility of
submission with the designated representative has the salutary effect
of clarifying that the DR should be aware of all submissions and should
inquire of the persons with personal knowledge of the information in
those submissions. The DR has the flexibility to delegate duties, such
as the preparation of submissions, but retains the ultimate
responsibility to sign and certify all submissions. (See, 58 FR 3590,
3598, January 11, 1993.)
Furthermore, while the DR or his delegatee may need to acquire
necessary reporting information from a third party, the DR must make
the appropriate inquiries and certification when reporting; ultimate
responsibility rests and must necessarily rest on him or her. The DR
may provide in contracts, leases, or other agreements with third
parties that true, accurate, and correct reporting information must be
provided to the DR in a timely fashion. If the third party fails to
provide timely, true, accurate, or correct information to the DR, then
the DR has recourse contractually, or otherwise, on the third party.
Finally, in recognition of their potential need to adjust contracts,
leases, or agreements accordingly, additional flexibility has been
provided in the rule to allow facilities to utilize best available
monitoring methods for a limited period. For more information, see
Section V of the preamble to the 2009 final Part 98 (74 FR 56260) and
the document Mandatory Greenhouse Gas Reporting Rule: EPA's Response to
Public Comments, Volume 11, Designated Representative and Data
Collection, Reporting, Management and Dissemination (EPA-HQ-OAR-2008-
0508).
7. Applicability
Comment: Multiple commenters requested that EPA develop a set of
[[Page 74475]]
screening tools to assist in the determination of which entities would
be required to report under subpart W of 40 CFR part 98.
Response: Similar to what EPA has already provided for other
subparts of the Greenhouse Gas Reporting Program to help reporters
assess the applicability of the Greenhouse Gas Reporting Program \5\ to
their facilities, EPA plans to develop voluntary screening tools for
the petroleum and natural gas source category. EPA anticipates that
such tools would be based on easily determined inputs such as major
equipment or operational counts. While the tools would be designed to
provide help to potential reporters for complying with the rule,
compliance with all Federal, State, and local laws and regulations
remain the sole responsibility of each facility owner or operator
subject to those laws and regulations. The tools would be a guide to
determine those facilities that are clearly well below the reporting
threshold, those clearly above, and those close to the threshold who
will need to collect further data to make a proper determination.
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\5\ http://www.epa.gov/climatechange/emissions/GHG-calculator/index.html.
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III. Economic Impacts of the Rule
This section of the preamble summarizes the costs and economic
impacts of the final subpart W rulemaking, including the estimated
costs and benefits of subpart W, and the estimated economic impacts on
affected facilities, including estimated impacts on small entities.
Complete details of the economic impacts of the final subpart W rule
can be found in the Economic Impact Analysis (EIA) in the rulemaking
docket (EPA-HQ-OAR-2009-0923).
This section also contains a brief summary of major comments and
responses on the economic impacts of the rule. EPA received a number of
comments on the estimated compliance costs as well as other comments
covering a variety of topics. Responses to significant comments can be
found in Mandatory Greenhouse Gas Reporting Program: EPA's Response to
Public Comments, Cost and Economic Impacts of the Rule, Docket EPA-HQ-
OAR-2008-0508.
A. How were compliance costs estimated?
1. Summary of Method Used To Estimate Compliance Costs of the Final
Rule
EPA estimated costs for each affected petroleum and natural gas
industry facility to comply with subpart W. These estimates capture the
costs associated with monitoring and reporting both equipment leaks and
vented emissions and incremental combustion-related emissions.\6\ EPA
based the estimates on the number of labor hours to perform specific
activities, the cost of labor, and the cost of monitoring equipment.
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\6\ Reporting entities that equal or exceed the subpart W
threshold for equipment leak and vented emissions must report
combustion emissions under subpart C, except for onshore production
and LDCs, which must report combustion emissions under subpart W.
Incremental combustion emissions refer to those from entities that
did not trigger the subpart C threshold in the absence of subpart W.
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The costs of complying with the rule will vary from one petroleum
and gas industry segment and facility to another, depending on factors
such as the types of emissions, the number of affected sources at the
facility and existing maintenance practices, monitoring, recordkeeping,
and reporting activities at the facility. The costs include
expenditures related to monitoring, recording, and reporting process
emissions and, as relevant, emissions from stationary combustion.
Staff activities and associated labor costs may also vary over
time. In particular, start-up activities, such as the installation of
ports for compressors to allow for spot measurements, result in notably
higher costs in the first year. Costs would also vary over time when
site-specific emissions factors are developed every 2 or 3 years. Thus,
EPA developed cost estimates for year one, which include start-up and
first-time reporting, and for subsequent year reporting.
EPA estimated annual costs in 2006 dollars using the 2006
population of emitting sources. In addition, the agency estimated costs
on a per entity basis and weighted them by the number of entities
affected at the 25,000 metric tons CO2e threshold.
To develop compliance cost estimates, EPA gathered existing data
from EPA studies and publications, industry trade associations and
publicly available data sources (e.g., labor rates from the Bureau of
Labor Statistics) to characterize the processes, sources, segments,
facilities, and companies/entities affected. EPA also considered cost
data submitted in public comments on the proposed rule.
Next, 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 data that are already being collected for
reasons not associated with the rule (to allow only the incremental
costs to be estimated).
Labor Costs. The costs of complying with and administering this
rule include time of managers, and of technical, operational and
administrative staff in the private sector. Staff hours were estimated
for activities, including:
Developing a plan: Reporting entity management, legal,
and technical staff hours to determine applicability of the rule,
organize training on rule requirements, identify staffing
assignments, train staff, and schedule activities as required below.
Setting up records: Technical and field staff hours to
develop data collection sheets and analytical model equations or
linkages to input data into software programs.
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.
Recordkeeping: 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 report it to EPA through electronic systems.
Estimates of labor hours were based on economic analyses 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. See the Economic
Impact Analysis for the Mandatory Reporting of Greenhouse Gas Emissions
Under Subpart W Final Rule (EPA-HQ-OAR-2009-0923) for a detailed
discussion about the engineering analysis used to develop these
estimates. In addition, 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.
EPA monetized the labor hours using wage rates from the Bureau of
Labor Statistics (BLS). The agency also adjusted the wage rates to
account for overhead.
[[Page 74476]]
Equipment Costs. Equipment costs include both the initial purchase
price of monitoring equipment and installation cost. 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 cost 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 5-year cost recovery period at a rate of seven percent. Not all
segments require monitoring equipment capital expenditures but those
that do are clearly documented in the Economic Impact Analysis.
Incremental Combustion Costs. EPA estimated the costs to monitor
and report incremental combustion emissions, which are combustion-
related emissions from entities that did not trigger the subpart C
threshold in the absence of subpart W. As discussed earlier in this
section, reporting entities that equal or exceed the subpart W
threshold must report combustion emissions following the methods under
subpart C, except for onshore production entities that consume field
gas or process vent gas and LDCs, which must report combustion
emissions following the methods under subpart W.
For purposes of cost estimation, EPA determined that under the
final rule, entities that need to report incremental combustion-related
emissions, as previously defined, would likely use either the Tier 1
calculation methodology as set forth in subpart C or the calculation
methodology as set forth in subpart W (40 CFR 98.233(z)). EPA
determined that the entities reporting incremental emissions under
subpart C would likely not meet the requirements for Tier 2 or higher
methods. However, as these entities will be reporting combustion
emissions under subpart C (except onshore production and LDCs), if a
facility did meet the requirements for a tier other than Tier 1, the
facility would have to use the required method, as specified in subpart
C.
Given that the combustion methodology in 40 CFR 98.233(z) is
similar to the Tier 1 calculation methodology, EPA estimated the costs
to monitor and report incremental combustion-related emissions based on
the approach used under 40 CFR part 98, subpart C.\7\ Specifically, EPA
applied the Tier 1 calculation methodology to estimate the costs to
monitor combustion emissions that became subject to reporting as a
result of this final action. The Tier 1 approach bases estimates on a
fuel-specific default CO2 emission factor, a default high
heating value of the fuel, and the annual fuel consumption from company
records.
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\7\ 40 CFR part 98 uses the IPCC Tier concept to estimate
combustions emissions (74 FR 56260, October 30, 2009). See EPA-HQ-
OAR-2008-0508-0004, U.S. EPA, Technical Support Document for
Stationary Fuel Combustion Emissions: Proposed Rule for Mandatory
Reporting of Greenhouse Gases, January 30, 2009, for more
information about the IPCC Tier methodology (pgs 10-15).
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EPA based its conclusion that entities would likely report
incremental combustion emissions using the Tier 1 method on three
considerations for applicability of the Tier 2 calculation methodology
and higher, as specified in subpart C, to the petroleum and natural gas
industry: (1) Availability of high heating values (HHVs) for the fuels
combusted at the frequency required by the Tier 2 calculation
methodology, (2) the maximum rated heat capacity of the equipment, and
(3) the type of fuel being combusted. First, in order to be allowed to
use a Tier 2 analysis, units must have a rated heat capacity less than
or equal to 250 mmBtu/hr, combust a fuel found in Table C-1 of subpart
C, and sample the HHV of the fuel consumed at the required frequency in
40 CFR 98.34(a). It was determined that this minimum required sampling
frequency is not currently carried out at these smaller units and
therefore these units would not be required to use Tier 2 methodology.
These units will generally follow Tier 1 methodology.
Second, Tier 3 and Tier 4 calculation methodologies generally apply
to equipment with a maximum rated heat capacity greater than 250 mmBtu/
hr. A 250 mmBtu/hr rating means that the emissions from that individual
unit alone will be greater than 25,000 metric tons CO2e;
these emissions would be subject to reporting under subpart C even in
the absence of subpart W and therefore would not fall in the category
of incremental combustion emissions considered in this analysis.
Third, the predominant fuels used in the petroleum and natural gas
industry are produced natural gas, pipeline quality natural gas,
distillate fuel, and any products recovered from equipment leaks and
vents. The use of produced natural gas is predominant in onshore
petroleum and natural gas production. Under the final rule for subpart
W, reporters in this segment are allowed to use methods similar to Tier
1 for all combustion emissions sources that use produced natural gas.
In the remaining segments, equipment using produced natural gas or
products recovered from equipment leaks and vents are normally required
to use Tier 2 methodology or higher. However, as described previously,
if the unit has a rated heat capacity less than or equal to 250 mmBtu/
hr, then the unit probably does not currently receive HHV at the
required frequency for a Tier 2 analysis and could use a Tier 1
analysis instead. If the unit has a maximum rated heat capacity greater
than 250 mmBtu/hr, then as just noted, emissions from a unit of this
size would already be subject to reporting under subpart C and would
not be included in the incremental combustion emissions category
considered in this analysis. In sum, the use of Tier 1 methodology for
incremental combustion is a reasonable assumption for costing the
subpart W rule.
Reporting Determination Costs. Facilities will have to estimate
their emissions to determine whether they exceed the reporting
threshold. The costs for making a reporting determination includes
primarily the use of screening tools, which EPA plans to develop. The
costs also account for cases in which preliminary monitoring is also
required to make a reporting determination.
2. Summary of Comments and Responses
EPA received many comments on the method used to estimate the
rule's compliance costs. Nearly all of these comments focused on both
the methodology and the resulting cost estimates. Therefore, a summary
of these comments and EPA's response is presented in the next section
of this preamble, Section III.B.2, What are the costs of the rule? For
the detailed responses to all comments received, see Mandatory
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments,
Subpart W: Petroleum and Natural Gas Systems (EPA-HQ-OAR-2009-0923).
B. What are the costs of the rule?
1. Summary of Costs
Table 6 of this preamble presents for each segment the total costs
and costs per ton in the first year and subsequent years as well as the
annualized costs. EPA estimates that the total private sector cost in
the first year is about $62 million and about $19 million for
subsequent years; the annualized cost over a 20-year time period is
about $21 million (3 percent discount rate) and $22 million (7 percent
discount rate) (2006$). Of these costs, EPA estimates
[[Page 74477]]
roughly $40 million to report process emissions in the first year and
about $15 million in subsequent years. In addition, EPA estimates
approximately $3 million to report incremental combustion related
emissions in both the first year and in the subsequent years.
The reporting threshold determines the number of entities required
to report GHG emissions and hence the costs of the rule. The number of
entities excluded increases with higher thresholds. Table 7a and Table
7b of this preamble provide the cost-effectiveness analysis for various
thresholds examined. Two metrics are used to evaluate the cost-
effectiveness of the emissions threshold. The first is the average cost
per metric ton of emissions reported ($/metric ton CO2e).
The second metric for evaluating the threshold option is the
incremental cost per metric ton of emissions reported. The incremental
cost is calculated as the additional (incremental) cost per metric ton
using 25,000 metric tons CO2 equivalent as the baseline. For
more information about the first year capital costs (unamortized),
project lifetime and the amortized (annualized) costs for each
petroleum and gas industry segment please refer to Section 4 of the
Economic Impact Analysis for the final subpart W.
Table 6--National Cost Estimates for Petroleum and Natural Gas Systems
[2006$] \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
First year Subsequent year
---------------------------------------------------------------------------- Annualized cost Annualized cost
Segment National cost Cost ($/metric National cost Cost ($/metric (3%) \2\ (7%) \3\
($million) ton) ($million) ton) ($million) ($million)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Processing............................ 8.13 0.26 2.10 0.07 2.43 2.57
Transmission.......................... 16.87 0.40 6.49 0.15 7.02 7.26
Underground Storage................... 2.73 0.35 1.02 0.13 1.10 1.14
LNG Storage........................... 0.70 0.41 0.26 0.15 0.28 0.29
LNG import/export..................... 0.14 0.44 0.03 0.09 0.04 0.04
LDC................................... 3.31 0.15 1.35 0.06 1.47 1.52
Onshore Production.................... 26.58 0.12 7.54 0.03 8.61 9.05
Offshore Production................... 3.33 0.65 0.24 0.05 0.42 0.49
-----------------------------------------------------------------------------------------------------------------
Total (8 Segments)................ 61.78 0.18 19.01 0.06 21.36 22.34
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Includes determination costs for non-reporters. These estimates are conservative and should be viewed as an upper-bound because the determination
costs were applied at the facility-level rather than the company-level. For example, for offshore production, determination costs were applied to each
of the approximately 3,000 platforms in the Gulf of Mexico rather than the 86 operators in that region. See the memo, ``Estimates of Determination
Costs,'' in the docket for complete details and additional determination cost estimates (EPA-HQ-OAR-2009-0923).
\2\ The cost to report annualized over 20 years at 3 percent (see additional details in section 5 of the EIA for the final rule).
\3\ The cost to report annualized over 20 years at 7 percent (see additional details in section 5 of the EIA for the final rule).
Table 7A--Threshold Cost-Effectiveness Analysis
[First Year, 2006$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Percentage of
Facilities Downstream total Average Incremental
Threshold (metric tons CO2e) required to Total costs \1\ emissions downstream reporting cost ($/Mt)
report (million 2006$) reported emissions cost ($/Mt) \1,2\
(MtCO2e/year) reported \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000............................................... 12,622 $148.67 391 99% $0.38 $1.62
10,000.............................................. 4,400 79.01 362 91% 0.22 0.69
25,000.............................................. 2,786 61.78 337 85% 0.18 0.00
100,000............................................. 1,062 44.32 273 69% 0.16 (0.27)
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Includes determination costs for non-reporters. The upper-bound first-year determination cost estimates for each threshold are as follows: 1,000
metric tons CO2e = $12.3 million; 10,000 metric tons CO2e = $17.4 million; 25,000 metric tons CO2e = $18.4 million; and 100,000 metric tons CO2e =
$19.3 million. As noted in previous table, these estimates are conservative. See the memo, ``Estimates of Determination Costs,'' in the docket for
complete details and additional determination cost estimates (EPA-HQ-OAR-2009-0923).
\2\ Cost per metric ton relative to the selected option (25,000 MT threshold).
Table 7B--Threshold Cost-Effectiveness Analysis
[Subsequent Year, 2006$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Percentage of
Facilities Downstream total Average Incremental
Threshold (metric tons CO2e) required to Total costs \1\ emissions downstream reporting cost ($/
report (million $2006) reported emissions cost ($/Mt) Mt)\1, 2\
(MtCO2e/year) reported \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000............................................... 12,622 $73.44 391 99% $0.19 $1.02
10,000.............................................. 4,400 30.51 362 91% 0.08 0.46
25,000.............................................. 2,786 19.01 337 85% 0.06 0.00
[[Page 74478]]
100,000............................................. 1,062 9.77 273 69% 0.04 (0.14)
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Includes determination costs for non-reporters. The upper-bound determination costs in subsequent years for each threshold are as follows: 1,000
metric tons CO2e = $1.8 million; 10,000 metric tons CO2e = $1.0 million; 25,000 metric tons CO2e = $0.6 million; and 100,000 metric tons CO2e = $0.2
million. As noted in previous table, these estimates are conservative. See the memo, ``Estimates of Determination Costs,'' in the docket for complete
details and additional determination cost estimates (EPA-HQ-OAR-2009-0923).
\2\ Cost per metric ton relative to the selected option (25,000 MT threshold).
2. Summary of Comments and Responses
Overview. EPA received extensive comments on the methodology and
cost data presented in the Economic Impact Analysis for the proposed
subpart W (EPA-HQ-OAR-2009-0923-0020). The comments can be sorted into
two major categories: (1) Comments on the costs for facilities to make
a reporting determination, and (2) comments on cost estimates of labor
and equipment for certain industry segments to monitor and report
emissions.
Reporting Determination. Commenters stated that EPA's analysis
underestimated the true compliance burden by omitting the costs for
facilities to make a reporting determination--i.e., estimate annual
emissions to determine whether they meet the reporting threshold. These
commenters recommended that EPA account for reporting determination
costs incurred by both facilities that report as well as non-reporters,
i.e., those that monitor emissions but do not meet the reporting
threshold. As discussed in Section II.F.6 of this preamble, the
commenters also recommended that EPA develop screening tools to reduce
the burden for facilities to make a reporting determination.
EPA agrees with commenters that the EIA would better reflect the
rule's total economic burden by including all reporting determination
costs. While EPA's compliance cost estimates accounted for the
reporting determination burden in the proposal, it did not include the
determination burden for non-reporters. Therefore, EPA has estimated
the burden for reporting determinations made by non-reporters and
included it in the EIA for the final rule. EPA based this estimate on
the assumption that non-reporters will use a screening tool, which EPA
intends to provide to facilitate reporting determinations. The
estimated total cost for all non-reporters to make a reporting
determination is about $18.4 million, which accounts for use of the
screening tool and, if required, the cost to conduct further screening;
Section 4 of the EIA provides a complete discussion of the basis for
this estimate.\8\ EPA expects use of the screening tool to minimize
burden by allowing facilities to enter basic activity data, such as
well count and drilling activity, into the tool to roughly assess
whether they meet the threshold. Facilities for which the tool
estimates emissions well below the threshold will generally not need to
conduct further screening. Facilities for which the tool estimates
emissions near the threshold will generally conduct additional
screening, and this is reflected in the cost estimates.
---------------------------------------------------------------------------
\8\ These estimates are conservative and should be viewed as an
upper-bound because the determination costs were applied at the
facility-level rather than the company-level. For example, for
offshore production, determination costs were applied to each of the
approximately 3,000 platforms in the Gulf of Mexico rather than the
86 operators in that region. See the memo, ``Estimates of
Determination Costs,'' in the docket for complete details and
additional determination cost estimates (EPA-HQ-OAR-2009-0923).
---------------------------------------------------------------------------
Labor and Equipment Costs. Many commenters disagreed with EPA's
cost estimates in particular segments and presented alternative
estimates that in some cases differed from the agency's estimates by
orders of magnitude. Many of the comments suggested that EPA's
estimates of labor costs (e.g., number of labor hours required to
collect field data, to use equipment and engineering analysis systems
to measure emissions, and to manage the emissions data) and equipment
costs (e.g., purchase of flow meters) were too low.
In development of this rule and in response to comments, EPA
collected and evaluated cost data from multiple sources, closely
reviewed the input received through public comments, and weighed the
analysis prepared against this input. EPA also carefully weighed the
burden of incrementally more comprehensive methods of measuring and
calculating emissions against the increase in coverage and accuracy,
and in some cases revised or clarified the measurement and calculation
requirements. EPA has thus adjusted both the rule requirements and its
cost estimates in response to comments, and concludes that its
methodology and final cost estimates appropriately account for the
compliance burden under this final rule. EPA determined that the
commenters' alternative estimates are much higher than the agency's
because of assumptions and interpretations that were either
inconsistent with EPA's original intent (and which EPA has now
clarified) or requirements that have been revised; in some cases, the
alternative estimates were also based on higher-cost, optional
monitoring methods.
EPA summarizes below the key assumptions, revisions,
misinterpretations, and use of higher-cost, optional methods and the
resulting costs estimates that differed most from EPA's estimates.
These comments were concentrated in three industry segments: (1)
Onshore production, (2) natural gas processing, and (3) natural gas
distribution segments.
3. Onshore Production
Comment: Commenters stated that EPA's estimated compliance costs
for the onshore petroleum and natural gas production segment were too
low. Overall, the commenters concluded that EPA should reassess the
analysis of entities covered by the rule, the assumptions underlying
the cost estimates, and reduce the monitoring and reporting burden.
One commenter provided detailed, alternative cost estimates and
concluded that costs could be as high as $1.8 billion for the onshore
production segment in the first year, which is notably higher than
EPA's proposal estimate of $30.4 million for this segment. The
commenter made various assumptions that differed from EPA's analysis
and accounted for the difference in the cost estimates. One
[[Page 74479]]
source of the difference stemmed from the estimate of the number of
sources in the onshore production segment subject to monitoring.
Specifically, the commenter assumed that because the proposed rule
would cover about 80 percent of emissions from the petroleum and gas
industry, approximately 80 percent of the sites and equipment at each
onshore production facility would be subject to the rule. The commenter
therefore concluded that the rule would cover 80 percent of the 823,000
wells in the nation, or about 667,000 wells, which exceeds EPA's
estimated coverage of about 467,000 wells, plus sources at non-well
sites.\9\ In particular, the commenter said that counting components to
estimate emissions from equipment leaks would be onerous.
---------------------------------------------------------------------------
\9\ Commenter estimated 823,000 wells based on a ``US Energy
Information Administration's 2008 report,'' but did not provide any
other citation information.
---------------------------------------------------------------------------
Additional differences in the commenter's and EPA's estimates
resulted from differences in the assumptions about labor wages and time
spent sampling. For example, the commenter presented a breakdown of the
labor and equipment costs, such as labor wages and time spent on
sampling activities. Sampling activities accounted for a notable
fraction of the commenter's estimates. For example, the commenter
estimated costs for sampling activity to determine the composition of
produced natural gas and low pressure separator oil and to analyze all
tanks for hydrocarbon liquids and produced water.
In addition, data management software constituted a substantial
fraction of the commenter's total cost estimate. The commenter stated
that individual reporters would spend between $100,000 and $850,000 for
data management software, which totals to approximately $123 million to
$1 billion for the entire segment.
EPA has carefully reviewed these comments and disagrees that the
true costs will be substantially higher than those estimated by the
agency.
First, EPA disagrees with the commenter's estimate of the number of
sources subject to reporting because it incorrectly assumed that the
proposed rule covered 80 percent of all wells in the United States. The
commenter's assumption that each reporter would need to monitor 80
percent of its wells in order to report about 80 percent of its
emissions implies that the type and quantity of emissions from each
well are identical. This assumption, which resulted in much more labor
and complex monitoring than required under the proposal, is incorrect.
The quantity and type of emissions from wells are variable; in fact, it
is not necessary to monitor 80 percent of wells to account for 80
percent of emissions and neither the proposed nor final rules would
require such a large percentage of wells to be covered. Because the
final rule tends to target those wells that have the higher emissions,
based on its threshold analysis, EPA estimates that approximately 60
percent of the wells are subject to the monitoring requirements, and
that these wells will account for about 85 percent of total GHG
emissions from this segment.
EPA conducted the threshold analysis using actual data available
through the commercial database from HPDI LLC, which collects these
data primarily from individual petroleum and natural gas producing
States that require petroleum and natural gas producing companies to
report field data. The HPDI database includes operator well count. In
most cases, HPDI provides data for each well on the production of
petroleum and natural gas by operator and basin; some data are listed
by property, which is a collection of wells. EPA developed a reasonable
estimate of the emissions per well by apportioning the national
emissions from each emissions source type to each of the wells based on
the contribution of petroleum and natural gas production from each well
to the national total. This analysis suggests that approximately 60
percent of the wells are owned or operated by entities that would
trigger the reporting threshold, not 80 percent.
The commenter's analysis of the onshore production burden also
incorrectly assumed that the rule required all onshore production
reporters to spend up to $1 billion on data management software. EPA
disagrees with this assumption. EPA notes that the rule does not
require reporters to purchase data collection software. It is at the
reporters' discretion to do so.
Although the commenter did not provide any information about the
software represented in its analysis (except for cost), a system in the
price range assumed by the commenter is usually customized to
accommodate data needs that extend far beyond the scope of this rule.
For example, such systems are typically tailored to an individual
facility and used to simultaneously manage, among other things,
criteria pollutants under the CAA, water discharge and permit data
under the Clean Water Act, employee accident and injury reporting under
Occupational Safety and Health Administration requirements, and onsite
hazardous and non-hazardous solid waste information for the Resource
Conservation and Recovery Act. In contrast, even the largest of
reporters under this final action will be able to use standard
spreadsheets or databases to collect the emissions data and perform
calculations at a facility level. Spreadsheet software can store and
manipulate tens of thousands of data points, and database software can
store hundreds of thousands of data points. In short, spreadsheet and
database software systems are capable of managing far more data than
will be necessary for even the largest onshore production reporter
under subpart W. Accordingly, EPA accounted for data management costs
by factoring in estimates of labor to set up spreadsheets and other
archiving and recordkeeping activities, as well as equipment costs like
file cabinets and external hard drives; see the EIA for a complete
discussion.
Another assumption contributing to the commenters' high cost
estimates concerned the extent of sampling required. For example,
commenters assumed that reporters would need to sample produced natural
gas. EPA disagrees in part because it expects reporters to already have
this information and would therefore not need to sample. In particular,
producers conduct composition analysis of produced natural gas in order
to pay royalties and taxes; they could use these data to estimate the
percentage of GHGs instead of analyzing additional samples.
The commenters also assumed that sampling would be required for
tanks and dehydrators, which resulted in cost estimates significantly
higher than EPA's. Although not explicitly stated in the proposed
subpart W, EPA did not intend for reporters to sample either the low
pressure separator oil associated with tanks or natural gas going to
dehydrators. Therefore, EPA has clarified the final rule to allow
reporters that use the engineering modeling software to rely on the
software's default values.
In addition, commenters also assumed that produced water and
hydrocarbon liquids produced from all reporting wells in the country
would have to be sampled to determine and report CO2
content; this assumption resulted in a large sampling cost. However,
EPA never intended for reporters to sample produced water and
hydrocarbon liquids from all wells but instead targeted EOR operations.
Therefore, EPA clarified in this final action that the sampling
requirement for hydrocarbon liquids applies only to EOR operations; EPA
also clarified in the final rule that
[[Page 74480]]
reporting from produced water emissions sources is not required.
Finally, in response to comments about the costs to count all
components to determine equipment leaks, EPA has revised the rule to
require reporters to count only major equipment (see Section II.E of
this preamble). EPA expects this revision to reduce the reporters'
burden because in many cases they already have an inventory of the
major equipment at each well site.
For the detailed responses to all of the comments received about
the costs for onshore production, see Mandatory Greenhouse Gas
Reporting Rule: EPA's Response to Public Comments, Subpart W: Petroleum
and Natural Gas Systems (EPA-HQ-OAR-2009-0923).
4. Natural Gas Processing
Comment: Commenters stated that EPA's estimated compliance costs
for the natural gas processing segment were too low. They recommended
that EPA reassess the costs for the processing segment and simplify the
reporting requirements. In particular, one commenter estimated
compliance costs at $4.5 billion for the processing segment. Of the
$4.5 billion, the commenter attributed $3.9 billion to monitoring
activities at gathering lines and boosting stations. The commenter
attributed the remainder of its estimate to processing facilities.
Response: Based on its thorough review of the comments, EPA
determined that the commenter's estimates for processing facilities
were higher in part because it made assumptions that were inconsistent
with EPA's intent. Specifically, it assumed higher-cost, optional
monitoring methods for processing facilities in its analysis. However,
EPA agrees with the commenter that the agency's analysis partly
underestimated the costs at processing facilities to place meters on
acid gas removal units. Likewise, EPA agrees that the agency's analysis
did not accurately account for the compliance costs for gathering lines
and boosting stations in the processing segment.
In the case of processing facilities, the commenter assumed that
the rule would require reporters to install permanent flow meters, at
an assumed cost of $100,000 per meter, to measure emissions from
compressor venting. However, the rule does not require this and allows
installation of a port for using a temporary insertion flow meter for
an annual one-time estimate of vented emissions. Temporary flow meters
are a significantly cheaper option than permanent meters. Based on
current market data, EPA estimated approximately $1,000 for each
installation of a temporary meter port for reciprocating compressors;
about $5,000 for centrifugal compressors; and about $800 in capital
costs for a reporter's hotwire anemometer.\10\ Reporters will only need
to purchase one hotwire anemometer per facility; the hotwire anemometer
can be used to measure the flow rate at multiple compressors at the
facility.
---------------------------------------------------------------------------
\10\ For example, see Global Water Instrumentation Inc., at
http://www.globalw.com/products/407119.html.
---------------------------------------------------------------------------
In addition, EPA considered and responded to the commenter's
assumption about the burden to install permanent outflow meters at acid
gas removal (AGR) vents. EPA incorrectly assumed that outlet meters
were already installed at most sites. Specifically, EPA determined upon
further analysis that the flow rates at the inlet and outlet streams
for an acid gas removal unit are roughly similar. EPA therefore
adjusted the calculation method in the final rule to allow the use of
flow rate at the inlet or outlet, where available, based on its
assumption that the outlet flow is the same as the inlet flow. In
addition, if equipment to measure the flow rate, such as CEMS or a
meter on the vent stack of the acid gas removal unit, is not available,
the final rule allows reporters to use engineering estimates of flow
rate of natural gas into the AGR. These revised requirements are
reflected in the cost analysis in the final EIA.
Finally, EPA used data about the number of gathering lines and
boosting stations presented by the commenter as a basis to modify the
rule requirements. EPA agrees that its EIA for the proposed rule did
not accurately reflect the number of gathering lines and boosting
stations that would have been subject to the rule. EPA has dropped the
requirement for reporting on gathering lines and boosting stations from
the final rule, so these costs are not included in the analysis.
Instead, EPA will continue to evaluate options for obtaining emissions
data from gathering lines and boosting stations in a way that maximizes
data quality while balancing industry burden; see Section II.F.1 of
this preamble for further discussion.
5. Natural Gas Distribution
Comment: Commenters stated that EPA's estimated compliance costs
for the natural gas distribution segment were too low by orders of
magnitude. For example, one commenter estimated approximately $11.3
billion for all reporters in the natural gas distribution segment to
comply with the rule. A large fraction of this estimate was based on
the commenter's assumption that the leak detection requirements applied
to customer meters, i.e., industrial, commercial, and residential
meters. The commenter did not, however, provide adequate information
about the basis for the remainder of its cost estimate. In particular,
the commenter stated that in addition to the costs of using an optical
gas imaging instrument, each LDC would spend on average about $41
million annually to comply with the rule, but did not specify any
compliance activities that accounted for the $41 million.
Response: EPA has carefully reviewed these comments and disagrees
that the agency's cost estimates should be orders of magnitude higher.
EPA has determined that commenters' interpretations of the proposed
rule were inconsistent with the Agency's intent and this likely
accounted for the discrepancies between the estimates.
EPA disagrees with the commenter's cost estimate because it is
based on the assumption that customer meters are subject to leak
detection requirements. The commenter assumed that the proposed rule
required leak detection and emissions estimates for all customer
meters, i.e., industrial, commercial, and residential meters; the
commenter estimated reporters would spend approximately $5.4 billion to
monitor these meters. EPA never intended to require reporting for
customer meters, which would involve a major cost and have minimal
effect on the quality of emissions estimates. EPA has therefore
clarified the final rule to note that sources subject to reporting in
the natural gas distribution segment do not include customer meters for
natural gas.
In addition, EPA has responded to the commenter's recommendation to
reduce the compliance costs by simplifying the requirements for optical
gas imaging instrument equipment, e.g., allowing alternatives to
infrared cameras in some situations. As discussed previously in Section
II.E of this preamble, this final action provides more flexibility and
further reduces the compliance cost by allowing facilities to use
alternative leak detection equipment.
The commenter did not identify the monitoring activities and
assumptions underlying its estimate of $5.9 billion to comply with leak
detection requirements. The commenter noted that it obtained the
estimate from an informal survey of its members but did not provide
sufficient information or documentation substantiating what was
included in this estimate. Because EPA has accounted for the two
primary issues raised by the commenter (monitoring of customer meters
and allowable leak detection equipment),
[[Page 74481]]
EPA did not change its cost estimate to reflect the much higher costs
estimated by the commenter.
C. What are the economic impacts of the rule?
1. Summary of Economic Impacts
EPA prepared an economic impact analysis to evaluate the impacts of
the rule on affected small and large reporting entities.
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.\11\ The national costs of
the rule are notable because there are a large number of affected
entities, but per-entity costs are low. 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.
---------------------------------------------------------------------------
\11\ Note: Before totaling the industry compliance costs, EPA
estimated costs for each of the industry segments. EPA then summed
the costs for each segment at the NAICS level for this screening
assessment.
---------------------------------------------------------------------------
These low average cost-to-sales ratios indicate that the final rule
is unlikely to result in significant changes in firms' production
decisions or other behavioral changes that would result in significant
changes in prices or quantities in affected markets. Given that prices
and quantities are unlikely to change significantly, and consistent
with the agency's guidelines for economic analyses, EPA 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.\12\ Table 8 of this preamble summarizes cost-to-sales
ratios for affected industries.
---------------------------------------------------------------------------
\12\ Guidelines for Preparing Economic Analyses (EPA, 2002, p.
124-125).
Table 8--Estimated Cost-to-sales Ratios for Affected Entities
(Year 1)
----------------------------------------------------------------------------------------------------------------
Average entity
Average cost cost-to-sales
NAICS NAICS Description MRR Segments included per entity ratio \a\
($1,000/entity) (percent)
----------------------------------------------------------------------------------------------------------------
211......................... Crude Petroleum and Onshore Production, $17.1 0.08
Natural Gas Offshore Production,
Extraction. Processing.
486210...................... Pipeline Transmission, 15.7 0.08
Transportation of Underground Storage,
Natural Gas. LNG Storage, and LNG
Import Terminals.
221210...................... Natural Gas Distribution.......... 13.9 0.06
Distribution.
----------------------------------------------------------------------------------------------------------------
\a\ This ratio reflects first year costs. Subsequent year costs will be lower because they do not include
initial start-up activities.
2. Summary of Comments and Responses
While EPA received a substantial number of comments on the
estimated costs for reporters to comply with the rule, there were
minimal additional comments on the economic impacts, such as changes in
production or effects on small entities in particular. As discussed in
the previous section of this preamble, commenters said that EPA
underestimated the compliance costs and recommended that EPA carefully
review the economic impact analysis. See the previous section of this
preamble for a summary; the response to comments document, Mandatory
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments,
Subpart W: Petroleum and Natural Gas Systems, provides detailed
comments.
As discussed in Section III.B.2 of this preamble, EPA collected and
evaluated cost data from multiple sources, thoroughly reviewed the
input received through public comments, and weighed the analysis
prepared for the proposal against this input. EPA has determined that
this analysis provides a reasonable characterization of costs and
economic impacts and that the documentation provides adequate
explanation of how the costs and impacts were estimated.
D. What are the impacts of the 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 85 percent of U.S. GHG emissions from the industry
segments reported by approximately 2,786 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 United States, while excluding many of the
smaller facilities and sources. In response to the comments EPA
received about the monitoring and reporting requirements in specific
source categories, EPA incorporated changes that reduce burden on
reporters while maintaining a high level of emissions coverage. 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 industry 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.\13\ 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 9 of this preamble.
---------------------------------------------------------------------------
\13\ EPA's RFA guidance for rule writers suggests the ``sales''
test continues to be the preferred quantitative metric for economic
impact screening analysis.
[[Page 74482]]
Table 9--Estimated Cost-to-Sales Ratios, Sales Receipts ($Million), and Number of Establishments for First Year Costs by Industry and Enterprise Size\a\
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
SBA Size standard Owned by enterprises with:
in num of Average cost -----------------------------------------------------------------------------------
Industry NAICS NAICS Description employees per entity All 1,000 to
(effective March ($1,000/ enterprises 1 to 20 20 to 99 100 to 499 <500 500 to 749 750 to 999 1,499
11, 2008) entity) Employees Employees Employees Employees Employees Employees Employees
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Onshore petroleum and natural 211 Crude Petroleum 500 $17.1 0.08% 1.32% 0.11% 0.05% 0.47% 0.47% 0.03% 0.02%
gas production; offshore and Natural Gas \d\$160,879 $7,573 $6,790 $9,609 $23,972 $4,609 $3,991 $2,805
petroleum and natural gas Extraction. \e\7,629 5,836 456 292 6,584 60 64 31
production; LNG storage; LNG
import and export.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Onshore natural gas processing; 486210 Pipeline \(b)\ $15.7 0.08% 0.12% 0.40% 0.24% 0.10% \(c)\ \(c)\ \(c)\
onshore natural gas Transportation \d\$35,897 $1,035 \c\$106 \c\$394 $2,566 \(c)\ \(c)\ \(c)\
transmission; underground of Natural Gas. \e\1,936 81 27 61 36 169 2 20
natural gas storage.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Natural gas distribution....... 221210 Natural Gas 500 $13.9 0.06% 0.27% 0.03% 0.06% 0.11% 0.07% 0.02% 0.03%
Distribution. \d\$67,275 $2,524 $4,642 $2,878 $13,127 $865 $2,116 $3,757
\e\2,897 483 86 131 700 68 33 73
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ 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, EPA assumes in this analysis that the enterprise definition above is
consistent with the concept of ultimate parent company that is typically used for Small Business Regulatory Enforcement Fairness Act (SBREFA) screening analyses.
\b\ The SBA size standard for NAICS 486210 is $7 million in average annual receipts.
\c\ The U.S. Census Bureau has missing data for this employee range; some estimates were possible using partial data. The receipts for these categories underestimate true value.
\d\ This row presents total annual sales receipts ($Million)for establishments in each enterprise category. Source: U.S. Census Bureau.
\e\ This row presents total number of establishments in each enterprise category. Source: U.S. Census Bureau.
[[Page 74483]]
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. The only exception is the ratio
for enterprises with 1-20 employees for crude petroleum and natural gas
extraction, which is greater than 1 percent but less than 2 percent. It
is important to note that this analysis does not screen out entities
that would be below the reporting threshold. Based on further analysis
of production data in HPDI, EPA estimates that in most cases, the
smaller enterprises have very small operations (such as a single family
owning a few production wells) that are unlikely to cross the 25,000
metric tons CO2e reporting threshold.
In other cases, a small enterprise (less than 20 employees) may own
large operations but conduct nearly all of its operations through
service providers, so that it has few employees of its own. Such
enterprises, however, tend to have higher annual revenues than those
with small operations and therefore have lower cost-to-sales ratios.
The review of production data by operator in HPDI shows a ratio of less
than one percent for the operators expected to meet the reporting
threshold.
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. That is, the analysis assumes that each
establishment is a unique enterprise. To the extent that a single
parent may own multiple establishments, the small entity impacts could
be lower.
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 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
established a reasonable balance of direct measurement, engineering
estimation, and emission factors based monitoring methods to quantify
emissions, which provides flexibility to entities and helps minimize
reporting costs.
2. Summary of Comments and Responses
Comment: Some commenters noted concerns about the rule's impact on
small businesses, in particular that small businesses would have to
apply the monitoring methods specified in the rule to determine whether
they have to report under the rule. One commenter recommended that EPA
redo its analysis of the rule's impacts on small businesses using
``more accurate economic impact data,'' but did not include or identify
alternative data sources for such an analysis. See the response to
comments document, Mandatory Greenhouse Gas Reporting Rule: EPA's
Response to Public Comments, Subpart W: Petroleum and Natural Gas
Systems, for the detailed comments.
Response: EPA has assessed the economic impact of the final rule on
small entities and concluded that this action will not have a
significant economic impact on a substantial number of small entities.
While the commenter did not provide details in its recommendation that
EPA redo the small business analysis using ``more accurate economic
impact data,'' EPA acknowledges the importance of using the best
available economic data. Accordingly, EPA analyzed the economic impact
on small entities using the revised cost estimates discussed in this
section of the preamble and in the EIA. These cost estimates were the
same order of magnitude as those estimated under the proposal; the
estimates also reflected improvements made in response to comments as
well as changes to the monitoring requirements in the final rule.
In addition, EPA's assessment of the economic impacts on small
entities continued to rely on data from the Statistics of U.S.
Businesses, a well-known database that provides national information on
the distribution of economic variables by the size of entity. As noted
in the EIA, these data were developed in cooperation with, and
partially funded by, the Office of Advocacy of the Small Business
Administration. Complete documentation of this analysis can be found in
Section 5.2 of the EIA for the final rule.
Finally, in response to concerns about the cost to make a reporting
determination, EPA intends to provide screening tools. As discussed
above, these tools will aid small businesses and other potential
reporters in determining whether or not they have to report.
The response to comments document, Mandatory Greenhouse Gas
Reporting Rule: EPA's Response to Public Comments, Subpart W: Petroleum
and Natural Gas Systems, presents the detailed comments and responses
related to the rule's impact on small businesses.
E. What are the benefits of the rule for society?
EPA examined the potential benefits of the final subpart W. The
benefits of a reporting system are based on their relevance to policy
making, transparency, 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 policymakers and the public by increased availability of
facility emissions data. Public data on emissions allows for
accountability of emitters to the public. Citizens, community groups,
and labor unions have made use of data from Pollutant Release and
Transfer Registers to negotiate directly with emitters 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. Facility-
specific emissions data will also aid local, State, and national
policymakers as they evaluate and consider future climate change policy
decisions.
The benefits of mandatory reporting of petroleum and natural gas
systems GHG emissions to government also include enhancing existing
programs, such as the Natural Gas STAR Program, and that provide
significant benefits. Through the Natural Gas STAR Program, EPA has
identified over 120 proven, cost effective technologies and practices
to reduce emissions of methane--the primary constituent of natural
gas--from operations in all of the major industry sectors--production,
gathering and processing, transmission, and distribution. The final
subpart W will increase knowledge of the location and magnitude of
significant methane emissions sources in the petroleum and natural gas
industry, which can result in improvements in these technologies and
the identification of new emissions reducing technologies.
[[Page 74484]]
Benefits to industry of GHG emissions monitoring include the value
of having 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.
The EIA for this final rule as well as the RIA for 40 CFR part 98
summarize the anticipated benefits, 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 justify the estimated costs.
IV. Statutory and Executive Order Review
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 final 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 2376.02.
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
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 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.
The projected cost and hour burden for non-Federal respondents is
$27.7 million and 396,474 hours per year. The estimated average burden
per response is 90.71 hours; the frequency of response is annual for
all respondents that must comply with the final rule's reporting
requirements; and the estimated average number of likely respondents
per year is 2,786. 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 $0.74 million), a
total operation and maintenance component (averaging $1.7 million per
year), and a labor cost component (averaging $25.3 million per
year).\14\
---------------------------------------------------------------------------
\14\ 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.
---------------------------------------------------------------------------
Burden is defined at 5 CFR 1320.3(b). These cost numbers differ
from those shown elsewhere in the EIA for these subparts because the
information collection request (ICR) costs represent the average cost
over the first three years of the rule, but costs are reported
elsewhere in the EIA for the subparts for the first year of the rule
and for subsequent years of the rule. In addition, the ICR focuses on
respondent burden, while the EIA includes both national compliance
costs and the burden for EPA to implement the rule.
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. When this ICR is
approved by OMB, the Agency will publish a technical amendment to 40
CFR part 9 in the Federal Register to display the OMB control number
for the approved information collection requirements contained in this
final rule.
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 final 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 that is independently owned and operated and is not
dominant in its field.
After considering the economic impacts of this final action 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 final rule include
small businesses in the petroleum and gas industry, small governmental
jurisdictions and small non-profits. EPA has determined that some small
businesses will be affected because their production processes emit
GHGs exceeding the reporting threshold.
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
[[Page 74485]]
businesses. This ratio constitutes a ``sales'' test that computes the
annualized compliance costs of this final 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 9 of this preamble, 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. It is important to note that this analysis does not screen out
entities that would be below the reporting threshold. Although the
costs to receipts for entities in onshore production with 1-20
employees is slightly over 1 percent, most of these facilities would
likely not exceed the 25,000 mtCO2e threshold, a threshold
supported by many stakeholders as one that sufficiently captures the
majority of GHG emissions while excluding small facilities.
EPA also concluded that the final rulemaking would not affect a
small organization that is any not-for-profit enterprise that is
independently owned and operated and is not dominant in its field.
Specifically, the data listing entities in each segment of the
petroleum and natural gas industry did not include any non-profit
entities.
In addition, EPA determined that the final rulemaking would not
have a significant impact on small governmental jurisdictions. EPA
determined that one segment of the petroleum and natural gas industry
might include small governments affected by the final rulemaking. A
comparison of the compliance costs to the revenue of potentially
affected small governmental jurisdictions revealed that the costs of
the rule are less than 1 percent of revenues.
Although this final 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 final rule on small
entities. For example, EPA determined appropriate thresholds that
reduce the number of small businesses reporting. In addition, EPA
allows different monitoring methods for different emissions sources,
requiring direct measurement only for selected sources. Also, EPA
intends to provide a screening tool that will help small businesses
make a reporting determination (see Section II.F.6 of this preamble).
Finally, EPA is establishing 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 website, along with a general fact sheet for the
rule, information sheets for every source category, and an FAQ
document. EPA also operated a hotline to answer questions about the
final rule. EPA 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 final 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 final rule.
EPA has therefore concluded that this final action will not have a
significant economic impact on a substantial number of small entities.
D. Unfunded Mandates Reform Act (UMRA)
This 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 sector in any one year.
EPA estimated the cost to individual facilities that may have to report
to this final rule using actual facility characteristics such as
throughput and size. EPA also determined the costs to non-reporters for
determination to report. The sum of these costs for the entire industry
has been estimated to be less than $100 million. Thus, this rule is not
subject to the requirements of sections 202 or 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. Based on EPA's
analysis of the rule's impact on small entities, the Agency determined
that natural gas distribution is the only industry segment that would
potentially have small governments affected by the rule. In this
segment, however, the facilities owned or operated by small governments
are expected to be too small to trigger the 25,000 metric tons
CO2e reporting threshold.
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 EO 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, EO 13132 does not apply to
this action.
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. EPA conducted an analysis
to determine potential impact of this action on tribes that own or
operate petroleum and natural gas systems (EPA-HQ-OAR-2009-0923-XXX).
First, EPA analyzed a comprehensive listing of all operators of
petroleum and natural gas systems in the United States in conducting
the threshold analysis. In a separate analysis, EPA researched
additional available data to determine which tribal entities may own or
operate petroleum and natural gas systems that could be impacted by
this final action. As a result of those analyses, EPA found one tribe
that may potentially be impacted by this final action. Finally, during
the comment period for the April 2010 proposal, EPA received comment
from one tribe, Southern Ute, which were specific to the proposed
reporting methodologies.
As further discussed in the 2009 final rule that established the
Greenhouse Gas reporting program, EPA believes that there are minimal
impacts to tribes. Tribes could be required to submit an annual GHG
report for any facility they own or operate that is subject to the
rule. Specifically, tribes that own or operate oil and gas operations
could be required to report emissions under this
[[Page 74486]]
rulemaking. It should be noted that the owner or operator of any
privately owned sources located on a reservation would be required to
report for any applicable facility. EPA sought opportunities to provide
information to tribal governments and representatives during rule
development. As stated in IV.F of this preamble, Executive Order 13175:
Consultation and Coordination with Indian Tribal Governments of 40 CFR
part 98, and in consultation with EPA's American Indian Environment
Office, EPA's outreach plan for the Greenhouse Gas Reporting Rule
included tribes. EPA conducted several conference calls with Tribal
organizations during the proposal phase of part 98. 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 The Climate Registry (TCR).
In addition, EPA prepared a short article on the Greenhouse Gas
Reporting Program 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 Greenhouse Gas Reporting Program, at the
National Tribal Conference on Environmental Management on June 24-26,
2008. In addition, EPA distributed copies of a short information sheet
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 participated in a conference call with Tribal air coordinators in
April 2009 and prepared a guidance sheet for Tribal governments on the
final Part 98. It was posted on the Greenhouse Gas Reporting Program
Web site and published in the Tribal Air Newsletter.
As required by section 7(a), EPA's Tribal Consultation Official has
certified that the requirements of the Executive Order have been met in
a meaningful and timely manner. A copy of the certification is included
in the docket for this action.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is not subject to EO 13045 because it does not
establish an environmental standard intended to mitigate health or
safety risks. Also, this is not an economically significant rule under
EO 12866, and thus EO 13045 does not apply.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This final 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, EPA has concluded that this final rule is not
likely to have any adverse energy effects. This final 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, EPA concludes that this final
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 final rule.
Instead, EPA reviewed existing rules for source categories and
voluntary greenhouse gas programs and 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 final
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 12898 (59 FR 7629, February 16, 1994) establishes
Federal executive policy on environmental justice. Its main provision
directs Federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
EPA has determined that this final 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.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA),
generally provides that before a rule may take effect, the agency
promulgating the rule must submit a rule report, which includes a copy
of the rule, to each House of the Congress and to the Comptroller
General of the United States. EPA will submit a report containing this
rule and other required information to the U.S. Senate, the U.S. House
of Representatives, and the Comptroller General of the U.S. prior to
publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective December 30, 2010.
List of Subjects in 40 CFR Part 98
Environmental protection, Administrative practice and procedure,
Greenhouse gases, Incorporation by reference, Suppliers, Reporting and
recordkeeping requirements.
[[Page 74487]]
Dated: November 8, 2010.
Lisa P. Jackson,
Administrator.
0
For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is amended as follows:
PART 98--[AMENDED]
0
1. The authority citation for part 98 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart A--[Amended]
0
2. Section 98.2 is amended by revising the introductory text to
paragraph (a) 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:
* * * * *
0
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.
* * * * *
Air injected flare means a flare in which air is blown into the
base of a flare stack to induce complete combustion of gas.
* * * * *
Blowdown vent stack emissions mean natural gas and/or
CO2 released due to maintenance and/or blowdown operations
including 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 an 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 or CO2 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 or
CO2 from escaping to the atmosphere.
Centrifugal compressor dry seal emissions mean natural gas or
CO2 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 vent emissions means
emissions that occur when the high-pressure oil barriers for
centrifugal compressors are depressurized to release absorbed natural
gas or CO2. 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.
* * * * *
Continuous bleed means a continuous flow of pneumatic supply gas to
the process measurement device (e.g. level control, temperature
control, pressure control) where the supply gas pressure is modulated
by the process condition, and then flows to the valve controller where
the signal is compared with the process set-point to adjust gas
pressure in the valve actuator.
* * * * *
Dehydrator means a device in which a liquid absorbent (including
desiccant, ethylene glycol, diethylene glycol, or triethylene glycol)
directly contacts a natural gas stream to absorb water vapor.
Dehydrator vent emissions means natural gas and CO2
released from a natural gas dehydrator system absorbent (typically
glycol) reboiler or regenerator to the atmosphere or a flare, 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 or absorption. Desiccants
include activated alumina, pelletized calcium chloride, lithium
chloride and granular silica gel material. Wet natural gas is passed
through a bed of the granular or pelletized solid adsorbent or
absorbent in these dehydrators. As the wet gas contacts the surface of
the particles of desiccant material, water is adsorbed on the surface
or absorbed and dissolves the surface of these desiccant particles.
Passing through the entire desiccant bed, almost all of the water is
adsorbed onto or absorbed into the desiccant material, leaving the dry
gas to exit the contactor.
* * * * *
Gas conditions mean the actual temperature, volume, and pressure of
a gas sample.
* * * * *
Gas to oil ratio (GOR) means the ratio of the volume of gas at
standard temperature and pressure that is produced from a volume of oil
when depressurized to standard temperature and pressure.
* * * * *
High-bleed pneumatic devices are automated, continuous bleed 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 that is
regulated by the process condition flows to a valve actuator controller
where it vents continuously (bleeds) to the atmosphere at a rate in
excess of 6 standard cubic feet per hour.
* * * * *
Intermittent 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. These are snap-acting or throttling devices that discharge
the full volume of the actuator intermittently when control action is
necessary, but does not bleed continuously.
* * * * *
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 that is regulated by the
process condition flows to a valve actuator controller where it vents
continuously (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
[[Page 74488]]
natural gas to move a piston or diaphragm, which pumps liquids on the
opposite side of the piston or diaphragm.
* * * * *
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. 1331, and of which the subsoil and seabed appertain to the
United States and are subject to its jurisdiction and control.
* * * * *
Reciprocating compressor means a piece of equipment that increases
the pressure of a process natural gas or CO2 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 or CO2 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.
* * * * *
Sales oil means produced crude oil or condensate measured at the
production lease automatic custody transfer (LACT) meter or custody
transfer tank gauge.
* * * * *
Sour natural gas means natural gas that contains significant
concentrations of hydrogen sulfide (H2S)and/or carbon
dioxide (CO2) 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.
* * * * *
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.
* * * * *
Well completions means the 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, steps
which may vent produced gas to the atmosphere via an open pit or tank.
Well completion also involves connecting the well bore to the
reservoir, which may include treating the formation or installing
tubing, packer(s), or lifting equipment, steps that do not
significantly vent natural gas to the atmosphere. This process may also
include high-rate flowback of injected gas, water, oil, and proppant
used to fracture or re-fracture and prop open new fractures in existing
lower permeability gas reservoirs, steps that may vent large quantities
of produced gas to the atmosphere.
Well workover means the process(es) of performing one or more of a
variety of remedial operations on producing petroleum and natural gas
wells to try to increase production. This process also includes high-
rate flowback of injected gas, water, oil, and proppant used to re-
fracture and prop-open new fractures in existing low permeability gas
reservoirs, steps that may vent large quantities of produced gas to the
atmosphere.
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. Wellhead equipment includes all equipment, permanent and
portable, located on the improved land area (i.e. well pad) surrounding
one or multiple wellheads.
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.''
* * * * *
0
4. Section 98.7 is amended by adding and reserving paragraphs (n) and
(o), and by adding paragraphs (p) and (q) to read as follows:
Sec. 98.7 What standardized methods are incorporated by reference
into this part?
* * * * *
(n) [Reserved]
(o) [Reserved]
(p) The following material is available for purchase from the
American Association of Petroleum Geologists, 1444 South Boulder
Avenue, Tulsa, Oklahoma 74119, (918) 584-2555, http://www.aapg.org.
(1) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG
Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J.
Wagner, Jr., Volume 75, Number 10 (October 1991), pages 1644-1651, IBR
approved for Sec. 98.238.
(2) Alaska Geological Province Boundary Map, Compiled by the
American Association of Petroleum Geologists Committee on Statistics of
Drilling in cooperation with the USGS, 1978, IBR approved for Sec.
98.238.
(q) The following material is available from the Energy Information
Administration (EIA), 1000 Independence Ave., SW., Washington, DC
20585, (202) 586-8800, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/field_code_master_list/current/pdf/fcml_all.pdf.
(1) Oil and Gas Field Code Master List 2008, DOE/EIA0370(08),
January 2009, IBR approved for Sec. 98.238.
(2) [Reserved]
0
5. Table A-4 to subpart A is amended by adding an entry for ``Petroleum
and Natural Gas Systems (subpart W)'' at the end of the table to read
as follows:
Table A-4 to Subpart A--Source Category List for Sec. 98.2(a)(2)
------------------------------------------------------------------------
-------------------------------------------------------------------------
Source Categories \a\ Applicable in 2010 and Future Years
* * * * * * *
Additional Source Categories \a\ Applicable in 2011 and Future Years
* * * * * * *
Petroleum and Natural Gas Systems (subpart W)
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.
0
6. Add Subpart W--Petroleum and Natural Gas Systems to read as follows:
Subpart W--Petroleum and Natural Gas Systems
Sec.
98.230 Definition of the source category.
[[Page 74489]]
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.
Table W-1A to Subpart W of Part 98--Default Whole Gas Emission
Factors for Onshore Petroleum and Natural Gas Production
Table W-1B to Subpart W of Part 98--Default Average Component Counts
for Major Onshore Natural Gas Production Equipment
Table W-1C to Subpart W of Part 98--Default Average Component Counts
For Major Crude Oil Production Equipment
Table W-1D of Subpart W of Part 98--Designation Of Eastern And
Western U.S.
Table W-2 to Subpart W of Part 98--Default Total Hydrocarbon
Emission Factors for Onshore Natural Gas Processing
Table W-3 to Subpart W of Part 98--Default Total Hydrocarbon
Emission Factors for Onshore Natural Gas Transmission Compression
Table W-4 to Subpart W of Part 98--Default Total Hydrocarbon
Emission Factors for Underground Natural Gas Storage
Table W-5 to Subpart W of Part 98--Default Methane Emission Factors
for Liquefied Natural Gas (LNG) Storage
Table W-6 to Subpart W of Part 98--Default Methane Emission Factors
for LNG Import and Export Equipment
Table W-7 to Subpart W of Part 98--Default Methane Emission Factors
for Natural Gas Distribution
Sec. 98.230 Definition of the source category.
(a) This source category consists of the following industry
segments:
(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
processes and/or transfers such hydrocarbons to storage, transport
vessels, or onshore. In addition, offshore production includes
secondary platform structures connected to the platform structure via
walkways, storage tanks associated with the platform structure and
floating production and storage offloading equipment (FPSO). This
source category does not include reporting of emissions from offshore
drilling and exploration that is not conducted on production platforms.
(2) Onshore petroleum and natural gas production. Onshore petroleum
and natural gas production means all equipment on a well pad or
associated with a well pad (including compressors, generators, or
storage facilities), and portable non-self-propelled equipment on a
well pad or associated with a well pad (including well drilling and
completion equipment, workover equipment, gravity separation equipment,
auxiliary non-transportation-related equipment, and leased, rented or
contracted equipment) used in the production, extraction, recovery,
lifting, stabilization, separation or treating of petroleum and/or
natural gas (including condensate). This equipment also includes
associated storage or measurement vessels and all enhanced oil recovery
(EOR) operations using CO2, 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. Natural gas processing
separates and recovers natural gas liquids (NGLs) and/or other non-
methane gases and liquids from a stream of produced natural gas using
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. This segment also includes all residue gas
compression equipment owned or operated by the natural gas processing
facility, whether inside or outside the processing facility fence. This
source category does not include reporting of emissions from gathering
lines and boosting stations. This source category includes:
(i) All processing facilities that fractionate.
(ii) All processing facilities that do not fractionate with
throughput of 25 MMscf per day or greater.
(4) Onshore natural gas transmission compression. Onshore natural
gas transmission compression means any stationary combination of
compressors that move natural gas 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 may include equipment for liquids
separation, natural gas dehydration, and tanks for the storage of water
and hydrocarbon liquids. Residue (sales) gas compression operated by
natural gas processing facilities are included in the onshore natural
gas processing segment and are excluded from this segment. This source
category also does not include reporting of emissions from gathering
lines and boosting stations--these sources are currently not covered by
subpart W.
(5) Underground natural gas storage. Underground natural gas
storage means subsurface storage, including depleted gas or oil
reservoirs and salt dome caverns that store 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 compression, dehydration and flow measurement, and excluding
transmission pipelines); and all the wellheads connected to the
compression units located at the facility that inject and recover
natural gas into and from the underground reservoirs.
(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, 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 the
distribution pipelines (not interstate transmission pipelines or
intrastate transmission pipelines) and metering and regulating
equipment at city gate stations, and excluding customer meters, that
physically deliver natural gas to end users and is operated by a Local
Distribution Company (LDC) that is regulated as a separate operating
company by a public utility commission or that is operated as an
independent municipally-owned distribution system. This segment
excludes customer meters and infrastructure and pipelines (both
interstate and intrastate) delivering natural gas directly to major
industrial users and ``farm taps'' upstream of the local distribution
company inlet.
(b) [Reserved]
Sec. 98.231 Reporting threshold.
(a) You must report GHG emissions under this subpart if your
facility contains petroleum and natural gas systems and the facility
meets the requirements of Sec. 98.2(a)(2). Facilities must report
emissions from the onshore petroleum and natural gas production
[[Page 74490]]
industry segment only if emission sources specified in paragraph Sec.
98.232(c) emit 25,000 metric tons of CO2 equivalent or more
per year. Facilities must report emissions from the natural gas
distribution industry segment only if emission sources specified in
paragraph Sec. 98.232(i) emit 25,000 metric tons of CO2
equivalent or more per year.
(b) For applying the threshold defined in Sec. 98.2(a)(2), natural
gas processing facilities must also include owned or operated residue
gas compression equipment.
Sec. 98.232 GHGs to report.
(a) You must report CO2, CH4, and
N2O emissions from each industry segment specified in
paragraph (b) through (i) of this section, CO2,
CH4, and N2O emissions from each flare as
specified in paragraph (j) of this section, and stationary and portable
combustion emissions as applicable as specified in paragraph (k) of
this section.
(b) For offshore petroleum and natural gas production, report
CO2, CH4, and N2O emissions from
equipment leaks, vented emission, and flare emission source types as
identified in the data collection and emissions estimation study
conducted by BOEMRE in compliance with 30 CFR 250.302 through 304.
Offshore platforms do not need to report portable emissions.
(c) For an onshore petroleum and natural gas production facility,
report CO2, CH4, and N2O emissions
from only the following source types on a well pad or associated with a
well pad:
(1) Natural gas pneumatic device venting.
(2) [Reserved]
(3) Natural gas driven pneumatic pump venting.
(4) Well venting for liquids unloading.
(5) Gas well venting during well completions without hydraulic
fracturing.
(6) Gas well venting during well completions with hydraulic
fracturing.
(7) Gas well venting during well workovers without hydraulic
fracturing.
(8) Gas well venting during well workovers with hydraulic
fracturing.
(9) Flare stack emissions.
(10) Storage tanks vented emissions from produced hydrocarbons.
(11) Reciprocating compressor rod packing venting.
(12) Well testing venting and flaring.
(13) Associated gas venting and flaring from produced hydrocarbons.
(14) Dehydrator vents.
(15) [Reserved]
(16) EOR injection pump blowdown.
(17) Acid gas removal vents.
(18) EOR hydrocarbon liquids dissolved CO2.
(19) Centrifugal compressor venting.
(20) [Reserved]
(21) Equipment leaks from valves, connectors, open ended lines,
pressure relief valves, pumps, flanges, and other equipment leak
sources (such as instruments, loading arms, stuffing boxes, compressor
seals, dump lever arms, and breather caps).
(22) You must use the methods in Sec. 98.233(z) and report under
this subpart the emissions of CO2, CH4, and
N2O from stationary or portable fuel combustion equipment
that cannot move on roadways under its own power and drive train, and
that are located at an onshore production well pad. Stationary or
portable equipment are the following equipment which are integral to
the extraction, processing or movement of oil or natural gas: Well
drilling and completion equipment, workover equipment, natural gas
dehydrators, natural gas compressors, electrical generators, steam
boilers, and process heaters.
(d) For onshore natural gas processing, report CO2 and
CH4 emissions from the following sources:
(1) Reciprocating compressor rod packing venting.
(2) Centrifugal compressor venting.
(3) Blowdown vent stacks.
(4) Dehydrator vents.
(5) Acid gas removal vents.
(6) Flare stack emissions.
(7) Equipment leaks from valves, connectors, open ended lines,
pressure relief valves, and meters.
(e) For onshore natural gas transmission compression, report
CO2 and CH4 emissions from the following sources:
(1) Reciprocating compressor rod packing venting.
(2) Centrifugal compressor venting.
(3) Transmission storage tanks.
(4) Blowdown vent stacks.
(5) Natural gas pneumatic device venting.
(6) [Reserved]
(7) Equipment leaks from valves, connectors, open ended lines,
pressure relief valves, and meters.
(f) For underground natural gas storage, report CO2 and
CH4 emissions from the following sources:
(1) Reciprocating compressor rod packing venting.
(2) Centrifugal compressor venting.
(3) Natural gas pneumatic device venting.
(4) [Reserved]
(5) Equipment leaks from valves, connectors, open ended lines,
pressure relief valves, and meters.
(g) For LNG storage, report CO2 and CH4
emissions from the following sources:
(1) Reciprocating compressor rod packing venting.
(2) Centrifugal compressor venting.
(3) Equipment leaks from valves; pump seals; connectors; vapor
recovery compressors, and other equipment leak sources.
(h) LNG import and export equipment, report CO2 and
CH4 emissions from the following sources:
(1) Reciprocating compressor rod packing venting.
(2) Centrifugal compressor venting.
(3) Blowdown vent stacks.
(4) Equipment leaks from valves, pump seals, connectors, vapor
recovery compressors, and other equipment leak sources.
(i) For natural gas distribution, report emissions from the
following sources:
(1) Above ground meters and regulators at custody transfer city
gate stations, including equipment leaks from connectors, block valves,
control valves, pressure relief valves, orifice meters, regulators, and
open ended lines. Customer meters are excluded.
(2) Above ground meters and regulators at non-custody transfer city
gate stations, including station equipment leaks. Customer meters are
excluded.
(3) Below ground meters and regulators and vault equipment leaks.
Customer meters are excluded.
(4) Pipeline main equipment leaks.
(5) Service line equipment leaks.
(6) Report under subpart W of this part the emissions of
CO2, CH4, and N2O emissions from
stationary fuel combustion sources following the methods in Sec.
98.233(z).
(j) All applicable industry segments must report the
CO2, CH4, and N2O emissions from each
flare.
(k) Report under subpart C of this part (General Stationary Fuel
Combustion Sources) the emissions of CO2, CH4,
and N2O from each stationary fuel combustion unit by
following the requirements of subpart C. Onshore petroleum and natural
gas production facilities must report stationary and portable
combustion emissions as specified in paragraph (c) of this section.
Natural gas distribution facilities must report stationary combustion
emissions as specified in paragraph (i) of this section.
(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.
You must calculate and report the annual GHG emissions as
prescribed in this section. For actual conditions,
[[Page 74491]]
reporters must use average atmospheric conditions or typical operating
conditions as applicable to the respective monitoring methods in this
section.
(a) Natural gas pneumatic device venting. Calculate CH4
and CO2 emissions from continuous high bleed, continuous low
bleed, and intermittent bleed natural gas pneumatic devices using
Equation W-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.173
Where:
Masss,i = Annual total mass GHG emissions in metric tons
CO2e per year at standard conditions from a natural gas
pneumatic device vent, for GHG i.
Count = Total number of continuous high bleed, continuous low bleed,
or intermittent bleed natural gas pneumatic devices of each type as
determined in paragraph (a)(1) of this section.
EF = Population emission factors for natural gas pneumatic device
venting listed in Tables W-1A, W-3, and W-4 of this subpart for
onshore petroleum and natural gas production, onshore natural gas
transmission compression, and underground natural gas storage
facilities, respectively.
GHGi = 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; 0.000410 for CH4, and 0.00005357
for CO2.
24 * 365 = Conversion to yearly emissions estimate.
(1) For onshore petroleum and natural gas production, provide the
total number of continuous high bleed, continuous low bleed, or
intermittent bleed natural gas pneumatic devices of each type as
follows:
(i) In the first calendar year, for the total number of each type,
you may count the total of each type, or count any percentage number of
each type plus an engineering estimate based on best available data of
the number not counted.
(ii) In the second consecutive year, for the total number of each
type, you may count the total of each type, or count any percentage
number of each type plus an engineering estimate based on best
available data of the number not counted.
(iii) In the third consecutive calendar year, complete the count of
all pneumatic devices, including any changes to equipment counted in
prior years.
(iv) For the calendar year immediately following the third
consecutive calendar year, and for calendar years thereafter,
facilities must update the total count of pneumatic devices and adjust
accordingly to reflect any modifications due to changes in equipment.
(2) For onshore natural gas transmission compression and
underground natural gas storage, all natural gas pneumatic devices must
be counted in the first year and updated every calendar year.
(b) [Reserved]
(c) Natural gas driven pneumatic pump venting. Calculate
CH4 and CO2 emissions from natural gas driven
pneumatic pump venting using Equation W-2 of this section. Natural gas
driven pneumatic pumps covered in paragraph (e) of this section do not
have to report emissions under paragraph (c) of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.174
Where:
Masss,i = Annual total mass GHG emissions in metric tons
CO2e per year at standard conditions from all natural gas
pneumatic pump venting, for GHG i.
Count = Total number of natural gas pneumatic pumps.
EF = Population emission factors for natural gas pneumatic pump
venting listed in Tables W-1A of this subpart for onshore petroleum
and natural gas production.
GHGi = Concentration of GHG i, CH4 or
CO2, in produced natural gas.
Convi = Conversion from standard cubic feet to metric
tons CO2e; 0.000410 for CH4, and 0.00005357
for CO2.
24 * 365 = Conversion to yearly emissions estimate.
(d) Acid gas removal (AGR) vents. For AGR vent (including processes
such as amine, membrane, molecular sieve or other absorbents and
adsorbents), calculate emissions for CO2 only (not
CH4) vented directly to the atmosphere or through a flare,
engine (e.g. permeate from a membrane or de-adsorbed gas from a
pressure swing adsorber used as fuel supplement), or sulfur recovery
plant using any of the calculation methodologies described in paragraph
(d) of this section.
(1) Calculation Methodology 1. If you operate and maintain a CEMS
that measures CO2 emissions according to subpart C of this
part, you must calculate CO2 emissions under this subpart by
following the Tier 4 Calculation Methodology and all associated
requirements for Tier 4 in subpart C of this part (General Stationary
Fuel Combustion Sources). If CEMS and/or volumetric flow rate monitor
are not available, you may install a CEMS that complies with the Tier 4
Calculation Methodology in subpart C of this part (General Stationary
Fuel Combustion).
(2) Calculation Methodology 2. If CEMS is not available, use the
CO2 composition and annual volume of vent gas to calculate
emissions using Equation W-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.175
Where:
Ea,CO2 = Annual volumetric CO2 emissions at
actual conditions, in cubic feet per year.
VS = Total annual volume of vent gas flowing out of the
AGR unit in cubic feet per year at actual conditions as determined
by flow meter using methods set forth in Sec. 98.234(b).
VolCO2 = Volume fraction of CO2 content in
vent gas out of the AGR unit as determined in (d)(6) of this
section.
(3) Calculation Methodology 3. If using CEMS or vent meter is not
an option, use the inlet or outlet gas flow rate of the acid gas
removal unit to calculate emissions for CO2 using Equation
W-4 of this section.
[[Page 74492]]
[GRAPHIC] [TIFF OMITTED] TR30NO10.176
Where:
Ea,CO2 = Annual volumetric CO2 emissions at
actual condition, in cubic feet per year.
V = Total annual volume of natural gas flow into or out of the AGR
unit in cubic feet per year at actual condition as determined using
methods specified in paragraph (d)(5) of this section.
[alpha] = Factor is 1 if the outlet stream flow is measured. Factor
is 0 if the inlet stream flow is measured.
VolI = Volume fraction of CO2 content in
natural gas into the AGR unit as determined in paragraph (d)(7) of
this section.
VolO = Volume fraction of CO2 content in
natural gas out of the AGR unit as determined in paragraph (d)(8) of
this section.
(4) Calculation Methodology 4. Calculate emissions using any
standard simulation software packages, such as AspenTech HYSYS[supreg]
and API 4679 AMINECalc, that uses the Peng-Robinson equation of state,
and speciates CO2 emissions. A minimum of the following
determined for typical operating conditions over the calendar year by
engineering estimate and process knowledge based on best available data
must be used to characterize emissions:
(i) Natural gas feed temperature, pressure, and flow rate.
(ii) Acid gas content of feed natural gas.
(iii) Acid gas content of outlet natural gas.
(iv) Unit operating hours, excluding downtime for maintenance or
standby.
(v) Exit temperature of natural gas.
(vi) Solvent pressure, temperature, circulation rate, and weight.
(5) Record the gas flow rate of the inlet and outlet natural gas
stream of an AGR unit using a meter according to methods set forth in
Sec. 98.234(b). If you do not have a continuous flow meter, either
install a continuous flow meter or use an engineering calculation to
determine the flow rate.
(6) If continuous gas analyzer is not available on the vent stack,
either install a continuous gas analyzer or take quarterly gas samples
from the vent gas stream to determine VolCO2 according to
methods set forth in Sec. 98.234(b).
(7) If a continuous gas analyzer is installed on the inlet gas
stream, then the continuous gas analyzer results must be used. If
continuous gas analyzer is not available, either install a continuous
gas analyzer or take quarterly gas samples from the inlet gas stream to
determine VolI according to methods set forth in Sec.
98.234(b).
(8) Determine volume fraction of CO2 content in natural
gas out of the AGR unit using one of the methods specified in paragraph
(d)(8) of this section.
(i) If a continuous gas analyzer is installed on the outlet gas
stream, then the continuous gas analyzer results must be used. If a
continuous gas analyzer is not available, you may install a continuous
gas analyzer.
(ii) If a continuous gas analyzer is not available or installed,
quarterly gas samples may be taken from the outlet gas stream to
determine VolO according to methods set forth in Sec.
98.234(b).
(iii) Use sales line quality specification for CO2 in
natural gas.
(9) Calculate CO2 volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
(10) Mass CO2 emissions shall be calculated from
volumetric CO2 emissions using calculations in paragraph (v)
of this section.
(11) Determine if emissions from the AGR unit are recovered and
transferred outside the facility. Adjust the emission estimated in
paragraphs (d)(1) through (d)(10) of this section downward by the
magnitude of emission recovered and transferred outside the facility.
(e) Dehydrator vents. For dehydrator vents, calculate annual
CH4, CO2 and N2O (when flared)
emissions using calculation methodologies described in paragraphs
(e)(1) or (e)(2) of this section.
(1) Calculation Methodology 1. Calculate annual mass emissions from
dehydrator vents with throughput greater than or equal to 0.4 million
standard cubic feet per day using a software program, such as AspenTech
HYSYS[supreg] or GRI-GLYCalc, that uses the Peng-Robinson equation of
state to calculate the equilibrium coefficient, speciates
CH4 and CO2 emissions from dehydrators, and has
provisions to include regenerator control devices, a separator flash
tank, stripping gas and a gas injection pump or gas assist pump. A
minimum of the following parameters determined by engineering estimate
based on best available data must be used to characterize 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 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 and pressure.
(xi) Wet natural gas composition. Determine this parameter by
selecting one of the methods described under paragraph (e)(2)(xi) of
this section.
(A) Use the wet natural gas composition as defined in paragraph
(u)(2)(i) of this section.
(B) If wet natural gas composition cannot be determined using
paragraph (u)(2)(i) of this section, select a representative analysis.
(C) You may use an appropriate standard method published by a
consensus-based standards organization if such a method exists or you
may use an industry standard practice as specified in Sec.
98.234(b)(1) to sample and analyze wet natural gas composition.
(D) If only composition data for dry natural gas is available,
assume the wet natural gas is saturated.
(2) Calculation Methodology 2. Calculate annual CH4 and
CO2 emissions from glycol dehydrators with throughput less
than 0.4 million cubic feet per day using Equation W-5 of this section:
[GRAPHIC] [TIFF OMITTED] TR30NO10.177
Where:
Es,i = Annual total volumetric GHG emissions (either
CO2 or CH4) at standard conditions in cubic
feet.
EFi = Population emission factors for glycol dehydrators
in thousand standard cubic feet per dehydrator per year. Use 74.5
for CH4 and 3.26 for CO2 at 68[deg]F and 14.7
psia or 73.4 for CH4 and 3.21 for CO2 at
60[deg]F and 14.7 psia.
Count = Total number of glycol dehydrators with throughput less than
0.4 million cubic feet.
1000 = Conversion of EFi in thousand standard cubic to
cubic feet.
[[Page 74493]]
(3) Determine if dehydrator unit has vapor recovery. Adjust the
emissions estimated in paragraphs (e)(1) or (e)(2) of this section
downward by the magnitude of emissions captured.
(4) Calculate annual emissions from dehydrator vents to flares or
regenerator fire-box/fire tubes as follows:
(A) Use the dehydrator vent volume and gas composition as
determined in paragraphs (e)(1) and (e)(2) of this section.
(B) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine dehydrator vent emissions from the
flare or regenerator combustion gas vent.
(5) 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-6 of this section.
Desiccant dehydrators covered in (e)(5) of this section do not have to
report emissions under (i) of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.178
Where:
Es,n = Annual natural gas emissions at standard
conditions in cubic feet.
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).
100 = Conversion of %G to fraction.
(6) Both CH4 and CO2 volumetric and mass
emissions shall be calculated from volumetric natural gas emissions
using calculations in paragraphs (u) and (v) of this section.
(f) Well venting for liquids unloadings. Calculate CO2
and CH4 emissions from well venting for liquids unloading
using one of the calculation methodologies described in paragraphs
(f)(1), (f)(2) or (f)(3) of this section.
(1) Calculation Methodology 1. For one well of each unique well
tubing diameter and producing horizon/formation combination in each gas
producing field (see Sec. 98.238 for the definition of 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-7 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.179
Where:
Ea,n = Annual natural gas emissions at actual conditions
in cubic feet.
Th,t = Cumulative amount of time in hours of venting from
all wells of the same tubing diameter (t) and producing horizon (h)/
formation combination during the year.
FRh,t = Average flow rate in cubic feet per hour of the
measured well venting for the duration of the liquids unloading,
under actual conditions as determined in paragraph (f)(1)(i) of this
section.
(i) Determine the well vent average flow rate as specified under
paragraph (f)(1)(i) of this section.
(A) The average flow rate per hour of venting is calculated for
each unique tubing diameter and producing horizon/formation combination
in each producing field by averaging the recorded flow rates for the
recorded time of one representative well venting to the atmosphere.
(B) This average flow rate is applied to all wells in the field
that have the same tubing diameter and producing horizon/formation
combination, for the number of hours of venting these wells.
(C) A new average flow rate is calculated every other calendar year
for each reporting field and horizon starting the first calendar year
of data collection.
(ii) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
(2) Calculation Methodology 2. Calculate emissions from each well
venting for liquids unloading using Equation W-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.180
Where:
Ea,n = Annual natural gas emissions at actual conditions,
in cubic feet/year.
0.37x10-3 = {3.14 (pi)/4{time} /{14.7*144{time} (psia
converted to pounds per square feet).
CD = Casing diameter (inches).
WD = Well depth to first producing horizon (feet).
SP = Shut-in pressure (psia).
NV = Number of vents per year.
SFR = Average sales flow rate of gas well in cubic feet per hour.
HR = Hours that the well was left open to the atmosphere during
unloading.
1.0 = Hours for average well to blowdown casing volume at shut-in
pressure.
Z = If HR is less than 1.0 then Z is equal to 0. If HR is greater
than or equal to 1.0 then Z is equal to 1.
(i) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
(ii) [Reserved]
(3) Calculation Methodology 3. Calculate emissions from each well
venting to the atmosphere for liquids unloading with plunger lift
assist using Equation W-9 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.181
[[Page 74494]]
Where:
Ea,n = Annual natural gas emissions at actual conditions,
in cubic feet/year.
0.37x10-3 = {3.14 (pi)/4{time} /{14.7*144{time} (psia
converted to pounds per square feet).
TD = Tubing diameter (inches).
WD = Tubing depth to plunger bumper (feet).
SP = Sales line pressure (psia).
NV = Number of vents per year.
SFR = Average sales flow rate of gas well in cubic feet per hour.
HR = Hours that the well was left open to the atmosphere during
unloading.
0.5 = Hours for average well to blowdown tubing volume at sales line
pressure.
Z = If HR is less than 0.5 then Z is equal to 0. If HR is greater
than or equal to 0.5 then Z is equal to 1.
(i) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
(ii) [Reserved]
(4) 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.
(g) Gas well venting during completions and workovers from
hydraulic fracturing. Calculate CH4, CO2 and
N2O (when flared) annual emissions from gas well venting
during completions involving hydraulic fracturing in wells and well
workovers using Equation W-10 of this section. Both CH4 and
CO2 volumetric and mass emissions shall be calculated from
volumetric total gas emissions using calculations in paragraphs (u) and
(v) of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.182
Where:
Ea,n = Annual volumetric total gas emissions in cubic
feet at standard conditions from gas well venting during completions
following hydraulic fracturing.
T = Cumulative amount of time in hours of all well completion
venting in a field during the year reporting.
FR = Average flow rate in cubic feet per hour, under actual
conditions, converted to standard conditions, as required in
paragraph (g)(1) of this section.
EnF = Volume of CO2 or N2 injected gas in
cubic feet at standard conditions that was injected into the
reservoir during an energized fracture job. If the fracture process
did not inject gas into the reservoir, then EnF is 0. If injected
gas is CO2 then EnF is 0.
SG = Volume of natural gas in cubic feet at standard conditions that
was recovered into a sales pipeline. If no gas was recovered for
sales, SG is 0.
(1) The average flow rate for gas well venting to the atmosphere or
to a flare during well completions and workovers from hydraulic
fracturing shall be determined using either of the calculation
methodologies described in this paragraph (g)(1) of this section.
(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 (digital or analog) shall be installed on the
vent line, ahead of a flare if used, to measure the backflow venting
event according to methods set forth in Sec. 98.234(b).
(A) The average flow rate in cubic feet per hour of venting to the
atmosphere or routed to a flare is determined from the flow recording
over the period of backflow venting.
(B) The respective flow rates are applied to all well completions
in the producing field and to all well workovers in the producing field
for the total number of hours of venting of each of these wells.
(C) New flow rates for completions and workovers are measured every
other calendar year for each reporting gas producing field and gas
producing geologic horizon in each gas producing field starting in the
first calendar year of data collection.
(D) Calculate total volumetric flow rate at standard conditions
using calculations in paragraph (t) of this section.
(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 well flowing pressure upstream (and downstream in subsonic
flow) of a well choke according to methods set forth in Sec. 98.234(b)
to calculate intermittent well flow rate of gas during venting to the
atmosphere or a flare. Calculate emissions using Equation W-11 of this
section for subsonic flow or Equation W-12 of this section for sonic
flow:
[GRAPHIC] [TIFF OMITTED] TR30NO10.183
Where:
FR = Average flow rate in cubic feet per hour, under subsonic flow
conditions.
A = Cross sectional area of orifice (m\2\).
P1 = Upstream pressure (psia).
Tu = Upstream temperature (degrees Kelvin).
P2 = Downstream pressure (psia).
3430 = Constant with units of m\2\/(sec\2\ * K).
1.27*10\5\ = Conversion from m\3\/second to ft\3\/hour.
[GRAPHIC] [TIFF OMITTED] TR30NO10.184
Where:
FR = Average flow rate in cubic feet per hour, under sonic flow
conditions.
A = Cross sectional area of orifice (m\2\).
Tu = Upstream temperature (degrees Kelvin).
187.08 = Constant with units of m\2\/(sec\2\ * K).
1.27*10\5\ = Conversion from m\3\/second to ft\3\/hour.
(A) The average flow rate in cubic feet per hour of venting across
the choke is calculated for one well completion in each gas producing
field and for one well workover in each gas producing field by
averaging the gas flow rates during venting to the atmosphere or
routing to a flare.
(B) The respective flow rates are applied to all well completions
in the gas producing field and to all well workovers in the gas
producing field for the total number of hours of venting of each of
these wells.
(C) Flow rates for completions and workovers in each field shall be
calculated once every two years for each
[[Page 74495]]
reporting gas producing field and geologic horizon in each gas
producing field starting in the first calendar year of data collection.
(D) Calculate total volumetric flow rate at standard conditions
using calculations in paragraph (t) of this section.
(2) The volume of CO2 or N2 injected into the
well reservoir during energized hydraulic fractures will be measured
using an appropriate meter as described in 98.234(b) or using receipts
of gas purchases that are used for the energized fracture job.
(i) Calculate gas volume at standard conditions using calculations
in paragraph (t) of this section.
(ii) [Reserved]
(3) The volume of recovered completion gas sent to a sales line
will be measured using existing company records. If data does not exist
on sales gas, then an appropriate meter as described in 98.234(b) may
be used.
(i) Calculate gas volume at standard conditions using calculations
in paragraph (t) of this section.
(ii) [Reserved]
(4) Both CH4 and CO2 volumetric and mass
emissions shall be calculated from volumetric total emissions using
calculations in paragraphs (u) and (v) of this section.
(5) Determine if the well completion or workover from hydraulic
fracturing recovered gas with purpose designed equipment that separates
saleable gas from the backflow, and sent this gas to a sales line (e.g.
reduced emissions completion).
(i) Use the factor SG in Equation W-10 of this section, to adjust
the emissions estimated in paragraphs (g)(1) through (g)(4) of this
section by the magnitude of emissions captured using reduced emission
completions as determined by engineering estimate based on best
available data.
(ii) [Reserved]
(6) Calculate annual emissions from gas well venting during well
completions and workovers from hydraulic fracturing to flares as
follows:
(i) Use the total gas well venting volume during well completions
and workovers as determined in paragraph (g) 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 using hydraulic fracturing emissions from the
flare. This adjustment to emissions from completions using flaring
versus completions without flaring accounts for the conversion of
CH4 to CO2 in the flare.
(h) Gas well venting during completions and workovers without
hydraulic fracturing. Calculate CH4, CO2 and
N2O (when flared) emissions from each gas well venting
during well completions and workovers not involving hydraulic
fracturing and well workovers not involving hydraulic fracturing using
Equation W-13 of this section:
[GRAPHIC] [TIFF OMITTED] TR30NO10.185
Where:
Ea,n = Annual natural gas emissions in cubic feet at
actual conditions from gas well venting during well completions and
workovers without hydraulic fracturing.
Nwo = Number of workovers per field not involving
hydraulic fracturing in the reporting year.
EFwo = Emission Factor for non-hydraulic fracture well
workover venting in actual cubic feet per workover. EFwo
= 2,454 standard cubic feet per well workover without hydraulic
fracturing.
f = Total number of well completions without hydraulic fracturing in
a field.
Vf = Average daily gas production rate in cubic feet per
hour of each well completion without hydraulic fracturing. This is
the total annual gas production volume divided by total number of
hours the wells produced to the sales line. For completed wells that
have not established a production rate, you may use the average flow
rate from the first 30 days of production. In the event that the
well is completed less than 30 days from the end of the calendar
year, the first 30 days of the production straddling the current and
following calendar years shall be used.
Tf = Time each well completion without hydraulic
fracturing was venting in hours during the year.
(1) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
(2) 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.
(3) Calculate annual emissions from gas well venting during well
completions and workovers not involving hydraulic fracturing to flares
as follows:
(i) Use the gas well venting volume during well completions and
workovers as determined in paragraph (h) 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 without hydraulic fracturing from
the flare.
(i) Blowdown vent stacks. Calculate CO2 and
CH4 blowdown vent stack emissions from depressurizing
equipment to the atmosphere (excluding depressurizing to a flare, over-
pressure relief, operating pressure control venting and blowdown of
non-GHG gases; desiccant dehydrator blowdown venting before reloading
is covered in paragraph (e)(5) of this section) as follows:
(1) Calculate the total volume (including pipelines, compressor
case or cylinders, manifolds, suction bottles, discharge bottles, and
vessels) between isolation valves determined by engineering estimate
based on best available data.
(2) If the total volume between isolation valves is greater than or
equal to 50 standard cubic feet, retain logs of the number of blowdowns
for each equipment type (including but not limited to compressors,
vessels, pipelines, headers, fractionators, and tanks). Blowdown
volumes smaller than 50 standard cubic feet are exempt from reporting
under paragraph (i) of this section.
(3) Calculate the total annual venting emissions for each equipment
type using Equation W-14 of this section:
[GRAPHIC] [TIFF OMITTED] TR30NO10.186
[[Page 74496]]
Where:
Es,n = Annual natural gas venting emissions at standard
conditions from blowdowns in cubic feet.
N = Number of repetitive blowdowns for each equipment type of a
unique volume in calendar year.
Vv = Total volume of blowdown equipment chambers
(including pipelines, compressors and vessels) between isolation
valves in cubic feet.
C = Purge factor that is 1 if the equipment is not purged or zero if
the equipment is purged using non-GHG gases.
Ts = Temperature at standard conditions ([deg]F).
Ta = Temperature at actual conditions in the blowdown
equipment chamber ([deg]F).
Ps = Absolute pressure at standard conditions (psia).
Pa = Absolute pressure at actual conditions in the
blowdown equipment chamber (psia).
(4) Calculate both CH4 and CO2 mass emissions
from volumetric natural gas emissions using calculations in paragraph
(v) of this section.
(5) Calculate total annual venting emissions for all blowdown vent
stacks by adding all standard volumetric and mass emissions determined
in Equation W-14 and paragraph (i)(4) of this section.
(j) Onshore production storage tanks. Calculate CH4,
CO2 and N2O (when flared) emissions from
atmospheric pressure fixed roof storage tanks receiving hydrocarbon
produced liquids from onshore petroleum and natural gas production
facilities (including stationary liquid storage not owned or operated
by the reporter), calculate annual CH4 and CO2
emissions using any of the calculation methodologies described in this
paragraph (j).
(1) Calculation Methodology 1. For separators with oil throughput
greater than or equal to 10 barrels per day. Calculate annual
CH4 and CO2 emissions from onshore production
storage tanks using operating conditions in the last wellhead gas-
liquid separator before liquid transfer to storage tanks. Calculate
flashing emissions with a software program, such as AspenTech
HYSYS[supreg] or API 4697 E&P Tank, that uses the Peng-Robinson
equation of state, models flashing emissions, and speciates
CH4 and CO2 emissions that will result when the
oil from the separator enters an atmospheric pressure storage tank. A
minimum of the following parameters determined for typical operating
conditions over the year by engineering estimate and process knowledge
based on best available data must be used to characterize emissions
from liquid transferred to tanks.
(i) Separator temperature.
(ii) Separator pressure.
(iii) Sales oil or stabilized oil API gravity.
(iv) Sales oil or stabilized oil production rate.
(v) Ambient air temperature.
(vi) Ambient air pressure.
(vii) Separator oil composition and Reid vapor pressure. If this
data is not available, determine these parameters by selecting one of
the methods described under paragraph (j)(1)(viii) of this section.
(A) If separator oil composition and Reid vapor pressure default
data are provided with the software program, select the default values
that most closely match your separator pressure first, and API gravity
secondarily.
(B) If separator oil composition and Reid vapor pressure data are
available through your previous analysis, select the latest available
analysis that is representative of produced crude oil or condensate
from the field.
(C) Analyze a representative sample of separator oil in each field
for oil composition and Reid vapor pressure using an appropriate
standard method published by a consensus-based standards organization.
(2) Calculation Methodology 2. Calculate annual CH4 and
CO2 emissions from onshore production storage tanks for
wellhead gas-liquid separators with oil throughput greater than or
equal to 10 barrels per day by assuming that all of the CH4
and CO2 in solution at separator temperature and pressure is
emitted from oil sent to storage tanks. You may use an appropriate
standard method published by a consensus-based standards organization
if such a method exists or you may use an industry standard practice as
described in Sec. 98.234(b)(1) to sample and analyze separator oil
composition at separator pressure and temperature.
(3) Calculation Methodology 3. For wells with oil production
greater than or equal to 10 barrels per day that flow directly to
atmospheric storage tanks without passing through a wellhead separator,
calculate CH4 and CO2 emissions by either of the
methods in paragraph (j)(3) of this section:
(i) If well production oil and gas compositions are available
through your previous analysis, select the latest available analysis
that is representative of produced oil and gas from the field and
assume all of the CH4 and CO2 in both oil and gas
are emitted from the tank.
(ii) If well production oil and gas compositions are not available,
use default oil and gas compositions in software programs, such as API
4697 E&P Tank, that most closely match your well production gas/oil
ratio and API gravity and assume all of the CH4 and
CO2 in both oil and gas are emitted from the tank.
(4) Calculation Methodology 4. For wells with oil production
greater than or equal to 10 barrels per day that flow to a separator
not at the well pad, calculate CH4 and CO2
emissions by either of the methods in paragraph (j)(4) of this section:
(i) If well production oil and gas compositions are available
through your previous analysis, select the latest available analysis
that is representative of oil at separator pressure determined by best
available data and assume all of the CH4 and CO2
in the oil is emitted from the tank.
(ii) If well production oil composition is not available, use
default oil composition in software programs, such as API 4697 E&P
Tank, that most closely match your well production API gravity and
pressure in the off-well pad separator determined by best available
data. Assume all of the CH4 and CO2 in the oil
phase is emitted from the tank.
(5) Calculation Methodology 5. For well pad gas-liquid separators
and for wells flowing off a well pad without passing through a gas-
liquid separator with throughput less than 10 barrels per day use
Equation W-15 of this section:
[GRAPHIC] [TIFF OMITTED] TR30NO10.187
Where:
Es,i = Annual total volumetric GHG emissions (either
CO2 or CH4) at standard conditions in cubic
feet.
EFi = Populations emission factor for separators and
wells in thousand standard cubic feet per separator or well per
year, for crude oil use 4.3 for CH4 and 2.9 for
CO2 at 68 [deg]F and 14.7 psia, and for gas condensate
use 17.8 for CH4 and 2.9 for CO2 at 68 [deg]F
and 14.7 psia.
Count = Total number of separators and wells with throughput less
than 10 barrels per day.
(6) Determine if the storage tank receiving your separator oil has
a vapor recovery system.
(i) Adjust the emissions estimated in paragraphs (j)(1) through
(j)(5) of this section downward by the magnitude of emissions recovered
using a vapor recovery system as determined by engineering estimate
based on best available data.
(ii) [Reserved]
(7) Determine if the storage tank receiving your separator oil is
sent to flare(s).
(i) Use your separator flash gas volume and gas composition as
determined in this section.
(ii) Use the calculation methodology of flare stacks in paragraph
(n) of this
[[Page 74497]]
section to determine your contribution to storage tank emissions from
the flare.
(8) Calculate emissions from occurrences of well pad gas-liquid
separator liquid dump valves not closing during the calendar year by
using Equation W-16 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.188
Where:
Es,i = Annual total volumetric GHG emissions at standard
conditions from each storage tank in cubic feet.
En = Storage tank emissions as determined in Calculation
Methodologies 1, 2, or 5 in paragraphs (j)(1) through (j)(5) of this
section (with wellhead separators) during time Tn in
cubic feet per hour.
Tn = Total time the dump valve is not closing properly in
the calendar year in hours. Tn is estimated by
maintenance or operations records (records) such that when a record
shows the valve to be open improperly, it is assumed the valve was
open for the entire time period preceding the record starting at
either the beginning of the calendar year or the previous record
showing it closed properly within the calendar year. If a subsequent
record shows it is closing properly, then assume from that time
forward the valve closed properly until either the next record of it
not closing properly or, if there is no subsequent record, the end
of the calendar year.
CFn = Correction factor for tank emissions for time
period Tn is 3.87 for crude oil production. Correction
factor for tank emissions for time period Tn is 5.37 for
gas condensate production. Correction factor for tank emissions for
time period Tn is 1.0 for periods when the dump valve is
closed.
Et = Storage tank emissions as determined in Calculation
Methodologies 1, 2, or 3 in paragraphs (j)(1) through (j)(5) of this
section at maintenance or operations during the time the dump valve
is closing properly (ie. 8760-Tn) in cubic feet per hour.
(9) Calculate both CH4 and CO2 mass emissions
from volumetric natural gas emissions using calculations in paragraph
(v) of this section.
(k) Transmission storage tanks. For condensate storage tanks,
either water or hydrocarbon, without vapor recovery or thermal control
devices in onshore natural gas transmission compression facilities
calculate CH4, CO2 and N2O (when
flared) annual emissions from compressor scrubber dump valve leakage as
follows:
(1) Monitor the tank vapor vent stack annually for emissions using
an optical gas imaging instrument according to methods set forth in
Sec. 98.234(a)(1) for a duration of 5 minutes. Or you may annually
monitor leakage through compressor scrubber dump valve(s) into the tank
using an acoustic leak detection device according to methods set forth
in Sec. 98.234(a)(5).
(2) If the tank vapors are continuous for 5 minutes, or the
acoustic leak detection device detects a leak, then use one of the
following two methods in paragraph (k)(2) of this section to quantify
emissions:
(i) Use a meter, such as a turbine meter, to estimate tank vapor
volumes according to methods set forth in Sec. 98.234(b). If you do
not have a continuous flow measurement device, you may install a flow
measuring device on the tank vapor vent stack.
(ii) Use an acoustic leak detection device on each scrubber dump
valve connected to the tank according to the method set forth in Sec.
98.234(a)(5).
(iii) Use the appropriate gas composition in paragraph (u)(2)(iii)
of this section.
(3) If the leaking dump valve(s) is fixed following leak detection,
the annual emissions shall be calculated from the beginning of the
calendar year to the time the valve(s) is repaired.
(4) Calculate emissions from storage tanks to flares as follows:
(i) Use the storage tank emissions volume and gas composition as
determined in either paragraph (j)(1)of this section or with an
acoustic leak detection device in paragraphs (k)(1) through (k)(3) 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 CH4,
CO2 and N2O (when flared) well testing venting
and flaring emissions as follows:
(1) Determine the gas to oil ratio (GOR) of the hydrocarbon
production from each well tested.
(2) If GOR cannot be determined from your available data, then you
must measure quantities reported in this section according to one of
the two procedures in paragraph (l)(2) of this section to determine
GOR:
(i) You may use an appropriate standard method published by a
consensus-based standards organization if such a method exists.
(ii) Or you may use an industry standard practice as described in
Sec. 98.234(b).
(3) Estimate venting emissions using Equation W-17 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.189
Where:
Ea,n = Annual volumetric natural gas emissions from well
testing in cubic feet under actual 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.
(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.
(6) 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 CH4,
CO2 and N2O (when flared) associated gas venting
and flaring emissions not in conjunction with well testing (refer to
paragraph (l): Well testing venting and flaring of this section) as
follows:
(1) Determine the GOR of the hydrocarbon production from each well
whose associated natural gas is vented or flared. If GOR from each well
is not available, the GOR from a cluster of wells in the same field
shall be used.
[[Page 74498]]
(2) If GOR cannot be determined from your available data, then use
one of the two procedures in paragraph (m)(2) of this section to
determine GOR:
(i) You may use an appropriate standard method published by a
consensus-based standards organization if such a method exists.
(ii) Or you may use an industry standard practice as described in
Sec. 98.234(b).
(3) Estimate venting emissions using Equation W-18 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.190
Where:
Ea,n = Annual volumetric natural gas emissions from
associated gas venting under actual 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 = Volume of oil produced in barrels in the calendar year during
which associated gas was vented or flared.
(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.
(6) Calculate emissions from associated natural gas to flares as
follows:
(i) Use the associated natural gas volume and gas composition as
determined in paragraph (m)(1) through (4) 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 stack emissions. Calculate CO2,
CH4, and N2O 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 all of the flare gas is not measured by the existing flow
measurement device, then the flow not measured can be estimated using
engineering calculations based on best available data or company
records. 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 based on process knowledge, company records,
and best available data.
(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) For onshore natural gas production, determine natural gas
composition using (u)(2)(i) of this section.
(ii) For onshore natural gas processing, when the stream going to
flare is natural gas, use the GHG mole percent in feed natural gas for
all streams upstream of the de-methanizer or dew point control, and GHG
mole percent in facility specific residue gas to transmission pipeline
systems for all emissions sources downstream of the de-methanizer
overhead or dew point control for onshore natural gas processing
facilities.
(iii) When the stream going to the flare is a hydrocarbon product
stream, such as ethane, propane, butane, pentane-plus and mixed light
hydrocarbons, then use a representative composition from the source for
the stream determined by engineering calculation based on process
knowledge and best available data.
(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-19, W-20, and W-21 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.191
Where:
Ea,CH4(un-combusted) = Contribution of annual un-
combusted CH4 emissions from flare stack in cubic feet,
under actual conditions.
Ea,CO2(un-combusted) = Contribution of annual un-
combusted CO2 emissions from flare stack in cubic feet,
under actual conditions.
Ea,CO2(combusted) = Contribution of annual combusted
CO2 emissions from flare stack in cubic feet, under
actual conditions.
Va = Volume of gas sent to flare in cubic feet, during
the year.
[eta] = Fraction of gas combusted by a burning flare (default is
0.98). For gas sent to an unlit flare, [eta] is zero.
XCH4 = Mole fraction of CH4 in gas to the
flare.
XCO2 = Mole fraction of CO2 in gas to the
flare.
Yj = Mole fraction of gas hydrocarbon constituents j
(such as methane, ethane, propane, butane, and pentanes-plus).
Rj = Number of carbon atoms in the 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.
(7) Calculate total annual emission from flare stacks by summing
Equation W-40, Equation W-19, Equation W-20 and Equation W-21 of this
section.
(8) Calculate N2O emissions from flare stacks using
Equation W-40 in paragraph (z) of this section.
(9) The flare emissions determined under paragraph (n) of this
section must be corrected for flare emissions calculated and reported
under other paragraphs of this section to avoid double counting of
these emissions.
(o) Centrifugal compressor venting. Calculate CH4,
CO2 and N2O (when flared) emissions from both wet
seal and dry seal centrifugal compressor vents as follows:
(1) For each centrifugal compressor covered by Sec. 98.232 (d)(2),
(e)(2), (f)(2), (g)(2), and (h)(2) you must conduct an annual
measurement in the operating mode in which it is found. Measure
emissions from all vents (including emissions manifolded to common
vents)
[[Page 74499]]
including wet seal oil degassing vents, unit isolation valve vents, and
blowdown valve vents. Record emissions from the following vent types in
the specified compressor modes during the annual measurement.
(i) Operating mode, blowdown valve leakage through the blowdown
vent, wet seal and dry seal compressors.
(ii) Operating mode, wet seal oil degassing vents.
(iii) Not operating, depressurized mode, unit isolation valve
leakage through open blowdown vent, without blind flanges, wet seal and
dry seal compressors.
(A) For the not operating, depressurized mode, each compressor must
be measured at least once in any three consecutive calendar years. If a
compressor is not operated and has blind flanges in place throughout
the 3 year period, measurement is not required in this mode. If the
compressor is in standby depressurized mode without blind flanges in
place and is not operated throughout the 3 year period, it must be
measured in the standby depressurized mode.
(2) For wet seal oil degassing vents, determine vapor volumes sent
to an atmospheric vent or flare, using a temporary meter such as a vane
anemometer or permanent flow meter according to 98.234(b) of this
section. If you do not have a permanent flow meter, you may install a
permanent flow meter on the wet seal oil degassing tank vent.
(3) For blowdown valve leakage and unit isolation valve leakage to
open ended vents, you can use one of the following methods: Calibrated
bagging or high volume sampler according to methods set forth in Sec.
98.234(c) and Sec. 98.234(d), respectively. For through valve leakage,
such as isolation valves, you may use an acoustic leak detection device
according to methods set forth in Sec. 98.234(a). If you do not have a
flow meter, you may install a port for insertion of a temporary meter,
or a permanent flow meter, on the vents.
(4) Estimate annual emissions using the flow measurement and
Equation W-22 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.192
Where:
Es,i,m = Annual GHGi (either CH4 or
CO2) volumetric emissions at standard conditions, in
cubic feet.
MTm = Measured gas emissions in standard cubic feet per
hour.
Tm = Total time the compressor is in the mode for which
Es,i is being calculated, in the calendar year in hours.
Mi,m = Mole fraction of GHGi in the vent gas;
use the appropriate gas compositions in paragraph (u)(2) of this
section.
Bm = Fraction of operating time that the vent gas is sent
to vapor recovery or fuel gas as determined by keeping logs of the
number of operating hours for the vapor recovery system and the time
that vent gas is directed to the fuel gas system or sales.
(5) Calculate annual emissions from each centrifugal compressor
using Equation W-23 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.193
Where:
Es,i = Annual total volumetric GHG emissions at standard
conditions from each centrifugal compressor in cubic feet.
EFm = Reporter emission factor for each mode m, in cubic
feet per hour, from Equation W-24 of this section as calculated in
paragraph 6.
Tm = Total time in hours per year the compressor was in
each mode, as listed in paragraph (o)(1)(i) through (o)(1)(iii).
GHGi = For 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(a)(4) through (a)(8),GHGi equals
1.
(6) You shall use the flow measurements of operating mode wet seal
oil degassing vent, operating mode blowdown valve vent and not
operating depressurized mode isolation valve vent for all the
reporter's compressor modes not measured in the calendar year to
develop the following emission factors using Equation W-24 of this
section for each emission source and mode as listed in paragraph
(o)(1)(i) through (o)(1)(iii).
[GRAPHIC] [TIFF OMITTED] TR30NO10.194
Where:
EFm = Reporter emission factors for compressor in the
three modes m (as listed in paragraph (o)(1)(i) through (o)(1)(iii))
in cubic feet per hour.
MTm = Flow Measurements from all centrifugal compressor
vents in each mode in (o)(1)(i) through (o)(1)(iii) of this section
in cubic feet per hour.
Countm = Total number of compressors measured.
m = Compressor mode as listed in paragraph (o)(1)(i) through
(o)(1)(iii).
(i) The emission factors must be calculated annually. You must use
all measurements from the current calendar year and the preceding two
calendar years, totaling three consecutive calendar years of
measurements in paragraph (o)(6) of this section.
(ii) [Reserved]
(7) Onshore petroleum and natural gas production shall calculate
emissions from centrifugal compressor wet seal oil degassing vents as
follows:
[GRAPHIC] [TIFF OMITTED] TR30NO10.195
[[Page 74500]]
Where:
Es,i = Annual total volumetric GHG emissions at standard
conditions from centrifugal compressor wet seals in cubic feet.
Count = Total number of centrifugal compressors for the reporter.
EFi = Emission factor for GHG i. Use 12.2
million standard cubic feet per year per compressor for
CH4 and 538 thousand standard cubic feet per year per
compressor for CO2 at 68[deg]F and 14.7 psia or 12
million standard cubic feet per year per compressor for
CH4 and 530 thousand standard cubic feet per year per
compressor for CO2 at 60[deg]F and 14.7 psia.
(8) Calculate both CH4 and CO2 mass emissions
from volumetric emissions using calculations in paragraph (v) of this
section.
(9) Calculate emissions from seal oil degassing vent vapors to
flares as follows:
(i) Use the seal oil degassing vent vapor volume and gas
composition as determined in paragraphs (o)(5) 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 venting. Calculate CH4 and
CO2 emissions from all reciprocating compressor vents as
follows. For each reciprocating compressor covered in Sec.
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1) you must conduct an
annual measurement for each compressor in the mode in which it is found
during the annual measurement, except as specified in paragraph (p)(9)
of this section. Measure emissions from (including emissions manifolded
to common vents) reciprocating rod packing vents, unit isolation valve
vents, and blowdown valve vents. Record emissions from the following
vent types in the specified compressor modes during the annual
measurement as follows:
(1) Operating or standby pressurized mode, blowdown vent leakage
through the blowdown vent stack.
(2) Operating mode, reciprocating rod packing emissions.
(3) Not operating, depressurized mode, unit isolation valve leakage
through the blowdown vent stack, without blind flanges.
(i) For the not operating, depressurized mode, each compressor must
be measured at least once in any three consecutive calendar years if
this mode is not found in the annual measurement. If a compressor is
not operated and has blind flanges in place throughout the 3 year
period, measurement is not required in this mode. If the compressor is
in standby depressurized mode without blind flanges in place and is not
operated throughout the 3 year period, it must be measured in the
standby depressurized mode.
(ii) [Reserved]
(4) If reciprocating rod packing and blowdown vent are connected to
an open-ended vent line 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 vents using either calibrated bagging or high
volume sampler according to methods set forth in Sec. 98.234(c) and
Sec. 98.234(d), respectively.
(ii) Use a temporary meter such as a vane anemometer or a permanent
meter such as an orifice meter to measure emissions from all vents
(including emissions manifolded to a common vent) including rod packing
vents and unit isolation valve leakage through blowdown vents according
to methods set forth in Sec. 98.234(b). If you do not have a permanent
flow meter, you may install a port for insertion of a temporary meter
or a permanent flow meter on the vents. For through-valve leakage to
open ended vents, such as unit isolation valves on not operating,
depressurized compressors and blowdown valves on pressurized
compressors, you may use an acoustic detection device according to
methods set forth in Sec. 98.234(a).
(5) If reciprocating rod packing is not equipped with a vent line
use the following method to calculate emissions:
(i) You must use the methods described in Sec. 98.234(a) to
conduct annual leak detection of equipment leaks from the packing case
into an open distance piece, or from the compressor crank case breather
cap or other vent with a closed distance piece.
(ii) Measure emissions found in paragraph (p)(5)(i) of this section
using an appropriate meter, or calibrated bag, or high volume sampler
according to methods set forth in Sec. 98.234(b), (c), and (d),
respectively.
(6) Estimate annual emissions using the flow measurement and
Equation W-26 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.196
Where:
Es,i,m = Annual GHG i (either CH4 or
CO2) volumetric emissions at standard conditions, in
cubic feet.
MTm = Measured gas emissions in standard cubic feet per
hour.
Tm = Total time the compressor is in the mode for which
Es,i,m is being calculated, in the calendar year in
hours.
Mi,m = Mole fraction of GHG i in gas; use the appropriate
gas compositions in paragraph (u)(2) of this section.
(7) Calculate annual emissions from each reciprocating compressor
using Equation W-27 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.197
Where:
Es,i = Annual total volumetric GHG emissions at standard
conditions from each reciprocating compressor in cubic feet.
EFm = Reporter emission factor for each mode, m, in cubic
feet per hour, from Equation W-28 of this section as calculated in
paragraph (p)(7)(i) of this section.
Tm = Total time in hours per year the compressor was in
each mode, m, as listed in paragraph (p)(1) through (p)(3).
GHGi = For 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(a)(4) through (a)(8), GHGi equals
1.
m = Compressor mode as listed in paragraph (p)(1) through (p)(3).
(i) You shall use the flow meter readings from measurements of
operating and standby pressurized blowdown vent, operating mode vents,
not operating depressurized isolation valve vent for all the reporter's
compressor modes not measured in the
[[Page 74501]]
calendar year to develop the following emission factors using Equation
W-28 of this section for each mode as listed in paragraph (p)(1)
through (p)(3).
[GRAPHIC] [TIFF OMITTED] TR30NO10.198
Where:
EFm = Reporter emission factors for compressor in the
three modes, m, in cubic feet per hour.
MTm = Meter readings from all reciprocating compressor
vents in each and mode, m, in cubic feet per hour.
Countm = Total number of compressors measured in each
mode, m.
m = Compressor mode as listed in paragraph (p)(1) through (p)(3).
(A) You must combine emissions for blowndown vents, measured in the
operating and standby pressurized modes.
(B) The emission factors must be calculated annually. You must use
all measurements from the current calendar year and the preceding two
calendar years, totaling three consecutive calendar years of
measurements.
(ii) [Reserved]
(8) Determine if the reciprocating compressor vent vapors are sent
to a vapor recovery system.
(i) Adjust the emissions estimated in paragraphs (p)(7) of this
section downward by the magnitude of emissions recovered using a vapor
recovery system as determined by engineering estimate based on best
available data.
(ii) [Reserved]
(9) Onshore petroleum and natural gas production shall calculate
emissions from reciprocating compressors as follows:
[GRAPHIC] [TIFF OMITTED] TR30NO10.199
Where:
Es,i = Annual total volumetric GHG emissions at standard
conditions from reciprocating compressors in cubic feet.
Count = Total number of reciprocating compressors for the reporter.
EFi = Emission factor for GHG i. Use 9.63 thousand
standard cubic feet per year per compressor for CH4 and
0.535 thousand standard cubic feet per year per compressor for
CO2 at 68[deg]F and 14.7 psia or 9.48 thousand standard
cubic feet per year per compressor for CH4 and 0.527
thousand standard cubic feet per year per compressor for
CO2 at 60[deg]F and 14.7 psia.
(10) 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 leak detection(s) of
equipment leaks from all sources listed in Sec. 98.232(d)(7), (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. Tubing systems
equal to or less than one half inch diameter are exempt from the
requirements of this paragraph (q) and do not need to be reported. If
equipment leaks are detected for sources listed in this paragraph (q),
calculate emissions using Equation W-30 of this section for each source
with equipment leaks.
[GRAPHIC] [TIFF OMITTED] TR30NO10.200
Where:
Es,i = Annual total volumetric GHG emissions at standard
conditions from each equipment leak source in cubic feet.
x = Total number of this type of emissions source found to be
leaking during Tx.
EFs = 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)(4) through (a)(8),
GHGi equals 1 for CH4 and 1.1 x
10-2 for CO2.
Tx = The total time the component was found leaking and
operational, in hours. If one leak detection survey is conducted,
assume the component was leaking for the entire calendar year. If
multiple leak detection surveys are conducted, assume that the
component found to be leaking has been leaking since the previous
survey or the beginning of the calendar year. For the last leak
detection survey in the calendar year, assume that all leaking
components continue to leak until the end of the calendar year.
(1) You must select to conduct either one leak detection survey in
a calendar year or multiple complete leak detection surveys in a
calendar year. The number of leak detection surveys selected must be
conducted during the calendar year.
(2) Calculate GHG mass emissions in carbon dioxide equivalent at
standard conditions using calculations in paragraph (v) of this
section.
(3) Onshore natural gas processing facilities shall use the
appropriate default leaker emission factors listed in Table W-2 of this
subpart for equipment leaks detected from valves, connectors, open
ended lines, pressure relief valves, and meters.
(4) Onshore natural gas transmission compression facilities shall
use the appropriate default leaker emission factors listed in Table W-3
of this subpart for equipment leaks detected from valves, connectors,
open ended lines, pressure relief valves, and meters.
(5) 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 equipment leaks detected from valves,
connectors, open ended lines, pressure relief valves, and meters.
(6) LNG storage facilities shall use the appropriate default leaker
emission factors listed in Table W-5 of this subpart for equipment
leaks detected from valves, pump seals, connectors, and other.
(7) LNG import and export facilities shall use the appropriate
default leaker emission factors listed in Table W-6 of this subpart for
equipment leaks detected from valves, pump seals, connectors, and
other.
(8) Natural gas distribution facilities for above ground meters and
regulators at city gate stations at custody transfer, shall use the
appropriate default leaker emission factors listed in Table W-7 of this
subpart for equipment leak detected from connectors, block valves,
control valves, pressure relief valves, orifice meters, regulators, and
open ended lines.
(r) Population count and emission factors. This paragraph applies
to emissions sources listed in Sec. 98.232 (c)(21), (f)(5), (g)(3),
(h)(4), (i)(2), (i)(3), (i)(4) and (i)(5), 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. Tubing systems equal or less than one half inch diameter are
exempt from the requirements of paragraph (r) of this section and do
not need to be reported. Calculate emissions from all sources listed in
this paragraph using Equation W-31 of this section.
[[Page 74502]]
[GRAPHIC] [TIFF OMITTED] TR30NO10.201
Where:
Es,i = Annual volumetric GHG emissions at standard
conditions from each equipment leak source in cubic feet.
Counts = Total number of this type of emission source at
the facility. Average component counts are provided by major
equipment piece in Tables W-1B and Table W-1C of this subpart. Use
average component counts as appropriate for operations in Eastern
and Western U.S., according to Table W-1D of this subpart.
EFs = Population emission factor for the specific source,
s listed in Table W-1A and Tables W-3 through Table W-7 of this
subpart. Use appropriate population emission factor for operations
in Eastern and Western U.S., according to Table W-1D of this
subpart. EF for non-custody transfer city gate stations is
determined in Equation W-32.
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(a)(4) through (a)(8), GHGi equals
1 for CH4 and 1.1 x 10-2 for CO2.
Ts = Total time the specific source s associated with the
equipment leak emission was operational in the calendar 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-1A of this subpart for equipment leaks from valves, connectors, open
ended lines, pressure relief valves, pump, flanges, and other. Major
equipment and components associated with gas wells are considered gas
service components in reference to Table 1-A of this subpart and major
natural gas equipment in reference to Table W-1B of this subpart. Major
equipment and components associated with crude oil wells are considered
crude service components in reference to Table 1-A of this subpart and
major crude oil equipment in reference to Table W-1C of this subpart.
Where facilities conduct EOR operations the emissions factor listed in
Table W-1A of this subpart shall be used to estimate all streams of
gases, including recycle CO2 stream. The component count can
be determined using either of the methodologies described in this
paragraph (r)(2). The same methodology must be used for the entire
calendar year.
(i) Component Count Methodology 1. For all onshore petroleum and
natural gas production operations in the facility perform the following
activities:
(A) Count all major equipment listed in Table W-1B and Table W-1C
of this subpart.
(B) Multiply major equipment counts by the average component counts
listed in Table W-1B and W-1C of this subpart for onshore natural gas
production and onshore oil production, respectively. Use the
appropriate factor in Table W-1A of this subpart for operations in
Eastern and Western U.S. according to the mapping in Table W-1D of this
subpart.
(ii) Component Count Methodology 2. Count each component
individually for the facility. Use the appropriate factor in Table W-1A
of this subpart for operations in Eastern and Western U.S. according to
the mapping in Table W-1D of this subpart.
(3) 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 equipment leak from connectors,
valves, pressure relief valves, and open ended lines.
(4) LNG storage facilities shall use the appropriate default
population emission factors listed in Table W-5 of this subpart for
equipment leak from vapor recovery compressors.
(5) LNG import and export facilities shall use the appropriate
default population emission factor listed in Table W-6 of this subpart
for equipment leak from vapor recovery compressors.
(6) Natural gas distribution facilities shall use the appropriate
emission factors as described in paragraph (r)(6) of this section.
(i) Below grade meters and regulators; mains; and services, shall
use the appropriate default population emission factors listed in Table
W-7 of this subpart.
(ii) Above grade meters and regulators at city gate stations not at
custody transfer as listed in Sec. 98.232(i)(2), shall use the total
volumetric GHG emissions at standard conditions for all equipment leak
sources calculated in paragraph (q)(8) of this section to develop
facility emission factors using Equation W-32 of this section. The
calculated facility emission factor from Equation W-32 of this section
shall be used in Equation W-31 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.202
Where:
EF = Facility emission factor for a meter at above grade M&R at city
gate stations not at custody transfer in cubic feet per meter per
year.
Es,i = Annual volumetric GHG emissions at standard
condition from all equipment leak sources at all above grade M&R
city gate stations at custody transfer, from paragraph (q) of this
section.
Count = Total number of meter runs at all above grade M&R city gate
stations at custody transfer.
(s) Offshore petroleum and natural gas production facilities.
Report CO2, CH4, and N2O emissions for
offshore petroleum and natural gas production from all equipment leaks,
vented emission, and flare emission source types as identified in the
data collection and emissions estimation study conducted by BOEMRE in
compliance with 30 CFR 250.302 through 304.
(1) Offshore production facilities under BOEMRE jurisdiction shall
report the same annual emissions as calculated and reported by BOEMRE
in data collection and emissions estimation study published by BOEMRE
referenced in 30 CFR 250.302 through 304 (GOADS).
(i) For any calendar year that does not overlap with the most
recent BOEMRE emissions study publication year, report the most recent
BOEMRE reported emissions data published by BOEMRE referenced in 30 CFR
250.302 through 304 (GOADS). Adjust emissions based on the operating
time for the facility relative to the operating time in the most recent
BOEMRE published study.
(ii) [Reserved]
(2) Offshore production facilities that are not under BOEMRE
jurisdiction shall use monitoring methods and calculation methodologies
published by BOEMRE referenced in 30 CFR 250.302 through 304 to
calculate and report emissions (GOADS).
(i) For any calendar year that does not overlap with the most
recent BOEMRE emissions study publication, report the
[[Page 74503]]
most recent reported emissions data with emissions adjusted based on
the operating time for the facility relative to operating time in the
previous reporting period.
(ii) [Reserved]
(3) If BOEMRE discontinues or delays their data collection effort
by more than 4 years, then offshore reporters shall once in every 4
years use the most recent BOEMRE data collection and emissions
estimation methods to report emission from the facility sources.
(4) For either first or subsequent year reporting, offshore
facilities either within or outside of BOEMRE jurisdiction that were
not covered in the previous BOEMRE data collection cycle shall use the
most recent BOEMRE data collection and emissions estimation methods
published by BOEMRE referenced in 30 CFR 250.302 through 304 to
calculate and report emissions (GOADS) to report emissions.
(t) Volumetric emissions. Calculate volumetric emissions at
standard conditions as specified in paragraphs (t)(1) or (2) of this
section determined by engineering estimate based on best available data
unless otherwise specified.
(1) Calculate natural gas volumetric emissions at standard
conditions by converting actual temperature and pressure of natural gas
emissions to standard temperature and pressure of natural gas using
Equation W-33 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.203
Where:
Es,n = Natural gas volumetric emissions at standard
temperature and pressure (STP) conditions in cubic feet.
Ea,n = Natural gas volumetric emissions at actual
conditions in cubic feet.
Ts = Temperature at standard conditions ([deg]F).
Ta = Temperature at actual emission conditions ([deg]F).
Ps = Absolute pressure at standard conditions (psia).
Pa = Absolute pressure at actual conditions (psia).
(2) Calculate GHG volumetric emissions at standard conditions by
converting actual temperature and pressure of GHG emissions to standard
temperature and pressure using Equation W-34 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.204
Where:
Es,i = GHG i volumetric emissions at standard temperature
and pressure (STP) conditions in cubic feet.
Ea,i = GHG i volumetric emissions at actual conditions in
cubic feet.
Ts = Temperature at standard conditions ([deg]F).
Ta = Temperature at actual emission conditions ([deg]F).
Ps = Absolute pressure at standard conditions (psia).
Pa = Absolute pressure at actual conditions (psia).
(u) GHG volumetric emissions. Calculate GHG volumetric emissions at
standard conditions as specified in paragraphs (u)(1) and (2) of this
section determined by engineering estimate based on best available data
unless otherwise specified.
(1) Estimate CH4 and CO2 emissions from
natural gas emissions using Equation W-35 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.205
Where:
Es,i = GHG i (either CH4 or CO2)
volumetric emissions at standard conditions in cubic feet.
Es,n = Natural gas volumetric emissions at standard
conditions in cubic feet.
Mi = Mole fraction of GHG i in the natural gas.
(2) For Equation W-35 of this section, the mole fraction,
Mi, shall be the annual average mole fraction for each
facility, as specified in paragraphs (u)(2)(i) through (vii) of this
section.
(i) GHG mole fraction in produced natural gas for onshore petroleum
and natural gas production facilities. If you have a continuous gas
composition analyzer for produced natural gas, you must use these
values for determining the mole fraction. If you do not have a
continuous gas composition analyzer, then you must use your most recent
gas composition based on available sample analysis of the field.
(ii) GHG mole fraction in feed natural gas for all emissions
sources upstream of the de-methanizer or dew point control and GHG mole
fraction in facility specific residue gas to transmission pipeline
systems for all emissions sources downstream of the de-methanizer
overhead or dew point control for onshore natural gas processing
facilities. If you have a continuous gas composition analyzer on feed
natural gas, you must use these values for determining the mole
fraction. If you do not have a continuous gas composition analyzer,
then annual samples must be taken according to methods set forth in
Sec. 98.234(b).
(iii) GHG mole fraction in transmission pipeline natural gas that
passes through the facility for onshore natural gas transmission
compression facilities.
(iv) GHG mole fraction in natural gas stored in underground natural
gas storage facilities.
(v) GHG mole fraction in natural gas stored in LNG storage
facilities.
(vi) GHG mole fraction in natural gas stored in LNG import and
export facilities.
(vii) GHG mole fraction 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-36 of this
section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.206
[[Page 74504]]
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. Use 0.0538 kg/ft\3\ for
CO2 and N2O, and 0.0196 kg/ft\3\ for
CH4 at 68[deg]F and 14.7 psia or 0.0530 kg/ft\3\ for
CO2 and N2O, and 0.0193 kg/ft\3\ for
CH4 at 60[deg]F and 14.7 psia.
GWP = Global warming potential, 1 for CO2, 21 for
CH4, and 310 for N2O.
(w) EOR injection pump blowdown. Calculate CO2 pump
blowdown emissions as follows:
(1) Calculate the total volume in cubic feet (including pipelines,
manifolds and vessels) between isolation valves.
(2) Retain logs of the number of blowdowns per calendar year.
(3) Calculate the total annual venting emissions using Equation W-
37 of this section:
[GRAPHIC] [TIFF OMITTED] TR30NO10.207
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 the calendar year.
Vv = Total volume in cubic feet of blowdown equipment
chambers (including pipelines, manifolds and vessels) between
isolation valves.
Rc = Density of critical phase EOR injection gas in kg/
ft\3\. You may use an appropriate standard method published by a
consensus-based standards organization if such a method exists or
you may use an industry standard practice to determine density of
super critical EOR injection gas.
GHGi = Mass fraction of GHGi in critical phase
injection gas.
1 x 10-3 = Conversion factor from kilograms to metric
tons.
(x) EOR hydrocarbon liquids dissolved CO2. Calculate
dissolved CO2 in hydrocarbon liquids produced through EOR
operations as follows:
(1) Determine the amount of CO2 retained in hydrocarbon
liquids after flashing in tankage at STP conditions. Annual 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 annual analysis for
the calendar year.
(2) Estimate emissions using Equation W-38 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.208
Where:
Masss,CO2 = Annual CO2 emissions from
CO2 retained in hydrocarbon liquids produced through EOR
operations 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 at the
EOR operations in barrels in the calendar year.
(y) [Reserved]
(z) Onshore petroleum and natural gas production and natural gas
distribution combustion emissions. Calculate CO2
CH4,and N2O combustion-related emissions from
stationary or portable equipment as follows:
(1) If the fuel combusted in the stationary or portable equipment
is listed in Table C-1 of subpart C of this part, or is a blend of
fuels listed in Table C-1, use the Tier 1 methodology described in
subpart C of this part (General Stationary Fuel Combustion Sources). If
the fuel combusted is natural gas and is pipeline quality and has a
minimum high heat value of 950 Btu per standard cubic foot, then the
natural gas emission factor and high heat values listed in Tables C-1
and C-2 of this part may be used.
(2) For fuel combustion units that combust field gas or process
vent gas, or any blend of field gas or process vent gas and fuels
listed in Table C-1 of subpart C of this part, calculate combustion
emissions as follows:
(i) If you have a continuous flow meter on the combustion unit, you
must use the measured flow volumes to calculate the total flow of gas
to the unit. If you do not have a permanent flow meter on the
combustion unit, you may install a permanent flow meter on the
combustion unit, or use company records or engineering calculations
based on best available data on heat duty or horsepower to estimate
volumetric unit gas flow.
(ii) If you have a continuous gas composition analyzer on fuel to
the combustion unit, you must use these compositions for determining
the concentration of gas hydrocarbon constituent in the flow of gas to
the unit. If you do not have a continuous gas composition analyzer on
gas to the combustion unit, you must use the appropriate gas
compositions for each stream of hydrocarbons going to the combustion
unit as specified in paragraph (u)(2)(i) of this section.
(iii) Calculate GHG volumetric emissions at actual conditions using
Equations W-39 of this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.209
Where:
Ea,CO2 = Contribution of annual emissions from portable
or stationary fuel combustion sources in cubic feet, under actual
conditions.
Va = Volume of gas sent to combustion unit in cubic feet,
during the year.
Yj = Concentration of gas hydrocarbon constituents j
(such as methane, ethane, propane, butane, and pentanes plus).
Rj = Number of carbon atoms in the gas hydrocarbon
constituent j; 1 for methane, 2 for ethane, 3 for propane, 4 for
butane, and 5 for pentanes plus).
(3) External fuel combustion sources with a rated heat capacity
equal to or less than 5 mmBtu/hr do not need to report combustion
emissions. You must report the type and number of each external fuel
combustion unit.
(4) Calculate GHG volumetric emissions at standard conditions using
calculations in paragraph (t) of this section.
(5) Calculate both combustion-related CH4 and
CO2 mass emissions from volumetric CH4 and
CO2 emissions using calculation in paragraph (v) of this
section.
[[Page 74505]]
(6) Calculate N2O mass emissions using Equation W-40 of
this section.
[GRAPHIC] [TIFF OMITTED] TR30NO10.210
Where:
N2O = Annual N2O emissions from the combustion
of a particular type of fuel (metric tons).
Fuel = Mass or volume of the fuel combusted (mass or volume per
year, choose appropriately to be consistent with the units of HHV).
HHV = High heat value of the fuel from paragraphs (z)(8)(i),
(z)(8)(ii) or (z)(8)(iii) of this section (units must be consistent
with Fuel).
EF = Use 1.0 x 10-\4\ kg N2O/mmBtu.
1 x 10-\3\ = Conversion factor from kilograms to metric
tons.
(i) For fuels listed in Table C-1 of subpart C of this part, use
the provided default HHV in the table.
(ii) For field gas or process vent gas, use 1.235 x
10-\3\ mmBtu/scf for HHV.
(iii) For fuels not listed in Table C-1 of subpart C of this part
and not field gas or process vent gas, you must use the methodology set
forth in the Tier 2 methodology described in subpart C of this part to
determine HHV.
Sec. 98.234 Monitoring and QA/QC requirements.
The GHG emissions data for petroleum and natural gas emissions
sources must be quality assured as applicable as specified in this
section. Offshore petroleum and natural gas production facilities shall
adhere to the monitoring and QA/QC requirements as set forth in 30 CFR
250.
(a) You must use any of the methods described as follows in this
paragraph to conduct leak detection(s) of equipment leaks and through-
valve leakage from all source types listed in Sec. 98.233(k), (o), (p)
and (q) that occur during a calendar year, except as provided in
paragraph (a)(4) of this section.
(1) Optical gas imaging instrument. Use an optical gas imaging
instrument for equipment leak detection in accordance with 40 CFR part
60, subpart A, Sec. 60.18(i)(1) and (2) of the Alternative work
practice for monitoring equipment leaks. Any emissions detected by the
optical gas imaging instrument is a leak unless screened with Method 21
(40 CFR part 60, appendix A-7) monitoring, in which case 10,000 ppm or
greater is designated a leak. In addition, you must operate the optical
gas imaging instrument to image the source types required by this
subpart in accordance with the instrument manufacturer's operating
parameters.
(2) Method 21. Use the equipment leak detection methods in 40 CFR
part 60, appendix A-7, Method 21. If using Method 21 monitoring, if an
instrument reading of 10,000 ppm or greater is measured, a leak is
detected. Inaccessible emissions sources, as defined in 40 CFR part 60,
are not exempt from this subpart. Owners or operators must use
alternative leak detection devices as described in paragraph(a)(1) of
this section to monitor inaccessible equipment leaks or vented
emissions.
(3) Infrared laser beam illuminated instrument. Use an infrared
laser beam illuminated instrument for equipment leak detection. Any
emissions detected by the infrared laser beam illuminated instrument is
a leak unless screened with Method 21 monitoring, in which case 10,000
ppm or greater is designated a leak. In addition, you must operate the
infrared laser beam illuminated instrument to detect the source types
required by this subpart in accordance with the instrument
manufacturer's operating parameters.
(4) Optical gas imaging instrument. An optical gas imaging
instrument must be used for all source types that are inaccessible and
cannot be monitored without elevating the monitoring personnel more
than 2 meters above a support surface.
(5) Acoustic leak detection device. Use the acoustic leak detection
device to detect through-valve leakage. When using the acoustic leak
detection device to quantify the through-valve leakage, you must use
the instrument manufacturer's calculation methods to quantify the
through-valve leak. When using the acoustic leak detection device, if a
leak of 3.1 scf per hour or greater is calculated, a leak is detected.
In addition, you must operate the acoustic leak detection device to
monitor the source valves required by this subpart in accordance with
the instrument manufacturer's operating parameters.
(b) You must operate and calibrate all flow meters, composition
analyzers and pressure gauges used to measure quantities reported in
Sec. 98.233 according to the procedures in Sec. 98.3(i) and the
procedures in paragraph (b) of this section. You may use an appropriate
standard method published by a consensus-based standards organization
if such a method exists or you may use an industry standard practice.
Consensus-based standards organizations include, but are not limited
to, the following: ASTM International, the American National Standards
Institute (ANSI), the American Gas Association (AGA), the American
Society of Mechanical Engineers (ASME), the American Petroleum
Institute (API), and the North American Energy Standards Board (NAESB).
(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 positioning the instrument for complete capture of the
equipment leak 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 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).
[[Page 74506]]
(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.
(e) Peng Robinson Equation of State means the equation of state
defined by Equation W-41 of this section:
[GRAPHIC] [TIFF OMITTED] TR30NO10.211
Where:
p = Absolute pressure.
R = Universal gas constant.
T = Absolute temperature.
Vm = Molar volume.
[GRAPHIC] [TIFF OMITTED] TR30NO10.212
Where:
[omega] = Acentric factor of the species.
Tc = Critical temperature.
Pc = Critical pressure.
(f) Special reporting provisions
(1) Best available monitoring methods. EPA will allow owners or
operators to use best available monitoring methods for parameters in
Sec. 98.233 Calculating GHG Emissions as specified in paragraphs
(f)(2), (f)(3), and (f)(4) of this section. If the reporter anticipates
the potential need for best available monitoring for sources for which
they need to petition EPA and the situation is unresolved at the time
of the deadline, reporters should submit written notice of this
potential situation to EPA by the specified deadline for requests to be
considered. EPA reserves the right to review petitions after the
deadline but will only consider and approve late petitions which
demonstrate extreme or unusual circumstances. The Administrator
reserves to right to request further information in regard to all
petition requests. The owner or operator must use the calculation
methodologies and equations in Sec. 98.233 Calculating GHG Emissions.
Best available monitoring methods means any of the following methods
specified in paragraph (f)(1) of this section:
(i) Monitoring methods currently used by the facility that do not
meet the specifications of this subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(2) Best available monitoring methods for well-related emissions.
During January 1, 2011 through June 30, 2011, owners or operators may
use best available monitoring methods for any well-related data that
cannot reasonably be measured according to the monitoring and QA/QC
requirements of this subpart, and only where required measurements
cannot be duplicated due to technical limitations after June 30, 2011.
These well-related sources are:
(i) Gas well venting during well completions and workovers with
hydraulic fracturing as specified in Sec. 98.233(g).
(ii) Well testing venting and flaring as specified in Sec.
98.233(l).
(3) Best available monitoring methods for specified activity data.
During January 1, 2011 through June 30, 2011, owners or operators may
use best available monitoring methods for activity data as listed below
that cannot reasonably be obtained according to the monitoring and QA/
QC requirements of this subpart, specifically for events that generate
data that can be collected only between January 1, 2011 and June 30,
2011 and cannot be duplicated after June 30, 2011. These sources are:
(i) Cumulative hours of venting, days, or times of operation in
Sec. 98.233(e), (f), (g), (h), (l), (o), (p), (q), and (r).
(ii) Number of blowdowns, completions, workovers, or other events
in Sec. 98.233(f), (g), (h), (i), and (w).
(iii) Cumulative volume produced, volume input or output, or volume
of fuel used in paragraphs Sec. 98.233(d), (e), (j), (k), (l), (m),
(n), (x), (y), and (z).
(4) Best available monitoring methods for leak detection and
measurement. The owner or operator may request use of best available
monitoring methods between January 1, 2011 and December 31, 2011 for
sources requiring leak detection and/or measurement. These sources
include:
(i) Reciprocating compressor rod packing venting in onshore natural
gas processing, onshore natural gas transmission compression,
underground natural gas storage, LNG storage, and LNG import and export
equipment as specified in Sec. 98.232(d)(1), (e)(1), (f)(1), (g)(1),
and (h)(1).
(ii) Centrifugal compressor wet seal oil degassing venting in
onshore natural gas processing, onshore natural gas transmission
compression, underground natural gas storage, LNG storage, and LNG
import and export equipment as specified in Sec. 98.232(d)(2), (e)(2),
(f)(2), (g)(2), and (h)(2).
(iii) Acid gas removal vent stacks in onshore petroleum and natural
gas production and onshore natural gas processing as specified in Sec.
98.232(c)(17) and (d)(6).
(iv) Equipment leak emissions from valves, connectors, open ended
lines, pressure relief valves, block valves, control valves, compressor
blowdown valves, orifice meters, other meters, regulators, vapor
recovery compressors, centrifugal compressor dry seals, and/or other
equipment leaks in onshore
[[Page 74507]]
natural gas processing, onshore natural gas transmission compression,
underground natural gas storage, LNG storage, LNG import and export
equipment, and natural gas distribution as specified in Sec.
98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1).
(v) Condensate (oil and/or water) storage tanks in onshore natural
gas transmission compression as specified in Sec. 98.232(e)(3).
(5) Requests for the use of best available monitoring methods. The
owner or operator may submit a request to the Administrator to use one
or more best available monitoring methods.
(i) No request or approval by the Administrator is necessary to use
best available monitoring methods between January 1, 2011 and June 30,
2011 for the sources specified in paragraph (f)(2) of this section.
(ii) No request or approval by the Administrator is necessary to
use best available monitoring methods between January 1, 2011 and June
30, 2011 for the sources specified in paragraph (f)(3) of this section.
(iii) Owners or operators must submit a request and receive
approval by the Administrator to use best available monitoring methods
between January 1, 2011 and December 31, 2011 for sources specified in
paragraph (f)(4) of this section.
(A) Timing of request. The request to use best available monitoring
methods for paragraph (f)(4) of this section must be submitted to EPA
no later than April 30, 2011.
(B) Content of request. Requests must contain the following
information for sources listed in paragraph (f)(4) of this section:
(1) A list of specific source types and specific equipment,
monitoring instrumentation, and/or services for which the request is
being made and the locations where each piece of monitoring
instrumentation will be installed or monitoring service will be
supplied.
(2) Identification of the specific rule requirements (by subpart,
section, and paragraph number) for which the instrumentation or
monitoring service is needed.
(3) Documentation which demonstrates that the owner or operator
made all reasonable efforts to obtain the information, services or
equipment necessary to comply with subpart W reporting requirements,
including evidence of specific service or equipment providers contacted
and why services or information could not be obtained during 2011.
(4) A description of the specific actions the facility will take to
obtain and/or install the equipment or obtain the monitoring service as
soon as reasonably feasible and the expected date by which the
equipment will be obtained and operating or service will be provided.
(C) Approval criteria. To obtain approval, the owner or operator
must demonstrate to the Administrator's satisfaction that it does not
own the required monitoring equipment, and it is not reasonably
feasible to acquire, install, and operate a required piece of
monitoring equipment or to obtain leak detection or measurement
services in order to meet the requirements of this subpart for 2011.
(iv) EPA does not anticipate a need to approve the use of best
available monitoring methods for sources not listed in
paragraphs(f)(2), (f)(3), and (f)(4) of this section; however, EPA will
review such requests if submitted in accordance with paragraph
(f)(5)(iv)(A)-(C) of this section.
(A) Timing of request. The request to use best available monitoring
methods for sources not listed in paragraphs (f)(2), (f)(3), and (f)(4)
of this section must be submitted to EPA no later than April 30, 2011.
(B) Content of request. Requests must contain the following
information:
(1) A list of specific source categories and parameters for which
the owner or operator is seeking use of best available monitoring
methods.
(2) A description of the data collection methodologies that do not
meet safety regulations, technical infeasibility, or specific laws or
regulations that conflict with each specific source for which an owner
or operator is requesting use of best available monitoring
methodologies.
(3) A detailed explanation and supporting documentation of how and
when the owner or operator will receive the services or equipment to
comply with all subpart W reporting requirements.
(C) Approval criteria. To obtain approval, the owner or operator
must demonstrate to the Administrator's satisfaction that the owner or
operator faces unique safety, technical or legal issues rendering them
unable to meet the requirements of this subpart for 2011.
(6) Requests for extension of the use of best available monitoring
methods through December 31, 2011 for sources in paragraph (f)(2) of
this section. The owner or operator may submit a request to the
Administrator to use one or more best available monitoring methods
described in paragraph (f)(2) of this section beyond June 30, 2011.
(i) Timing of request. The extension request must be submitted to
EPA no later than April 30, 2011.
(ii) Content of request. Requests must contain the following
information:
(A) A list of specific source types and specific equipment,
monitoring instrumentation, contract modifications, and/or services for
which the request is being made and the locations where each piece of
monitoring instrumentation will be installed, monitoring service will
be supplied, or contracts will be modified.
(B) Identification of the specific rule requirements (by subpart,
section, and paragraph number) for which the instrumentation, contract
modification, or monitoring service is needed.
(C) A description and applicable correspondence outlining the
diligent efforts of the owner or operator in obtaining the needed
equipment or service and why they could not be obtained and installed
in a period of time enabling completion of applicable requirements of
this subpart within the 2011 calendar year.
(D) If the reason for the extension is that the owner or operator
cannot collect data from a service provider or relevant organization in
order for the owner or operator to meet requirements of this subpart
for the 2011 calendar year, the owner or operator must demonstrate a
good faith effort that it is not possible to obtain the necessary
information, service or hardware which may include providing
correspondence from specific service providers or other relevant
entities to the owner or operator, whereby the service provider states
that it is unable to provide the necessary data or services requested
by the owner or operator that would enable the owner or operator to
comply with subpart W reporting requirements by June 30, 2011.
(E) A description of the specific actions the owner or operator
will take to comply with monitoring requirements in 2012 and beyond.
(iii) Approval criteria. To obtain approval, the owner or operator
must demonstrate to the Administrator's satisfaction that it is not
reasonably feasible to obtain the data necessary to meet the
requirements of this subpart for the sources specified in paragraph
(f)(2) of this section by June 30, 2011.
(7) Requests for extension of the use of best available monitoring
methods through December 31, 2011 for sources in paragraph (f)(3) of
this section. The owner or operator may submit a request to the
Administrator to use one or more best available monitoring methods
described in paragraph (f)(3) of this section beyond June 30, 2011.
[[Page 74508]]
(i) Timing of request. The extension request must be submitted to
EPA no later than April 30, 2011.
(ii) Content of request. Requests must contain the following
information:
(A) A list of specific source types for which data collection could
not be implemented.
(B) Identification of the specific rule requirements (by subpart,
section, and paragraph number) for which the data collection could not
be implemented.
(C) A description of the data collection methodologies that do not
meet safety regulations, technical infeasibility, or specific laws or
regulations that conflict with each specific source for which an owner
or operator is requesting use of best available monitoring
methodologies for which data collection could not be implemented in the
2011 calendar year.
(iii) Approval criteria. To obtain approval, the owner or operator
must demonstrate to the Administrator's satisfaction that it is not
reasonably feasible to implement the data collection for the sources
described in paragraph (f)(3) of this section for the methods required
in this subpart by June, 30, 2011.
(8) Requests for extension of the use of best available monitoring
methods beyond 2011 for sources listed in paragraphs (f)(2), (f)(3),
(f)(4), (f)(5)(iv) of this section and other sources in this subpart.
EPA does not anticipate a need for approving the use of best available
methods beyond December 31, 2011, except in extreme circumstances,
which include safety, a requirement being technically infeasible or
counter to other local, State, or Federal regulations.
(i) Timing of request. The request to use best available monitoring
methods for paragraphs (f)(2), (f)(3), (f)(4), (f)(5)(iv) of this
section and sources not listed in paragraphs (f)(2), (f)(3), (f)(4),
(f)(5)(iv) of this section must be submitted to EPA no later than
September 30, 2011.
(ii) Content of request. Requests must contain the following
information:
(iii) A list of specific source categories and parameters for which
the owner or operator is seeking use of best available monitoring
methods.
(iv) A description of the data collection methodologies that do not
meet safety regulations, technical infeasibility, or specific laws or
regulations that conflict with each specific source for which an owner
or operator is requesting use of best available monitoring
methodologies.
(v) A detailed explanation and supporting documentation of how and
when the owner or operator will receive the services or equipment to
comply with all of this subpart W reporting requirements.
(C) Approval criteria. To obtain approval, the owner or operator
must demonstrate to the Administrator's satisfaction that the owner or
operator faces unique safety, technical or legal issues rendering them
unable to meet the requirements of this subpart.
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 calendar year if missing
data are not discovered until after December 31 of the year in which
data are collected, until valid data for reporting is obtained. Data
developed and/or collected in a subsequent calendar year to substitute
for missing data cannot be used for that subsequent year's emissions
estimation. Where missing 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. For missing data
which are continuously monitored or measured, (for example flow
meters), or for missing temperature or pressure data that are required
under Sec. 98.236, the reporter may use best available data for use in
emissions determinations. The reporter must record and report the basis
for the best available data in these cases.
Sec. 98.236 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain reported emissions and related information
as specified in this section.
(a) Report annual emissions separately for each of the industry
segments listed in paragraphs (a)(1) through (8) of this section in
metric tons CO2e per year at standard conditions. For each
segment, report emissions from each source type Sec. 98.232(a) in the
aggregate, unless specified otherwise. For example, an onshore natural
gas production 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) Offshore petroleum and natural gas production is not required
to report activity data and emissions for each aggregated source under
Sec. 98.236(c). Reporting requirements for offshore petroleum and
natural gas production is set forth by BOEMRE in compliance with 30 CFR
250.302 through 304.
(c) For each aggregated source, unless otherwise specified, report
activity data and emissions (in metric tons CO2e per year at
standard conditions) for each aggregated source type as follows:
(1) For natural gas pneumatic devices (refer to Equation W-1 of
Sec. 98.233), report the following:
(i) Actual count and estimated count separately of natural gas
pneumatic high bleed devices as applicable.
(ii) Actual count and estimated count separately of natural gas
pneumatic low bleed devices as applicable.
(iii) Actual count and estimated count separately of natural gas
pneumatic intermittent bleed devices as applicable.
(iv) Report emissions collectively.
(2) For natural gas driven pneumatic pumps (refer to Equation W-2
of Sec. 98.233), report the following,
(i) Count of natural gas driven pneumatic pumps.
(ii) Report emissions collectively.
(3) For each acid gas removal unit (refer to Equation W-3 and
Equation W-4 of Sec. 98.233), report the following:
(i) Total throughput off the acid gas removal unit using a meter or
engineering estimate based on process knowledge or best available data
in million cubic feet per year.
(ii) For Calculation Methodology 1 and Calculation Methodology 2 of
Sec. 98.233(d), fraction of CO2 content in the vent from
the acid gas removal unit (refer to Sec. 98.233(d)(6)).
(iii) For Calculation Methodology 3 of Sec. 98.233(d), volume
fraction of CO2 content of natural gas into and out of the
acid gas removal unit (refer to Sec. 98.233(d)(7) and (d)(8)).
(iv) Report emissions from the AGR unit recovered and transferred
outside the facility.
(v) Report emissions individually.
(4) For dehydrators, report the following:
(i) For each Glycol dehydrator with a throughput greater than or
equal to 0.4 MMscfd (refer to Sec. 98.233(e)(1)), report the
following:
[[Page 74509]]
(A) Glycol dehydrator feed natural gas flow rate in MMscfd,
determined by engineering estimate based on best available data.
(B) Glycol dehydrator absorbent circulation pump type.
(C) Whether stripper gas is used in glycol dehydrator.
(D) Whether a flash tank separator is used in glycol dehydrator.
(E) Type of absorbent.
(F) Total time the glycol dehydrator is operating in hours.
(G) Temperature, in degrees Fahrenheit and pressure, in psig, of
the wet natural gas.
(H) Concentration of CH4 and CO2 in natural
gas.
(I) What vent gas controls are used (refer to Sec. 98.233(e)(3)
and (e)(4)).
(J) Report vent and flared emissions individually.
(ii) For all glycol dehydrators with a throughput less than 0.4
MMscfd (refer to Sec. 98.233, Equation W-5 of Sec. 98.233), report
the following:
(A) Count of glycol dehydrators.
(B) Whether any vent gas controls are used (refer to Sec.
98.233(e)(3) and (e)(4)).
(C) Report vent emissions collectively.
(iii) For absorbent desiccant dehydrators (refer to Equation W-6 of
Sec. 98.233), report the following:
(A) Count of desiccant dehydrators.
(B) Report emissions collectively.
(5) For well venting for liquids unloading (refer to Equations W-7,
W-8 and W-9 of Sec. 98.233), report the following by field:
(i) Count of wells vented to the atmosphere for liquids unloading.
(ii) Count of plunger lifts.
(iii) Cumulative number of unloadings vented to the atmosphere.
(iv) Average flow rate of the measured well venting in cubic feet
per hour (refer to Sec. 98.233(f)(1)(i)(A)).
(v) Average casing diameter in inches.
(vi) Report emissions collectively.
(6) For well completions and workovers, report the following for
each field:
(i) For gas well completions and workovers with hydraulic
fracturing (refer to Equation W-10 of Sec. 98.233):
(A) Total count of completions in calendar year.
(B) Average flow rate of the measured well completion venting in
cubic feet per hour (refer to Sec. 98.233(g)(1)(i) or (g)(1)(ii)).
(C) Total count of workovers in calendar year.
(D) Average flow rate of the measured well workover venting in
cubic feet per hour (refer to Sec. 98.233(g)(1)(i) or (g)(1)(ii)).
(E) Total number of days of gas venting to the atmosphere during
backflow for completion.
(F) Total number of days of gas venting to the atmosphere during
backflow for workovers.
(G) Report number of completions and workovers employing reduced
emissions completions and engineering estimate based on best available
data of the amount of gas recovered to sales.
(H) Report vent emissions collectively. Report flared emissions
collectively.
(ii) For gas well completions and workovers without hydraulic
fracturing (refer to Equation W-13 of Sec. 98.233):
(A) Total count of completions in calendar year.
(B) Total count of workovers in calendar year.
(C) Total number of days of gas venting to the atmosphere during
backflow for completion.
(D) Report vent emissions collectively. Report flared emissions
collectively.
(7) For each blowdown vent stack (refer to Equation W-14 of Sec.
98.233), report the following:
(i) Total number of blowdowns per equipment type in calendar year.
(ii) Report emissions collectively per equipment type.
(8) For gas emitted from produced oil sent to atmospheric tanks:
(i) For wellhead gas-liquid separator with oil throughput greater
than or equal to 10 barrels per day, using Calculation Methodology 1
and 2 of Sec. 98.233(j), report the following by field:
(A) Number of wellhead separators sending oil to atmospheric tanks.
(B) Estimated average separator temperature, in degrees Fahrenheit,
and estimated average pressure, in psig.
(C) Estimated average sales oil stabilized API gravity, in degrees.
(D) Count of hydrocarbon tanks at well pads.
(E) Best estimate of count of stock tanks not at well pads
receiving your oil.
(F) Total volume of oil from all wellhead separators sent to
tank(s) in barrels per year.
(G) Count of tanks with emissions control measures, either vapor
recovery system or flaring, for tanks at well pads.
(H) Best estimate of count of stock tanks assumed to have emissions
control measures not at well pads, receiving your oil.
(I) Range of concentrations of flash gas, CH4 and
CO2.
(J) Report emissions individually for Calculation Methodology 1 and
2 of Sec. 98.233(j).
(ii) For wells with oil production greater than or equal to 10
barrels per day, using Calculation Methodology 3 and 4 of Sec.
98.233(j), report the following by field:
(A) Total volume of sales oil from all wells in barrels per year.
(B) Total number of wells sending oil directly to tanks.
(C) Total number of wells sending oil to separators off the well
pads.
(D) Sales oil API gravity range for (B) and (C) of this section, in
degrees.
(E) Count of hydrocarbon tanks on wellpads.
(F) Count of hydrocarbon tanks, both on and off well pads assumed
to have emissions control measures: either vapor recovery system or
flaring of tank vapors.
(G) Report emissions collectively for Calculation Methodology 3 and
4 of Sec. 98.233(j).
(iii) For wellhead gas-liquid separators and wells with throughput
less than 10 barrels per day, using Calculation Methodology 5 of Sec.
98.233(j) Equation W-15 of Sec. 98.233), report the following:
(A) Number of wellhead separators.
(B) Number of wells without wellhead separators.
(C) Total volume of oil production in barrels per year.
(D) Best estimate of fraction of production sent to tanks with
assumed control measures: either vapor recovery system or flaring of
tank vapors.
(E) Count of hydrocarbon tanks on well pads.
(F) Report CO2 and CH4 emissions
collectively.
(iv) If wellhead separator dump valve is functioning improperly
during the calendar year (refer to Equation W-16 of Sec. 98.233),
report the following:
(A) Count of wellhead separators that dump valve factor is applied.
(9) For transmission tank emissions identified using optical gas
imaging instrument per Sec. 98.234(a) (refer to Sec. 98.233(k)), or
acoustic leak detection of scrubber dump valves report the following
for each tank:
(i) Report emissions individually.
(ii) [Reserved]
(10) For well testing (refer to Equation W-17 of Sec. 98.233),
report the following for each basin:
(i) Number of wells tested per basin in calendar year.
(ii) Average gas to oil ratio for each basin.
(iii) Average number of days the well is tested in a basin.
(iv) Report emissions of the venting gas collectively.
(11) For associated natural gas venting (refer to Equation W-18 of
Sec. 98.233), report the following for each basin:
(i) Number of wells venting or flaring associated natural gas in a
calendar year.
(ii) Average gas to oil ratio for each basin.
[[Page 74510]]
(iii) Report emissions of the flaring gas collectively.
(12) For flare stacks (refer to Equation W-19, W-20, and W-21 of
Sec. 98.233), report the following for each flare:
(i) Whether flare has a continuous flow monitor.
(ii) Volume of gas sent to flare in cubic feet per year.
(iii) Percent of gas sent to un-lit flare determined by engineering
estimate and process knowledge based on best available data and
operating records.
(iv) Whether flare has a continuous gas analyzer.
(v) Flare combustion efficiency.
(vi) Report uncombusted and combusted CO2 and
CH4 emissions separately.
(13) For each centrifugal compressor:
(i) For compressors with wet seals in operational mode (refer to
Equations W-22 through W-24 of Sec. 98.233), report the following for
each degassing vent:
(A) Number of wet seals connected to the degassing vent.
(B) Fraction of vent gas recovered for fuel or sales or flared.
(C) Annual throughput in million scf, use an engineering
calculation based on best available data.
(D) Type of meters used for making measurements.
(E) Reporter emission factor for wet seal oil degassing vents in
cubic feet per hour (refer to Equation W-24 of Sec. 98.233).
(F) Total time the compressor is operating in hours.
(G) Report seal oil degassing vent emissions for compressors
measured (refer to Equation W-22 of Sec. 98.233) and for compressors
not measured (refer to Equation W-23 and Equation W-24 of Sec.
98.233).
(ii) For wet and dry seal centrifugal compressors in operating
mode, (refer to Equations W-22 through W-24 of Sec. 98.233), report
the following:
(A) Total time in hours the compressor is in operating mode.
(B) Reporter emission factor for blowdown vents in cubic feet per
hour (refer to Equation W-24 of Sec. 98.233).
(C) Report blowdown vent emissions when in operating mode (refer to
Equation W-23 and Equation W-24 of Sec. 98.233).
(iii) For wet and dry seal centrifugal compressors in not
operating, depressurized mode (refer to Equations W-22 through W-24 of
Sec. 98.233), report the following:
(A) Total time in hours the compressor is in shutdown,
depressurized mode.
(B) Reporter emission factor for isolation valve emissions in
shutdown, depressurized mode in cubic feet per hour (refer to Equation
W-24 of Sec. 98.233).
(C) Report the isolation valve leakage emissions in not operating,
depressurized mode in cubic feet per hour (refer to Equation W-23 and
Equation W-24 of Sec. 98.233).
(iv) Report total annual compressor emissions from all modes of
operation (refer to Equation W-24 of Sec. 98.233).
(v) For centrifugal compressors in onshore petroleum and natural
gas production (refer to Equation W-25 of Sec. 98.233), report the
following:
(A) Count of compressors.
(B) Report emissions (refer to Equation W-25 of Sec. 98.233)
collectively.
(14) For reciprocating compressors:
(i) For reciprocating compressors rod packing emissions with or
without a vent in operating mode, report the following:
(A) Annual throughput in million scf, use an engineering
calculation based on best available data.
(B) Total time in hours the reciprocating compressor is in
operating mode.
(C) Report rod packing emissions for compressors measured (refer to
Equation W-26 of Sec. 98.233) and for compressors not measured (refer
to Equation W-27 and Equation W-28 of Sec. 98.233).
(ii) For reciprocating compressors blowdown vents not manifold to
rod packing vents, in operating and standby pressurized mode (refer to
Equations W-26 through W-28 of Sec. 98.233), report the following:
(A) Total time in hours the compressor is in standby, pressurized
mode.
(B) Reporter emission factor for blowdown vents in cubic feet per
hour (refer to Sec. 98.233, Equation W-28).
(C) Report blowdown vent emissions when in operating and standby
pressurized modes (refer to Equation W-27 and Equation W-28 of Sec.
98.233).
(iii) For reciprocating compressors in not operating, depressurized
mode (refer to Equations W-26 through W-28 of Sec. 98.233), report the
following:
(A) Total time the compressor is in not operating, depressurized
mode.
(B) Reporter emission factor for isolation valve emissions in not
operating, depressurized mode in cubic feet per hour (refer to Equation
W-28 of Sec. 98.233).
(C) Report the isolation valve leakage emissions in not operating,
depressurized mode.
(iv) Report total annual compressor emissions from all modes of
operation (refer to Equation W-27 and Equation W-28 of Sec. 98.233).
(v) For reciprocating compressors in onshore petroleum and natural
gas production (refer to Equation W-29 of Sec. 98.233), report the
following:
(A) Count of compressors.
(B) Report emissions collectively.
(15) For each equipment leak sources that uses emission factors for
estimating emissions (refer to Sec. 98.233(q) and (r).
(i) For equipment leaks found in each leak survey (refer to Sec.
98.233(q)), report the following:
(A) Total count of leaks found in each complete survey listed by
date of survey and each type of leak source for which there is a leaker
emission factor in Tables W-2, W-3, W-4, W-5, W-6, and W-7 of this
subpart.
(B) Concentration of CH4 and CO2 as described
in Equation W-30 of Sec. 98.233.
(C) Report CH4 and CO2 emissions (refer to
Equation W-30 of Sec. 98.233) collectively by equipment type.
(ii) For equipment leaks calculated using population counts and
factors (refer to Sec. 98.233(r)), report the following:
(A) For source categories Sec. 98.230(a)(3), (a)(4), (a)(5),
(a)(6), and (a)(7), total count for each type of leak source in Tables
W-2, W-3, W-4, W-5, and W-6 of this subpart for which there is a
population emission factor, listed by major heading and component type.
(B) For onshore production (refer to Sec. 98.230 paragraph
(a)(2)), total count for each type of major equipment in Table W-1B and
Table W-1C of this subpart, by field.
(C) Report CH4 and CO2 emissions (refer to
Equation W-31 of Sec. 98.233) collectively by equipment type.
(16) For local distribution companies, report the following:
(i) Number of custody transfer gate stations.
(ii) Number of non-custody transfer gate stations.
(iii) Custody transfer gate station meter run leak factor (refer to
Equation W-32 of Sec. 98.233).
(iv) Number of below grade M&R stations with inlet pressure greater
than 300 psig.
(v) Number of below grade M&R stations with inlet pressure between
100 and 300 psig.
(vi) Number of below grate M&R stations with inlet pressure less
than 100 psig.
(vii) Number of miles of unprotected steel distribution mains.
(viii) Number of miles of protected steel distribution mains.
(ix) Number of miles of plastic distribution mains.
(x) Number of miles of cast iron distribution mains.
(xi) Number of unprotected steel distribution services.
(xii) Number of protected steel distribution services.
[[Page 74511]]
(xiii) Number of plastic distribution services.
(xiv) Number of copper distribution services.
(xv) Total emissions from each natural gas distribution facility.
(17) For each EOR injection pump blowdown (refer to Equation W-37
of Sec. 98.233), report the following:
(i) Pump capacity, in barrels per day.
(ii) Volume of critical phase gas between isolation valves.
(iii) Number of blowdowns per year.
(iv) Critical phase EOR injection gas density.
(v) Report emissions collectively.
(18) For EOR hydrocarbon liquids dissolved CO2 for each
field (refer to Equation W-38 of Sec. 98.233), report the following:
(i) Volume of crude oil produced in barrels per year.
(ii) Amount of CO2 retained in hydrocarbon liquids in
metric tons per barrel, under standard conditions.
(iii) Report emissions individually.
(19) For onshore petroleum and natural gas production and natural
gas distribution combustion emissions, report the following:
(i) Cumulative number of external fuel combustion units with a
rated heat capacity equal to or less than 5 mmBtu/hr, by type of unit.
(ii) Cumulative number of external fuel combustion units with a
rated heat capacity larger than 5 mmBtu/hr, by type of unit.
(iii) Cumulative emissions from external fuel combustion units with
a rated heat capacity larger than 5 mmBtu/hr, by type of unit.
(iv) Cumulative volume of fuel combusted in external fuel
combustion units with a rated heat capacity larger than 5 mmBtu/hr, by
fuel type.
(v) Cumulative number of all internal combustion units, by type of
unit.
(vi) Cumulative emissions from internal combustion units, by type
of unit.
(vii) Cumulative volume of fuel combusted in internal combustion
units, by fuel type.
(d) Report annual throughput as determined by engineering estimate
based on best available data for each industry segment listed in
paragraphs (a)(1) through (a)(8) of this section.
Sec. 98.237 Records that must be retained.
Monitoring Plans, as described in Sec. 98.3(g)(5), must be
completed by April 1, 2011. 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 in this section, all terms used in this subpart
have the same meaning given in the Clean Air Act and subpart A of this
part.
Acid gas means hydrogen sulfide (H2S) and/or carbon
dioxide (CO2) contaminants that are separated from sour
natural gas by an acid gas removal unit.
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 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.
Basin means geologic provinces as defined by the American
Association of Petroleum Geologists (AAPG) Geologic Note: AAPG-CSD
Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F.
Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10
(October 1991) (incorporated by reference, see Sec. 98.7) and the
Alaska Geological Province Boundary Map, Compiled by the American
Association of Petroleum Geologists Committee on Statistics of Drilling
in Cooperation with the USGS, 1978 (incorporated by reference, see
Sec. 98.7).
Component means 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 or CO2 by drawing in low pressure natural gas or
CO2 and discharging significantly higher pressure natural
gas or CO2.
Condensate means hydrocarbon and other liquid, including both water
and hydrocarbon liquids, separated from natural gas that condenses due
to changes in the temperature, pressure, or both, and remains liquid at
storage conditions.
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 subpart,
EOR applies to injection of critical phase or immiscible carbon dioxide
into a crude oil reservoir to enhance the recovery of oil.
Equipment leak means those emissions which could not reasonably
pass through a stack, chimney, vent, or other functionally-equivalent
opening.
Equipment leak detection means the process of identifying emissions
from equipment, components, and other point sources.
External combustion means fired combustion in which the flame and
products of combustion are separated from contact with the process
fluid to which the energy is delivered. Process fluids may be air, hot
water, or hydrocarbons. External combustion equipment may include fired
heaters, industrial boilers, and commercial and domestic combustion
units.
Facility with respect to natural gas distribution for purposes of
this subpart and for subpart A means the collection of all 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.
Facility with respect to onshore petroleum and natural gas
production for purposes of this subpart and for subpart A means all
petroleum or natural gas equipment on a well pad or associated with a
well pad and CO2 EOR operations that are under common
ownership or common control including leased, rented, or contracted
activities by an onshore petroleum and natural gas production owner or
operator and that are located in a single hydrocarbon basin as defined
in Sec. 98.238. Where a person or entity owns or operates more than
one well in a basin, then all onshore petroleum and natural gas
production equipment associated with all wells that the person or
entity owns or operates in the basin would be considered one facility.
Farm Taps are pressure regulation stations that deliver gas
directly from transmission pipelines to generally rural customers. The
gas may or may not be metered, but always does not pass through a city
gate station. In some cases a nearby LDC may handle the billing of the
gas to the customer(s).
[[Page 74512]]
Field means oil and gas fields identified in the United States as
defined by the Energy Information Administration Oil and Gas Field Code
Master List 2008, DOE/EIA 0370(08) (incorporated by reference, see
Sec. 98.7).
Flare stack emissions means CO2 and N2O from
partial combustion of hydrocarbon gas sent to a flare plus
CH4 emissions resulting from the incomplete combustion of
hydrocarbon gas in flares.
Flare combustion efficiency means the fraction of hydrocarbon gas,
on a volume or mole basis, that is combusted at the flare burner tip.
Gas well means a well completed for production of natural gas from
one or more gas zones or reservoirs. Such wells contain no completions
for the production of crude oil.
Internal combustion means the combustion of a fuel that occurs with
an oxidizer (usually air) in a combustion chamber. In an internal
combustion engine the expansion of the high-temperature and -pressure
gases produced by combustion applies direct force to a component of the
engine, such as pistons, turbine blades, or a nozzle. This force moves
the component over a distance, generating useful mechanical energy.
Internal combustion equipment may include gasoline and diesel
industrial engines, natural gas-fired reciprocating engines, and gas
turbines.
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 boil-off 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.
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.
Oil well means a well completed for the production of crude oil
from at least one oil zone or reservoir.
Onshore petroleum and natural gas production owner or operator
means the person or entity who holds the permit to operate petroleum
and natural gas wells on the drilling permit or an operating permit
where no drilling permit is issued, which operates an onshore petroleum
and/or natural gas production facility (as described in Sec.
98.230(a)(2). Where petroleum and natural gas wells operate without a
drilling or operating permit, the person or entity that pays the State
or Federal business income taxes is considered the owner or operator.
Operating pressure means the containment pressure that
characterizes the normal state of gas or liquid inside a particular
process, pipeline, vessel or tank.
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.
Reservoir means a porous and permeable underground natural
formation containing significant quantities of hydrocarbon liquids and/
or gases.
Residue Gas and Residue Gas Compression mean, respectively,
production lease natural gas from which gas liquid products and, in
some cases, non-hydrocarbon components have been extracted such that it
meets the specifications set by a pipeline transmission company, and/or
a distribution company; and the compressors operated by the processing
facility, whether inside the processing facility boundary fence or
outside the fence-line, that deliver the residue gas from the
processing facility to a transmission pipeline.
Separator means a vessel in which streams of multiple phases are
gravity separated into individual streams of single phase.
Transmission pipeline means high pressure cross country pipeline
transporting saleable 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.
Vented emissions means intentional or designed releases of
CH4 or CO2 containing natural gas or hydrocarbon
gas (not including stationary combustion flue gas), including 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).
Table W-1A to Subpart W of Part 98--Default Whole Gas Emission Factors
for Onshore Petroleum and Natural Gas Production
------------------------------------------------------------------------
Emission
factor (scf/
Onshore petroleum and natural gas production hour/
component)
------------------------------------------------------------------------
Eastern U.S.
------------------------------------------------------------------------
Population Emission Factors--All Components, Gas
Service:\1\
Valve................................................... 0.027
Connector............................................... 0.004
Open-ended Line......................................... 0.062
Pressure Relief Valve................................... 0.041
Low Continuous Bleed Pneumatic Device Vents \2\......... 1.80
High Continuous Bleed Pneumatic Device Vents \2\........ 48.1
Intermittent Bleed Pneumatic Device Vents \2\........... 17.4
Pneumatic Pumps \3\..................................... 13.3
Population Emission Factors--All Components, Light Crude
Service:\4\
Valve................................................... 0.04
Flange.................................................. 0.002
Connector............................................... 0.005
Open-ended Line......................................... 0.04
Pump.................................................... 0.01
Other \5\............................................... 0.23
Population Emission Factors--All Components, Heavy Crude
Service:\6\
Valve................................................... 0.0004
Flange.................................................. 0.0007
Connector (other)....................................... 0.0002
Open-ended Line......................................... 0.004
Other \5\............................................... 0.002
------------------------------------------------------------------------
Western U.S.
------------------------------------------------------------------------
Population Emission Factors--All Components, Gas
Service:\1\
Valve................................................... 0.123
Connector............................................... 0.017
Open-ended Line......................................... 0.032
Pressure Relief Valve................................... 0.196
Low Continuous Bleed Pneumatic Device Vents \2\......... 1.80
High Continuous Bleed Pneumatic Device Vents \2\........ 48.1
Intermittent Bleed Pneumatic Device Vents \2\........... 17.4
Pneumatic Pumps \3\..................................... 13.3
Population Emission Factors--All Components, Light Crude
Service:\4\
Valve................................................... 0.04
Flange.................................................. 0.002
Connector (other)....................................... 0.005
Open-ended Line......................................... 0.04
Pump.................................................... 0.01
Other \5\............................................... 0.23
[[Page 74513]]
Population Emission Factors--All Components, Heavy Crude
Service:\6\
Valve................................................... 0.0004
Flange.................................................. 0.0007
Connector (other)....................................... 0.0002
Open-ended Line......................................... 0.004
Other \5\............................................... 0.002
------------------------------------------------------------------------
\1\ For multi-phase flow that includes gas, use the gas service
emissions factors.
\2\ Emission Factor is in units of ``scf/hour/device.''
\3\ Emission Factor is in units of ``scf/hour/pump.''
\4\ Hydrocarbon liquids greater than or equal to 20[deg]API are
considered ``light crude.''.
\5\ ''Others'' category includes instruments, loading arms, pressure
relief valves, stuffing boxes, compressor seals, dump lever arms, and
vents.
\6\ Hydrocarbon liquids less than 20[deg]API are considered ``heavy
crude.''
Table W-1B to Subpart W of Part 98--Default Average Component Counts for Major Onshore Natural Gas Production
Equipment
----------------------------------------------------------------------------------------------------------------
Open-ended Pressure
Major equipment Valves Connectors lines relief valves
----------------------------------------------------------------------------------------------------------------
Eastern U.S.
----------------------------------------------------------------------------------------------------------------
Wellheads....................................... 8 38 0.5 0
Separators...................................... 1 6 0 0
Meters/piping................................... 12 45 0 0
Compressors..................................... 12 57 0 0
In-line heaters................................. 14 65 2 1
Dehydrators..................................... 24 90 2 2
----------------------------------------------------------------------------------------------------------------
Western U.S.
----------------------------------------------------------------------------------------------------------------
Wellheads....................................... 11 36 1 0
Separators...................................... 34 106 6 2
Meters/piping................................... 14 51 1 1
Compressors..................................... 73 179 3 4
In-line heaters................................. 14 65 2 1
Dehydrators..................................... 24 90 2 2
----------------------------------------------------------------------------------------------------------------
Table W-1C to Subpart W of Part 98--Default Average Component Counts For Major Crude Oil Production Equipment
----------------------------------------------------------------------------------------------------------------
Open-ended Other
Major equipment Valves Flanges Connectors lines components
----------------------------------------------------------------------------------------------------------------
Eastern U.S.
----------------------------------------------------------------------------------------------------------------
Wellhead........................ 5 10 4 0 1
Separator....................... 6 12 10 0 0
Heater-treater.................. 8 12 20 0 0
Header.......................... 5 10 4 0 0
----------------------------------------------------------------------------------------------------------------
Western U.S.
----------------------------------------------------------------------------------------------------------------
Wellhead........................ 5 10 4 0 1
Separator....................... 6 12 10 0 0
Heater-treater.................. 8 12 20 0 0
Header.......................... 5 10 4 0 0
----------------------------------------------------------------------------------------------------------------
Table W-1D of Subpart W of Part 98--Designation Of Eastern And Western
U.S.
------------------------------------------------------------------------
Eastern U.S. Western U.S.
------------------------------------------------------------------------
Connecticut............................... Alabama
Delaware.................................. Alaska
Florida................................... Arizona
Georgia................................... Arkansas
Illinois.................................. California
Indiana................................... Colorado
Kentucky.................................. Hawaii
Maine..................................... Idaho
Maryland.................................. Iowa
Massachusetts............................. Kansas
Michigan.................................. Louisiana
New Hampshire............................. Minnesota
New Jersey................................ Mississippi
New York.................................. Missouri
North Carolina............................ Montana
[[Page 74514]]
Ohio...................................... Nebraska
Pennsylvania.............................. Nevada
Rhode Island.............................. New Mexico
South Carolina............................ North Dakota
Tennessee................................. Oklahoma
Vermont................................... Oregon
Virginia.................................. South Dakota
West Virginia............................. Texas
Wisconsin................................. Utah
Washington
Wyoming
------------------------------------------------------------------------
Table W-2 to Subpart W of Part 98--Default Total Hydrocarbon Emission
Factors for Onshore Natural Gas Processing
------------------------------------------------------------------------
Emission
Factor (scf/
Onshore natural gas processing hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--Compressor Components, Gas Service
------------------------------------------------------------------------
Valve\1\................................................ 15.07
Connector............................................... 5.68
Open-Ended Line......................................... 17.54
Pressure Relief Valve................................... 40.27
Meter................................................... 19.63
------------------------------------------------------------------------
Leaker Emission Factors--Non-Compressor Components, Gas Service
------------------------------------------------------------------------
Valve................................................... 6.52
Connector............................................... 5.80
Open-Ended Line......................................... 11.44
Pressure Relief Valve................................... 2.04
Meter................................................... 2.98
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
Table W-3 to Subpart W of Part 98--Default Total Hydrocarbon Emission
Factors for Onshore Natural Gas Transmission Compression
------------------------------------------------------------------------
Emission
Factor (scf/
Onshore natural gas transmission compression hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--Compressor Components, Gas Service
------------------------------------------------------------------------
Valve\1\................................................ 15.07
Connector............................................... 5.68
Open-Ended Line......................................... 17.54
Pressure Relief Valve................................... 40.27
Meter................................................... 19.63
------------------------------------------------------------------------
Leaker Emission Factors--Non-Compressor Components, Gas Service
------------------------------------------------------------------------
Valve\1\................................................ 6.52
Connector............................................... 5.80
Open-Ended Line......................................... 11.44
Pressure Relief Valve................................... 2.04
Meter................................................... 2.98
------------------------------------------------------------------------
Population Emission Factors--Gas Service
------------------------------------------------------------------------
Low Continuous Bleed Pneumatic Device Vents\2\.......... 1.41
High Continuous Bleed Pneumatic Device Vents\2\......... 18.8
Intermittent Bleed Pneumatic Device Vents\2\............ 18.8
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Emission Factor is in units of ``scf/hour/device.''
Table W-4 to Subpart W of Part 98--Default Total Hydrocarbon Emission
Factors for Underground Natural Gas Storage
------------------------------------------------------------------------
Emission
Factor (scf/
Underground natural gas storage hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--Storage Station, Gas Service...................
------------------------------------------------------------------------
Valve \1\............................................... 15.07
Connector............................................... 5.68
Open-Ended Line......................................... 17.54
Pressure Relief Valve................................... 40.27
Meter................................................... 19.63
------------------------------------------------------------------------
Population Emission Factors--Storage Wellheads, Gas Service
------------------------------------------------------------------------
Connector............................................... 0.01
------------------------------------------------------------------------
Valve................................................... 0.10
Pressure Relief Valve................................... 0.17
------------------------------------------------------------------------
Leaker Emission Factors--Storage Station, Gas Service...................
------------------------------------------------------------------------
Open-ended Line......................................... 0.03
------------------------------------------------------------------------
Population Emission Factors--Other Components, Gas Service..............
------------------------------------------------------------------------
Low Continuous Bleed Pneumatic Device Vents \2\......... 1.41
High Continuous Bleed Pneumatic Device Vents \2\........ 18.8
Intermittent Bleed Pneumatic Device Vents \2\........... 18.8
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Emission Factor is in units of ``scf/hour/device''
Table W-5 to Subpart W of Part 98--Default Methane Emission Factors for
Liquefied Natural Gas (LNG) Storage
------------------------------------------------------------------------
Emission
Factor (scf/
LNG Storage hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--LNG Storage Components, LNG Service............
------------------------------------------------------------------------
Valve................................................... 1.21
Pump Seal............................................... 4.06
Connector............................................... 0.35
Other \1\............................................... 1.80
------------------------------------------------------------------------
Population Emission Factors--LNG Storage Compressor, Gas Service........
------------------------------------------------------------------------
Vapor Recovery Compressor\2\............................ 4.23
------------------------------------------------------------------------
\1\ ``other'' equipment type should be applied for any equipment type
other than connectors, pumps, or valves.
\2\ Emission Factor is in units of ``scf/hour/compressor.''
Table W-6 to Subpart W of Part 98--Default Methane Emission Factors for
LNG Import and Export Equipment
------------------------------------------------------------------------
Emission
Factor (scf/
LNG import and export equipment hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--LNG Terminals Components, LNG Service..........
------------------------------------------------------------------------
Valve................................................... 1.21
Pump Seal............................................... 4.06
Connector............................................... 0.35
Other \1\............................................... 1.80
------------------------------------------------------------------------
Population Emission Factors--LNG Terminals Compressor, Gas Service......
------------------------------------------------------------------------
Vapor Recovery Compressor \2\........................... 4.23
------------------------------------------------------------------------
\1\ ``other'' equipment type should be applied for any equipment type
other than connectors, pumps, or valves.
\2\ Emission Factor is in units of ``scf/hour/compressor.''
Table W-7 to Subpart W of Part 98--Default Methane Emission Factors for
Natural Gas Distribution
------------------------------------------------------------------------
Emission
Factor (scf/
Natural gas distribution hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--Above Grade M&R at City Gate Stations \1\
Components, Gas Service................................................
------------------------------------------------------------------------
Connector............................................... 1.72
Block Valve............................................. 0.566
Control Valve........................................... 9.48
Pressure Relief Valve................................... 0.274
Orifice Meter........................................... 0.215
[[Page 74515]]
Regulator............................................... 0.784
Open-ended Line......................................... 26.533
------------------------------------------------------------------------
Population Emission Factors--Below Grade M&R \2\ Components, Gas Service
\3\....................................................................
------------------------------------------------------------------------
Below Grade M&R Station, Inlet Pressure > 300 psig...... 1.32
Below Grade M&R Station, Inlet Pressure 100 to 300 psig. 0.20
Below Grade M&R Station, Inlet Pressure < 100 psig...... 0.10
------------------------------------------------------------------------
Population Emission Factors--Distribution Mains, Gas Service \4\........
------------------------------------------------------------------------
Unprotected Steel....................................... 12.77
Protected Steel......................................... 0.36
Plastic................................................. 1.15
Cast Iron............................................... 27.67
------------------------------------------------------------------------
Population Emission Factors--Distribution Services, Gas Service \5\.....
------------------------------------------------------------------------
Unprotected Steel....................................... 0.19
Protected Steel......................................... 0.02
Plastic................................................. 0.001
Copper.................................................. 0.03
------------------------------------------------------------------------
\1\ City gate stations at custody transfer and excluding customer
meters.
\2\ Excluding customer meters.
\3\ Emission Factor is in units of ``scf/hour/station''.
\4\ Emission Factor is in units of ``scf/hour/mile''.
\5\ Emission Factor is in units of ``scf/hour/number of services''.
[FR Doc. 2010-28655 Filed 11-29-10; 8:45 am]
BILLING CODE 6560-50-P