Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems, 64261-64298 [2015-25840]
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Vol. 80
Thursday,
No. 204
October 22, 2015
Part V
Environmental Protection Agency
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40 CFR Part 98
Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems; Final Rule
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Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 98
[EPA–HQ–OAR–2014–0831; FRL–9935–50–
OAR]
reported data and enhance
transparency. This action also finalizes
confidentiality determinations for new
data elements contained in these
amendments.
Environmental Protection
Agency (EPA).
ACTION: Final rule.
The Environmental Protection
Agency (EPA) is finalizing revisions and
confidentiality determinations for the
petroleum and natural gas systems
source category of the Greenhouse Gas
Reporting Rule. These revisions include
the addition of calculation methods and
reporting requirements for greenhouse
gas (GHG) emissions from gathering and
boosting facilities, completions and
workovers of oil wells with hydraulic
fracturing, and blowdowns of natural
gas transmission pipelines between
compressor stations. The revisions also
include the addition of well
identification reporting requirements to
improve the EPA’s ability to verify
This final rule is effective on
January 1, 2016.
ADDRESSES: The EPA has established a
docket for this action under Docket ID
No. EPA–HQ–OAR–2014–0831. All
documents in the docket are listed on
the https://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 electronically through https://
www.regulations.gov.
FOR FURTHER INFORMATION CONTACT:
RIN 2060–AS37
Greenhouse Gas Reporting Rule: 2015
Revisions and Confidentiality
Determinations for Petroleum and
Natural Gas Systems
AGENCY:
SUMMARY:
DATES:
Carole Cook, Climate Change Division,
Office of Atmospheric Programs (MC–
6207A), Environmental Protection
Agency, 1200 Pennsylvania Ave. NW.,
Washington, DC 20460; telephone
number: (202) 343–9263; fax number:
(202) 343–2342; email address:
GHGReportingRule@epa.gov. For
technical information, please go to the
Greenhouse Gas Reporting Rule Web
site, https://www.epa.gov/ghgreporting/.
To submit a question, select Help
Center, followed by ‘‘Contact Us.’’
Worldwide Web (WWW). In addition
to being available in the docket, an
electronic copy of this final rule will
also be available through the WWW.
Following the Administrator’s signature,
a copy of this action will be posted on
the EPA’s Greenhouse Gas Reporting
Rule Web site at https://www.epa.gov/
ghgreporting/.
SUPPLEMENTARY INFORMATION:
Regulated Entities. This final rule
adds calculation methods, monitoring,
and data reporting requirements and
finalizes confidentiality determinations
for the petroleum and natural gas
systems source category of the
Greenhouse Gas Reporting Rule (40 CFR
part 98). The Administrator determined
that 40 CFR part 98 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’’).
Entities affected by this final rule are
owners and operators of petroleum and
natural gas systems that directly emit
GHGs, which include those listed in
Table 1 of this preamble:
TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY
NAICS a
Category
Petroleum and Natural Gas Systems .........................................
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a North
211111
211112
221210
486210
Examples of affected facilities
Crude petroleum and natural gas extraction.
Natural gas liquid extraction.
Natural gas distribution.
Pipeline transportation of natural gas.
American Industry Classification System.
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. Types of facilities other than
those 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 and 40
CFR part 98, subpart W. If you have
questions regarding the applicability of
this action to a particular facility,
consult the person listed in the
preceding FOR FURTHER INFORMATION
CONTACT section.
What is the effective date? The final
rule is effective on January 1, 2016.
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
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for the District of Columbia Circuit (the
Court) by December 21, 2015. 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.
Section 307(d)(7)(B) of the CAA also
provides a mechanism for the EPA to
convene a proceeding for
reconsideration, ‘‘[i]f the person raising
an objection can demonstrate to the 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 the rule.’’ Any person
seeking to make such a demonstration to
us should submit a Petition for
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Reconsideration to the Office of the
Administrator, Environmental
Protection Agency, Room 3000, William
Jefferson Clinton Building, 1200
Pennsylvania Ave. NW., Washington,
DC 20460, 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 that 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 the EPA to
enforce these requirements.
Acronyms and Abbreviations. The
following acronyms and abbreviations
are used in this document.
AGR
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acid gas removal
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API American Petroleum Institute
BAMM best available monitoring methods
CAA Clean Air Act
CBI confidential business information
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e carbon dioxide equivalent
e-GGRT Electronic Greenhouse Gas
Reporting Tool
EPA U.S. Environmental Protection Agency
FERC Federal Energy Regulatory
Commission
FR Federal Register
ft3 cubic feet
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GOR gas to oil ratio
GRI Gas Research Institute
ICR information collection request
ID identification
LDC local distribution company
N2O nitrous oxide
NAICS North American Industry
Classification System
NGO non-government organization
NGPA Natural Gas Policy Act
NTTAA National Technology Transfer and
Advancement Act
O&M operation and maintenance
OMB Office of Management and Budget
PHMSA Pipeline and Hazardous Materials
Safety Administration
psi/ft pounds per square inch per foot
REC reduced emissions completion
RFA Regulatory Flexibility Act
scf standard cubic feet
scf/STB standard cubic feet per stock tank
barrel
U.S. United States
UMRA Unfunded Mandates Reform Act of
1995
WWW worldwide web
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Organization of This Document. The
following outline is provided to aid in
locating information in this preamble.
I. Background
A. Organization of This Preamble
B. Background on This Action
C. Legal Authority
D. How do these amendments apply to
2015 and 2016 reports?
II. Summary of Final Revisions and Other
Amendments to Subpart W and
Responses to Public Comment
A. Summary of Final Amendments for Oil
Wells With Hydraulic Fracturing
B. Summary of Final Amendments for the
Onshore Petroleum and Natural Gas
Gathering and Boosting Segment
C. Summary of Final Amendments for the
Onshore Natural Gas Transmission
Pipeline Segment
D. Summary of Final Amendments for Well
Identification Numbers
E. Summary of Final Amendments to Best
Available Monitoring Methods
III. Final Confidentiality Determinations
A. Summary of Final Confidentiality
Determinations for New Subpart W Data
Elements
B. Summary of Public Comments and
Responses on the Proposed
Confidentiality Determinations
IV. Impacts of the Final Amendments to
Subpart W
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A. Impacts of the Final Amendments
B. Summary of Comments and Responses
on the Impacts of the Proposed Rule
V. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act
(UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
H. Executive Order 13211: Actions
Concerning Regulations 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
Section I of this preamble provides
background information regarding the
origin of the final amendments. This
section also discusses the EPA’s legal
authority under the CAA to promulgate
and amend 40 CFR part 98 of the
Greenhouse Gas Reporting Rule
(hereafter referred to as ‘‘part 98’’) as
well as the legal authority for making
confidentiality determinations for the
data to be reported. Section II of this
preamble contains information on the
final amendments to part 98, subpart W
(Petroleum and Natural Gas Systems)
(hereafter referred to as ‘‘subpart W’’),
including a summary of the major
comments that the EPA considered in
the development of this final rule.
Section III of this preamble discusses
the final confidentiality determinations
for new data reporting elements. Section
IV of this preamble discusses the
impacts of the final amendments to
subpart W. Finally, Section V of this
preamble describes the statutory and
executive order requirements applicable
to this action.
B. Background on This Action
The EPA’s Greenhouse Gas Reporting
Program (GHGRP) requires annual
reporting of GHG data and other
relevant information from large sources
and suppliers in the United States. On
October 30, 2009, the EPA published
part 98 for collecting information
regarding GHG emissions from a broad
range of industry sectors (74 FR 56260).
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Although reporting requirements for
petroleum and natural gas systems were
originally proposed to be part of part 98
(75 FR 16448; April 10, 2009), the final
October 2009 rule did not include the
petroleum and natural gas systems
source category as one of the 29 source
categories for which reporting
requirements were finalized. The EPA
re-proposed subpart W in 2010 (79 FR
18608; April 12, 2010), and a
subsequent final rule was published on
November 30, 2010, with the
requirements for the petroleum and
natural gas systems source category at
40 CFR part 98, subpart W (75 FR
74458) (hereafter referred to as ‘‘the
final subpart W rule’’). Following
promulgation, the EPA finalized actions
revising subpart W (76 FR 22825, April
25, 2011; 76 FR 59533, September 27,
2011; 76 FR 80554, December 23, 2011;
77 FR 51477, August 24, 2012; 78 FR
25392, May 1, 2013; 78 FR 71904,
November 29, 2013; 79 FR 63750,
October 24, 2014; 79 FR 70352,
November 25, 2014).
On December 9, 2014, the EPA
proposed ‘‘2015 Revisions and
Confidentiality Determinations for
Petroleum and Natural Gas Systems’’
(79 FR 76267) to require the reporting of
GHG emissions from several sources
that had not previously been included
in subpart W. These sources include
completions and workovers of oil wells
with hydraulic fracturing, petroleum
and natural gas gathering and boosting
systems, and transmission pipeline
blowdowns between compressor
stations. The reporting requirements for
completions and workovers of oil wells
with hydraulic fracturing were proposed
to be included as part of the existing
Onshore Petroleum and Natural Gas
Production industry segment. For the
other sources, the EPA proposed two
new industry segments: The Onshore
Petroleum and Natural Gas Gathering
and Boosting segment for petroleum and
natural gas gathering and boosting
facilities, and the Onshore Natural Gas
Transmission Pipeline segment for
transmission pipeline blowdowns
between compressor stations. The EPA
also proposed to require the reporting of
a well identification number for oil and
gas wells covered in the Onshore
Petroleum and Natural Gas Production
segment. In addition, the EPA proposed
confidentiality determinations for new
data elements contained in the proposed
amendments. The public comment
period for these proposed rule
amendments ended on February 24,
2015, following a 2-week extension of
the original comment period end date
(80 FR 6495; February 5, 2015).
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In this action, the EPA is finalizing
additions and revisions to the subpart W
calculation, monitoring, and reporting
requirements for new sources, with
some changes made in response to
public comments. Responses to
comments submitted on the proposed
amendments can be found in sections II,
III, and IV of this preamble as well as
in ‘‘Response to Public Comments on
Greenhouse Gas Reporting Rule: 2015
Revisions and Confidentiality
Determinations for Petroleum and
Natural Gas Systems’’ in Docket ID No.
EPA–HQ–OAR–2014–0831. As noted in
the preamble to the proposed
amendments (79 FR 73148; December 9,
2014), these additions and revisions
further the EPA’s goals of improving the
completeness, quality, accuracy, and
transparency of data from this sector,
and improving the ability of agencies
and the public to use these GHG data to
analyze emissions and understand
emission trends.
The Strategy to Reduce Methane
Emissions in the President’s Climate
Action Plan summarizes the sources of
methane (CH4) emissions, commits to
new steps to cut emissions of this potent
GHG, and outlines the Administration’s
efforts to improve the measurement of
these emissions. The strategy builds on
progress to date and takes steps to
further cut CH4 emissions from several
sectors, including the oil and natural gas
sector. In the strategy, the EPA was
tasked to review regulatory
requirements to address potential gaps
in coverage, improve methods, and help
ensure high quality data reporting.1 The
final revisions to subpart W covered in
this action are responsive to this task by
addressing data gaps in subpart W,
specifying methods for measuring CH4
emissions, and providing data that can
be used to further analyze CH4
emissions in this industry.
This action also addresses a petition
the EPA received from a group of non-
government organizations (NGOs)
requesting that the EPA collect data
from emissions sources not currently
included in subpart W, including well
completion emissions from oil wells
that co-produce natural gas, facilities
and pipelines in the gathering and
boosting segment, and transmission
pipeline blowdown events (‘‘Petition for
Rulemaking’’).2 Table 2 of this preamble
summarizes how the EPA has
responded to the Petition for
Rulemaking. These revisions, and
previously finalized revisions where
noted in Table 2, reflect the EPA’s
complete response to the Petition for
Rulemaking. It is our position that we
have fully responded to the NGO
petition, however, any requests
included in the petition that have not
been responded to in Table 2 are
considered denied.
TABLE 2—EPA RESPONSE TO PETITION FOR RULEMAKING
Final rule citations
(40 CFR)
Request in petition
EPA’s response
Clarify that oil wells that co-produce natural gas (‘‘coproducing wells’’), specifically wells in tight-oil formations like the Bakken and Eagle Ford, are subject to
the completion reporting requirements as currently
written. Expand the well completion reporting requirements to all wells, ensuring co-producing wells in any
formation type are required to report completion emissions.
Require reporting from facilities and pipelines in the
gathering and boosting segment of the natural gas industry.
The EPA is not changing the definition of ‘‘gas well’’ or
‘‘oil well.’’ Instead, the EPA is amending subpart W to
require the reporting of GHG emissions from completions and workovers with hydraulic fracturing for wells
in the Onshore Petroleum and Natural Gas Production segment, regardless of whether their primary
product is oil or natural gas.
98.232(c)(6)
98.232(c)(8)
98.236(g)
The EPA is finalizing the proposal to amend subpart W
to add a new industry segment, Onshore Petroleum
and Natural Gas Gathering and Boosting, which covers emissions from equipment used by gathering
pipeline systems that move petroleum and natural
gas from the well to either larger gathering pipeline
systems, natural gas processing plants, natural gas
transmission pipelines, or natural gas distribution
pipelines.
The EPA is finalizing the proposal to add reporting requirements for emissions from natural gas transmission pipeline blowdowns between compressor
stations in a new Onshore Natural Gas Transmission
Pipeline segment.
The EPA is requiring the reporting of well identification
numbers for the Onshore Petroleum and Natural Gas
Production segment for information related specifically to wells.
98.230(a)(9)
98.232(j)
98.233 (various)
98.236(a)(9)
Prior to these amendments, BAMM was discontinued
for all sources except specific sources that were affected by the amendments finalized on November 25,
2014 (79 FR 70352); those BAMM provisions will be
unavailable after December 31, 2015. Reporters will
be allowed to use BAMM for the 2016 reporting year
for only the new industry segments and emission
sources included in this action. The EPA is not allowing the use of BAMM beyond 2016.
98.234(f) and (g)
Require reporting from transmission pipeline blowdown
events.
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Require reporters to include API well identification numbers along with their submissions to help the public
and policymakers understand which sources are reporting and how the threshold may be adjusted to
most effectively provide emissions information.
Phase out the use of best available monitoring methods
(BAMM), which will further help to ensure Subpart W
data are rigorous, and comprehensive.
1 Climate Action Plan—Strategy to Reduce
Methane Emissions. The White House, Washington,
DC, March 2014. Available at https://
www.whitehouse.gov/sites/default/files/strategy_to_
reduce_methane_emissions_2014-03-28_final.pdf.
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2 Petition for Rulemaking and Interpretive
Guidance Ensuring Comprehensive Coverage of
Methane Sources Under Subpart W of the
Greenhouse Gas Reporting Rule—Petroleum And
Natural Gas Systems; Submitted by Clean Air Task
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98.230(a)(10)
98.232(m)
98.236(aa)(11)
98.236(f), (g), (h), (l), and
(m)
98.238
Force, Environmental Defense Fund, Natural
Resources Defense Council, and Sierra Club; March
19, 2013. Docket Item No. EPA–HQ–OAR–2014–
0831–0005.
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TABLE 2—EPA RESPONSE TO PETITION FOR RULEMAKING—Continued
Final rule citations
(40 CFR)
Request in petition
EPA’s response
Consider including advanced innovative monitoring
methods as a way to accelerate development and deployment of real-time continuous CH4 emission monitoring in the oil and natural gas sector.
The agency is assessing the potential opportunities for
application of remote sensing technologies and other
innovations in measurement or monitoring technology
to identifying and calculating emissions from affected
sources under subpart W and requested comment in
the proposal. The EPA received multiple comments
in response to the request for comments on the feasibility, possible regulatory approaches, and provisions necessary to incorporate or allow the use of
advanced measurement or monitoring methods in
subpart W. All of the comments received are included in ‘‘Response to Public Comments on Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems’’ in Docket ID No. EPA–HQ–OAR–
2014–0831. The EPA is not including provisions related to advanced measurement or monitoring methods in this rule and is not responding to these comments in this rulemaking. Instead, following review of
the data and information received in comments, the
EPA may propose amendments related to the use of
innovative technologies in reporting to the GHGRP in
a future rulemaking.
Legal Authority
The EPA is finalizing these rule
amendments under its existing CAA
authority provided in CAA section 114.
As stated in the preamble to the 2009
final GHG reporting rule (74 FR 56260;
October 30, 2009), CAA section
114(a)(1) provides the EPA broad
authority to require the information to
be gathered by this rule because such
data would inform and are relevant to
the EPA’s carrying out a wide variety of
CAA provisions. See the preambles to
the proposed (74 FR 16448; April 10,
2009) and final GHG reporting rule (74
FR 56260; October 30, 2009) for further
information.
In addition, pursuant to sections 114,
301, and 307 of the CAA, the EPA is
publishing final confidentiality
determinations for the new data
elements required by these
amendments. Section 114(c) requires
that the EPA make information obtained
under section 114 available to the
public, except for information that
qualifies for confidential treatment. The
Administrator has determined that this
action is subject to the provisions of
section 307(d) of the CAA.
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D. How do these amendments apply to
2015 and 2016 reports?
These amendments are effective on
January 1, 2016. Thus, beginning on
January 1, 2016, facilities must follow
the revised methods in subpart W, as
amended, to calculate emissions
occurring during the 2016 calendar year
(i.e., reporting year 2016). The first
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annual reports of emissions calculated
using the amended requirements will be
those submitted by March 31, 2017,
covering reporting year 2016. For
reporting year 2015, reporters will
continue to calculate emissions and
other relevant data for the reports that
are submitted according to the
requirements in part 98 that are
applicable to reporting year 2015 (i.e.,
the requirements in place until the
effective date of this final rule).
For reporting year 2016 only, we are
allowing the use of best available
monitoring methods (BAMM) on a
short-term transitional basis for facilities
new to reporting under subpart W as
well as reporters of facilities subject to
new monitoring requirements associated
with these revisions. Reporters have the
option of using BAMM for only the new
industry segments and emission sources
included in this action from January 1,
2016, to December 31, 2016, without
seeking prior EPA approval. The EPA
will not accept requests for an extension
for the use of BAMM beyond the time
periods listed above. The EPA is not
allowing the use of BAMM for the new
well identification number provisions in
the Onshore Petroleum and Natural Gas
Production segment because the well
identification number is not a parameter
that requires monitoring equipment to
be measured and, therefore, does not
meet the requirements for BAMM. In
addition, reporters should already have
well identification numbers readily
available for all wells and associated
equipment to which this reporting
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requirement applies. See section II.E of
this preamble for more information.
II. Summary of Final Revisions and
Other Amendments to Subpart W and
Responses to Public Comment
In this action, the EPA is amending
subpart W to require the reporting of
GHG emissions from completions and
workovers of oil wells with hydraulic
fracturing as part of the existing
Onshore Petroleum and Natural Gas
Production industry segment. The EPA
is also adding requirements for two new
industry segments: the Onshore
Petroleum and Natural Gas Gathering
and Boosting segment for petroleum and
natural gas gathering and boosting
systems, and the Onshore Natural Gas
Transmission Pipeline segment for
transmission pipeline blowdowns
between compressor stations. Finally,
the EPA is requiring the reporting of
well identification numbers for oil and
gas well-specific information (e.g.,
completions and workovers, associated
gas venting and flaring) reported in the
Onshore Petroleum and Natural Gas
Production segment. The comments
received on this rule generally did not
dispute the merit of adding these new
segments and sources to subpart W, but
they did provide a number of
suggestions regarding the technical
details of monitoring, reporting, and
applicability.
Sections II.A through II.E of this
preamble describe the requirements and
other amendments that we are finalizing
in this rulemaking. Section II.A
describes the final amendments for the
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reporting of GHG emissions from
completions and workovers of oil wells
with hydraulic fracturing. Section II.B
describes the final amendments for the
reporting of GHG emissions from
sources in the new Onshore Petroleum
and Natural Gas Gathering and Boosting
segment. Section II.C describes the final
amendments for the reporting of GHG
emissions from sources in the new
Onshore Natural Gas Transmission
Pipeline segment. Section II.D describes
the requirements for reporting well
identification numbers for the Onshore
Petroleum and Natural Gas Production
segment. Finally, section II.E provides a
summary of the final amendments to the
best available monitoring method
requirements. The amendments
described in each section are followed
by a summary of the major comments on
those amendments and the EPA’s
responses. See ‘‘Response to Public
Comments on Greenhouse Gas
Reporting Rule: 2015 Revisions and
Confidentiality Determinations for
Petroleum and Natural Gas Systems’’ in
Docket ID No. EPA–HQ–OAR–2014–
0831 for a complete listing of all
comments and the EPA’s responses.
Finally, in the preamble to the
proposed rule, the EPA stated that the
agency is ‘‘assessing the potential
opportunities for applying remote
sensing technologies and other
innovations in measurement or
monitoring technology to identifying
and calculating emissions from affected
sources under subpart W’’ (79 FR 73148;
December 9, 2014). The EPA did not
propose, and therefore is not finalizing,
any amendments to subpart W to this
effect, but the EPA did request comment
on the feasibility, possible regulatory
approaches, provisions necessary to
incorporate or allow the use of
advanced measurement or monitoring
methods in subpart W, and methods to
ensure compliance with those
provisions in an efficient manner. The
EPA also requested comment on the
memorandum ‘‘Discussion Paper on
Potential Implementation of Alternative
Monitoring under the GHGRP’’ in
Docket ID No. EPA–HQ–OAR–2014–
0831. All of the comments received are
included in ‘‘Response to Public
Comments on Greenhouse Gas
Reporting Rule: 2015 Revisions and
Confidentiality Determinations for
Petroleum and Natural Gas Systems’’ in
Docket ID No. EPA–HQ–OAR–2014–
0831. The EPA will consider these
comments in the context of any future
action related to alternative monitoring.
The amendments in this action will
advance EPA’s goal of maximizing rule
effectiveness. For example, these
amendments provide clear monitoring,
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calculation and reporting requirements
for new segments and sources in subpart
W, thus enabling government, regulated
entities, and the public to easily identify
and understand rule requirements. In
addition, specific changes such as
increasing the flexibility and time
period for transitional BAMM will make
compliance easier than non-compliance.
These amendments will also improve
the EPA’s ability to assess compliance
by adding reporting elements that allow
the EPA to more thoroughly verify
greenhouse gas data and understand
trends in emissions. For example, the
requirement for the Onshore Petroleum
and Natural Gas Production segment to
report well identification numbers will
allow the EPA to link GHGRP data with
other data sources and assess the
completeness and representativeness of
the data collected relative to all activity
in the U.S. oil and gas production
sector. Lastly, these amendments further
advance the ability of the GHGRP to
provide access to quality data on
greenhouse gas emissions by adding key
petroleum and natural gas emission
sources to this program. One example is
the addition of the Onshore Petroleum
and Natural Gas Gathering and Boosting
segment, a significant greenhouse gas
emissions segment that had not been
previously covered under the GHGRP.
A. Summary of Final Amendments for
Oil Wells With Hydraulic Fracturing
1. Summary of Final Amendments
The EPA is amending subpart W to
require the reporting of GHG emissions
from completions and workovers with
hydraulic fracturing for wells in the
Onshore Petroleum and Natural Gas
Production segment, regardless of
whether their primary product is oil or
natural gas. In general, commenters
supported inclusion of emissions from
completions and workovers of oil wells
with hydraulic fracturing in subpart W,
and a few commenters provided
targeted technical edits and suggestions
for this source. Consistent with the
requirements for completions and
workovers of gas wells with hydraulic
fracturing, and consistent with the
proposed requirements, the new
provisions include the reporting of
activity data on the number of
completions and workovers of oil wells
with hydraulic fracturing and on the use
of flaring and reduced emission
completions (RECs). In response to
public comments, the final monitoring
and reporting amendments do not apply
to completions and workovers of oil
wells with hydraulic fracturing that
have a gas to oil ratio (GOR) of less than
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300 standard cubic feet per stock tank
barrel (scf/STB).
The EPA is also amending the
equations and definitions in 40 CFR
98.233(g) to reflect applicability to
completions and workovers of all gas
and oil wells with hydraulic fracturing.
As in the proposal, the final
amendments require the use of either
Equation W–10A or W–10B for
calculating GHG emissions from
completions and workovers of oil wells
with hydraulic fracturing. Equation W–
10A is used to calculate emissions from
wells using inputs obtained from a
representative sample of wells within a
sub-basin and the ratio of the gas
flowback rate to the production flow
rate, and Equation W–10B is used to
calculate emissions using inputs
obtained from all wells within a subbasin and the flow rate and flow volume
of the gas vented or flared. As proposed,
the EPA is finalizing that emissions be
calculated and reported separately for
gas wells and oil wells by sub-basin and
well type combination.3 Furthermore, as
proposed, the final amendments require
the use of Calculation Method 1 for
calculating inputs to Equations W–12A
and W–12B for oil wells. Calculation
Method 1 relies on direct measurement
of gas flow rate during flowback to
develop calculation inputs; the
requirements for the location of the flow
meter used to measure the gas flow rate
for oil wells are the same as the location
requirements for gas wells. Other
provisions that apply to completions
and workovers of gas wells with
hydraulic fracturing also apply to
completions and workovers of oil wells
with hydraulic fracturing, including the
determination of wells that constitute a
representative sample for use in
Equation W–10A.
For oil wells that do not meter gas
production, such as some wells with a
relatively low GOR, the EPA is adding
a new Equation W–12C as proposed to
calculate, rather than measure, the value
of PRs,p (the average gas production flow
rate during the first 30 days of
production after the completion or
workover), which is used as an input to
Equation W–10A. In this Equation W–
12C, the value of PRs,p is calculated by
multiplying the GOR of the well by the
measured oil production rate over the
3 Within subpart W, an individual well is labeled
an ‘‘oil well’’ or ‘‘gas well’’ depending on the
formation type reported for that well. If wells
produce from more than one formation type, then
the well is classified into only one type based on
the formation type with the most contribution to
production as determined by the reporter’s
engineering knowledge. See the definition of ‘‘Subbasin category, for onshore natural gas production’’
in 40 CFR 98.238.
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first 30 days of production after the
completion or workover.
2. Summary of Comments and
Responses
Comment: Several commenters
responded to the EPA’s request for
comment on whether to establish a
minimum GOR threshold such that oil
wells with a very low GOR would not
be subject to the monitoring and
reporting requirements for GHG
emissions from completions and
workovers with hydraulic fracturing.
Most of these commenters supported
establishment of a cutoff for wells with
very low emissions. One commenter
urged the EPA to require monitoring
and reporting for all completions and
workovers with hydraulic fracturing but
stated that if a threshold is set, it should
be set at a level that ensures that all
significant emissions sources are
included and that sources are able to
clearly determine whether they are
required to report. Three commenters
supported setting a minimum GOR
threshold. One commenter suggested a
minimum GOR threshold of 300 and
stated that, based on industry
experience, oil wells with GOR values
less than 300 do not have sufficient gas
to operate a separator. The second
commenter agreed that operators should
only have to monitor and report
emissions if the GOR is great enough to
operate a separator and direct
measurement is possible. The third
commenter supporting a minimum GOR
threshold did not provide a suggestion
for a specific numeric threshold but
stated that the emissions from wells
with a low GOR are insignificant, and
the time and resources involved in
measuring the flowback and reporting
emissions for wells expected to have
minimal emissions would outweigh any
contribution of these emissions to the
overall source category totals. This
commenter supported the inclusion of a
threshold so that only significant
sources of emissions would be included.
Response: The EPA agrees that
including a minimum GOR threshold
will help minimize reporting burden
while still capturing most of the
emissions from this source. Energy
Information Administration data show
that the number of ‘‘oil only’’ wells
drilled from 2007–2012 was less than 20
percent of all new wells.4 These wells
would have a GOR approaching zero
4 In this analysis, all hydrocarbon production in
the liquid state at the wellhead was considered oil.
J. Lieskovsky and S. Gorgen. ‘‘Drilling often results
in both oil and natural gas production.’’ Today in
Energy, U.S. Energy Information Administration,
October 29, 2013. https://www.eia.gov/todayin
energy/detail.cfm?id=13571. Accessed June 9, 2015.
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and, therefore, would be expected to
have low emissions. We believe that
having no threshold may create an
unnecessary burden for operators to
report emissions for these wells with
just a trace of gas. Given that the EPA
is finalizing the proposed requirement
that the oil well flow meter be located
downstream of the separator, the
separator must be operating for the
owner or operator to be able to measure
the flow rate and estimate emissions
from completions and workovers of oil
wells with hydraulic fracturing. One
commenter, an industry trade
association, suggested a threshold of 300
scf/STB based on the industry trade
association’s experience that separators
typically do not operate at a GOR less
than 300 scf/STB.
The primary concern when
determining the level for a threshold is
volatility; the threshold must be low
enough that the oil produced is
considered non-volatile. Non-volatile
‘‘black oils’’ (i.e., oil likely to not have
gases or light hydrocarbons associated
with it) are generally defined as having
GOR values in the range of 200 to 900
scf/STB.5 Oil wells with a GOR less than
the 300 scf/STB suggested by the
commenter are at the lower end of this
range, and completions and workovers
with hydraulic fracturing of these wells
will not likely have enough gas
associated that can be separated.
Therefore, the final monitoring and
reporting requirements do not apply to
completions and workovers of oil wells
with hydraulic fracturing that have a
GOR of less than 300 scf/STB.
Comment: Several commenters
responded to the EPA’s request for
comment on whether to establish a
minimum well pressure threshold such
that oil wells with a very low well
pressure would not be subject to the
monitoring and reporting requirements
for GHG emissions from completions
and workovers with hydraulic
fracturing. Most of these commenters
supported establishment of a cutoff for
wells with very low well pressure. One
commenter urged the EPA to require
monitoring and reporting for all
completions and workovers with
hydraulic fracturing but stated that if a
threshold is set, it should be set at a
level that ensures that all significant
emissions sources are included and that
sources are able to clearly determine
whether they are required to report.
Three commenters supported setting a
minimum well pressure threshold. One
5 M.P. Walsh. ‘‘Oil Reservoir Primary Drive
Mechanisms.’’ In Petroleum Engineering Handbook,
Volume V: Reservoir Engineering and Petrophysics,
E.D. Holstein (Ed.), L.W. Lake (Ed. in Chief), pp. V–
895–980. Society of Petroleum Engineers, 2007.
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commenter suggested a minimum well
pressure threshold of 0.4645 pounds per
square inch per foot (psi/ft) because this
is the vertical pressure gradient needed
for a well to flow back, based on
experience with the Natural Gas STAR
program. The second commenter
suggested that operators should only
have to monitor and report emissions if
the pressure of the reservoir during oil
well completions and workovers is
greater than the pressure gradient of
0.433 psi/ft and noted that the pressure
needed varies based on the density of
the materials in the column and the
depth of the well. The third commenter
supporting a minimum well pressure
threshold did not provide a suggestion
for a threshold but supported the
inclusion of a threshold so that only
significant sources of emissions would
be included.
Response: The EPA evaluated the
commenters’ suggestions and has
decided not to include a minimum well
pressure threshold. Both commenters
who suggested a specific value noted in
their comments that these pressure
gradients are the minimum needed for
the well to produce. In other words,
according to the commenters’ rationale,
wells with pressures below the
suggested pressure thresholds would
not have any production, regardless of
whether a threshold is included in the
final rule. As a result, specifying that
reporting of emissions from completions
and workovers of oil wells with
hydraulic fracturing is not required
below those pressures is redundant.
Therefore, the final rule does not
include a minimum well or reservoir
pressure threshold for completions and
workovers of oil wells with hydraulic
fracturing.
B. Summary of Final Amendments for
the Onshore Petroleum and Natural Gas
Gathering and Boosting Segment
The EPA is amending subpart W to
add a new industry segment, Onshore
Petroleum and Natural Gas Gathering
and Boosting, that covers emissions
from equipment used by gathering
pipeline systems that move petroleum
and natural gas from the well to either
larger gathering pipeline systems,
natural gas processing plants, natural
gas transmission pipelines, or natural
gas distribution pipelines. A gathering
and boosting system is a single network
of pipelines, compressors and process
equipment, including equipment to
perform natural gas compression,
dehydration, and acid gas removal, that
has one or more well-defined
connection points to gas and oil
production and a well-defined
downstream endpoint, typically a gas
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processing plant or transmission
pipeline. Gathering pipelines are
pipelines used to transport gas from the
furthermost downstream point in an
onshore production facility to certain
endpoints, generally either a gas
processing facility or point of
connection to a transmission pipeline.
Compressors located along the gathering
and boosting system are used to control
or ‘‘boost’’ the pressure of the gas in the
pipeline and keep the gas moving
downstream. Commenters generally
supported inclusion of gathering and
boosting system emissions in subpart W,
and many commenters suggested
targeted revisions concerning
definitions, what emission sources
should be included in the segment and
methods for individual emission
sources.
The remainder of this section
describes the final reporting
requirements for this new industry
segment, including the segment
description, definitions, calculation
methods, and information to be
reported. The amendments described in
each section are followed by a summary
of the major comments, if any, on those
amendments and the EPA’s responses.
See ‘‘Response to Public Comments on
Greenhouse Gas Reporting Rule: 2015
Revisions and Confidentiality
Determinations for Petroleum and
Natural Gas Systems’’ in Docket ID No.
EPA–HQ–OAR–2014–0831 for a
complete listing of all comments and
the EPA’s responses.
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1. Segment Description for the Onshore
Petroleum and Natural Gas Gathering
and Boosting Segment
a. Summary of Final Amendments
The EPA is finalizing the definition of
the Onshore Petroleum and Natural Gas
Gathering and Boosting segment in 40
CFR 98.230 as gathering pipelines and
other equipment used to collect
petroleum and/or natural gas from
onshore production gas or oil wells and
used to compress, dehydrate, sweeten,
or transport the petroleum and/or
natural gas to a natural gas processing
facility, a natural gas transmission
pipeline, or a natural gas distribution
pipeline. Gathering and boosting
equipment includes, but is not limited
to, gathering pipelines, separators,
compressors, acid gas removal (AGR)
units, dehydrators, pneumatic devices/
pumps, storage vessels, engines, boilers,
heaters, and flares. The Onshore
Petroleum and Natural Gas Gathering
and Boosting segment does not include
equipment and pipelines that are
reported under any other industry
segment defined in subpart W. The
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segment definition is being finalized as
proposed, except that the final
amendments provide two clarifications
regarding gathering pipelines. First,
gathering pipelines operating on a
vacuum are not included because they
would not be expected to have
emissions. Second, to address
comments regarding the inclusion of
liquid and multiphase streams in the
segment, the definition clarifies that
gathering pipelines with a GOR less
than 300 scf/STB are not a part of the
segment.
b. Summary of Comments and
Responses
Comment: Commenters requested that
the EPA remove ‘‘Petroleum and’’ from
the proposed segment name, ‘‘Onshore
Petroleum and Natural Gas Gathering
and Boosting.’’ The commenters
asserted that the removal would provide
a clear demarcation between onshore
petroleum and natural gas production
and onshore natural gas gathering and
boosting. They also stated that such a
change would be more consistent with
the segment definition, which includes
pipelines and equipment ‘‘used to
compress, dehydrate, sweeten, or
transport the gas to a natural gas
processing facility, a natural gas
transmission pipeline or to a natural gas
distribution pipeline.’’ The commenter
stated that the type of equipment
included in the gathering and boosting
segment is ‘‘synonymous’’ with gas
gathering and boosting systems, not
liquid or petroleum, and they noted that
the emission factor for equipment leaks
from gathering pipelines is not
applicable to gathering pipelines that
carry mostly liquid.
Commenters also specifically
requested that the EPA exclude
petroleum gathering pipelines from the
gathering and boosting segment because
the fugitive gas emissions from these
gathering pipelines would be negligible.
Both commenters stated that the
proposed emission factor for gathering
pipeline leaks is only applicable to gas
gathering pipelines. Two commenters
also requested that multi-phase flow
lines from wells to a centralized
production facility where initial
separation occurs be retained in the
Onshore Petroleum and Natural Gas
Production segment rather than
included in the new gathering and
boosting segment.
Response: The EPA is finalizing the
segment name as proposed and not
removing ‘‘Petroleum and’’ from the
segment name or moving multiphase
gathering pipelines to the Onshore
Petroleum and Natural Gas Production
segment. We proposed including
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‘‘Petroleum and’’ in the segment name
to reflect the complex nature of
upstream operations where wells can
produce oil, natural gas, or a mixture of
both and to signify the inclusion of GHG
emissions from gathering and boosting
systems moving high volatility liquids
in this new segment. Even in wells that
produce primarily liquids at surface
temperature and pressure conditions,
there is often a volatile gaseous
component. This associated gas is
usually considered wet due to the high
content of natural gas liquids (volatile
components) to go along with gaseous
CH4. Similarly, the inclusion of all
petroleum gathering pipelines in the
Onshore Petroleum and Natural Gas
Gathering and Boosting segment,
including multiphase pipelines, is
appropriate, because gathering lines are
a key component to gathering and
boosting systems. Therefore, all
gathering pipelines that collect
petroleum and/or natural gas from
onshore production gas or oil wells and
transport the petroleum and/or natural
gas to a natural gas processing facility,
a natural gas transmission pipeline or to
a natural gas distribution pipeline are
considered part of the final Onshore
Petroleum and Natural Gas Gathering
and Boosting segment.
However, the EPA does agree that
gathering pipelines carrying mostly oil
have a low potential for GHG emissions.
We note that the ratio of CH4 to volatile
components increases as the GOR
increases. Therefore, to clarify our
intent to exclude gathering pipelines
containing oil, the final rule clarifies
that the Onshore Petroleum and Natural
Gas Gathering and Boosting segment
does not include gathering pipelines
with a GOR of less than 300 scf/STB.
Operators of gathering pipelines below
that threshold are not required to
include those pipelines in their
gathering and boosting facility. See
section II.B.5 of this preamble for
additional discussion.
Finally, as part of evaluating this
comment, the EPA reviewed the
proposed definitions related to the
Onshore Petroleum and Natural Gas
Gathering and Boosting segment and
recognizes that two of them referred to
‘‘the gas’’ rather than ‘‘the petroleum
and/or natural gas.’’ One was the
proposed description of the Onshore
Petroleum and Natural Gas Gathering
and Boosting segment in 40 CFR 98.230,
as identified by the commenters, and
the other was the definition of
‘‘gathering and boosting system owner
or operator’’ in 40 CFR 98.238. For
consistency throughout the final rule
with the intent stated in this response,
the final description of the Onshore
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Petroleum and Natural Gas Gathering
and Boosting segment in 40 CFR 98.230
refers to ‘‘petroleum and/or natural gas’’
and the final definition of ‘‘gathering
and boosting system owner or operator’’
in 40 CFR 98.238 refers to ‘‘the
petroleum or natural gas transported.’’
Comment: One commenter stated that
there may be confusion regarding which
equipment should be reported in the
different industry segments, which
could lead to emissions being
mistakenly excluded or double-counted.
For example, gathering and boosting
equipment located on a single well pad
or associated with a single well pad
could be double-counted, especially if it
is operated by one entity but owned by
another. The commenter also noted that
confusion over the proper segment for
this type of equipment could make the
difference between reporting emissions
or not reporting emissions if a facility is
close to the reporting threshold of
25,000 metric tons carbon dioxide
equivalent (CO2e). Therefore, the
commenter requested that the EPA
incorporate by reference the U.S.
Department of Transportation’s Pipeline
and Hazardous Materials Safety
Administration (PHMSA) federally
defined boundaries of production,
gathering and boosting, and
transmission segments to ensure state/
federal transparency and consistency.
Response: The EPA is not changing
the segment description for the Onshore
Petroleum and Natural Gas Production
segment in 40 CFR 98.230(a)(2) or the
Onshore Natural Gas Processing
segment in 40 CFR 98.230(a)(3). As
stated at proposal, the EPA decided not
to make any changes to the existing
segment descriptions to provide
consistency for reporters in that
segment. This decision allows the EPA
to ensure that the data gap in subpart W
related to gathering and boosting
systems is addressed while minimizing
confusion over changes to other
segments. Instead, the EPA is reiterating
the intention for the Onshore Petroleum
and Natural Gas Gathering and Boosting
segment to cover equipment and
emission sources not included in
reporting for the existing Onshore
Petroleum and Natural Gas Production
or Onshore Natural Gas Processing
segments.
The EPA does not agree that
emissions from the same equipment will
be reported under more than one
industry segment in a given reporting
year; however, we acknowledge that
similar equipment may exist in adjacent
industry segments as defined in subpart
W. The owner or operator of the
equipment in question should first
determine if that equipment is subject to
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reporting in another segment of subpart
W, such as the Onshore Petroleum and
Natural Gas Production or Onshore
Natural Gas Processing segments. If the
equipment is not subject to reporting in
another segment of subpart W, then the
owner or operator should evaluate
whether or not the equipment is
included in the Onshore Petroleum and
Natural Gas Gathering and Boosting
source category. For example, if a
gathering and boosting owner or
operator also owns or operates
equipment on or associated with a
single well pad (40 CFR 98.230(a)(2)),
that equipment is part of the Onshore
Petroleum and Natural Gas Production
segment, not the Onshore Petroleum
and Natural Gas Gathering and Boosting
segment. Therefore, emissions from that
equipment should not be included
when determining if the gathering and
boosting facility exceeds the reporting
threshold.
Comment: One commenter requested
that the EPA clarify the proper segment
for AGR units and revise the rule
accordingly. The commenter suggested
that the Natural Gas Processing segment
should explicitly exclude sulfur dioxide
and carbon dioxide (CO2) removal units,
so that it is clear that those units do not
report under both the Natural Gas
Processing segment and the Onshore
Petroleum and Natural Gas Gathering
and Boosting segment. The commenter
stated that this revision would be more
consistent with the definition of gas
processing plant in other EPA rules. If
the EPA does not make this change, the
commenter stated that AGR units
should not be included in the Onshore
Petroleum and Natural Gas Gathering
and Boosting segment because they are
already included in the Natural Gas
Processing segment. The commenter
noted that AGR units are specifically
defined in 40 CFR 98.238 as a process
unit that separates hydrogen sulfide
and/or CO2 from sour natural gas using
liquid or solid absorbents or membrane
separators.
Response: The EPA agrees that
emissions from a particular acid gas
removal unit should not be reported
under both the Natural Gas Processing
segment and the Onshore Petroleum and
Natural Gas Gathering and Boosting
segment. However, as noted previously
in this preamble, the EPA is not
changing the segment description for
the Onshore Petroleum and Natural Gas
Production segment in 40 CFR
98.230(a)(2) or the Onshore Natural Gas
Processing segment in 40 CFR
98.230(a)(3). Instead, the EPA is
reiterating the intention for the Onshore
Petroleum and Natural Gas Gathering
and Boosting segment to cover
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equipment and emission sources not
included in reporting for the Onshore
Petroleum and Natural Gas Production
or Onshore Natural Gas Processing
segments. The final segment description
for the Onshore Petroleum and Natural
Gas Gathering and Boosting segment in
40 CFR 98.230(a)(10) specifies that
gathering and boosting equipment does
not include equipment reported under
any other industry segment defined in
40 CFR 98.230(a), which should address
the commenter’s concern about
reporting under multiple segments.
Regarding the commenter’s suggestion
to exclude AGR units from the Onshore
Petroleum and Natural Gas Gathering
and Boosting segment, the EPA believes
AGR units should be reported under
subpart W and that the current
requirements, coupled with the
revisions in this rulemaking, allow for a
clear demarcation of where they should
be included and reported. While most
AGR units will be included in the
Onshore Natural Gas Processing
segment, the EPA does not agree that the
Onshore Natural Gas Processing
segment includes all AGR vents,
particularly those in processes that do
not fractionate gas liquids with an
annual average throughput of less than
25 million scf per day. Therefore, the
final Onshore Petroleum and Natural
Gas Gathering and Boosting segment
includes AGR vents that do not meet the
segment descriptions for the Onshore
Petroleum and Natural Gas Production
segment in 40 CFR 98.230(a)(2) or the
Onshore Natural Gas Processing
segment in 40 CFR 98.230(a)(3) but do
meet the Onshore Petroleum and
Natural Gas Gathering and Boosting
segment description in 40 CFR
98.230(a)(10).
2. Definitions
a. Summary of Final Amendments
The EPA is finalizing the definition of
‘‘gathering and boosting system’’ as
proposed and is finalizing the definition
of ‘‘gathering and boosting system
owner or operator’’ as proposed with a
clarification that the fluid being
transported may be petroleum or natural
gas. Specifically, a gathering and
boosting system is a single network of
pipelines, compressors and process
equipment, including equipment to
perform natural gas compression,
dehydration, and acid gas removal, that
has one or more connection points to
gas and oil production and a
downstream endpoint, typically a gas
processing plant, transmission pipeline,
local distribution company (LDC)
pipeline, or other gathering and
boosting system. A gathering and
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boosting system owner or operator is
any person that: (1) Holds a contract in
which they agree to transport petroleum
or natural gas from one or more onshore
petroleum and natural gas production
wells to a natural gas processing facility,
another gathering and boosting system,
a natural gas transmission pipeline, or a
distribution pipeline; or (2) is
responsible for custody of the petroleum
or natural gas transported. In complex
ownership scenarios, the owner/
operator assigns a designated
representative responsible for reporting
consistent with 40 CFR 98.4.
The EPA is also finalizing the
definition of ‘‘facility with respect to
onshore petroleum and natural gas
gathering and boosting’’ in 40 CFR
98.238 as proposed. A facility with
respect to onshore petroleum and
natural gas gathering and boosting is all
gathering pipelines and other
equipment located along those pipelines
that are under common ownership or
common control by a gathering and
boosting system owner or operator and
that are located in a single hydrocarbon
basin as defined in 40 CFR 98.238.
Where a person owns or operates more
than one gathering and boosting system
in a basin (for example, separate
gathering lines that are not connected),
then all gathering and boosting systems
and equipment that the person owns or
operates in the basin are considered one
facility. Any gathering and boosting
equipment that is associated with a
single gathering and boosting system,
including leased, rented, or contracted
activities, is considered to be under
common control of the owner or
operator of the gathering and boosting
system. Emissions from an onshore
petroleum and natural gas gathering and
boosting facility only need to be
reported if the collection of emission
sources emits 25,000 metric tons CO2e
or more per year.
b. Summary of Comments and
Responses
Comment: Multiple commenters
provided comments on the definition of
‘‘facility with respect to onshore
petroleum and natural gas gathering and
boosting.’’ Some commenters supported
the basin-level approach that the EPA
proposed, although a few asked the EPA
to clarify how to report their emissions
if their gathering and boosting system is
in more than one basin. Other
commenters disagreed with the basinlevel approach and suggested that the
EPA should use the definition of facility
in 40 CFR 98.6. These commenters
asserted that the basin-level approach
would result in an expansive definition
of facility that includes huge numbers of
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emissions sources and that this
approach is not consistent with how a
facility is defined elsewhere in the
GHGRP or with traditional notions of
aggregation under the CAA. One
commenter asserted that defining a
facility in a way that is not consistent
with other CAA programs will make it
difficult for the EPA to use the GHGRP
data to inform future policy decisions.
The commenter also stated that the EPA
has not provided any explanation of
why basin-wide aggregation is a
reasonable data request under section
114 of the CAA.
Commenters opposing the basin-level
facility definition noted that the
Onshore Petroleum and Natural Gas
Gathering and Boosting segment has
very different characteristics from the
Onshore Petroleum and Natural Gas
Production segment, which also uses
the basin-level approach to defining a
facility. One commenter specifically
noted that production sources are
located at well-defined, discrete
locations, owners and operators of
production sites know where the wells
are physically located and how many
operate in a single production basin. In
contrast, the commenter stated, the
gathering and boosting operations of one
owner or operator in a single
hydrocarbon basin may include
hundreds or thousands of miles of
pipelines with multiple sites, including
interconnects, meter stations, scrubber
stations, pigging stations, compressor
stations, and gas treating plants.
Another commenter stated that
gathering and boosting sites have the
ability to boost and move gas from
multiple basins within the same site,
whereas production typically maintains
operations and moves gas within one
basin.
Another commenter also disagreed
with the basin-level approach, noting
that the term ‘‘basin’’ is not common
terminology that is used in the gathering
and boosting industry segment. The
commenter suggested that the EPA use
a county- or parish-level approach with
an equipment threshold (to determine
which equipment should be counted
when determining if the 25,000 metric
tons CO2e reporting threshold has been
exceeded).
Response: The EPA is finalizing the
definition of ‘‘facility with respect to
onshore petroleum and natural gas
gathering and boosting’’ as proposed. As
noted in the preamble to the proposed
amendments, the basin-level approach
to defining a facility for the Onshore
Petroleum and Natural Gas Gathering
and Boosting segment is expected to
achieve a balance of providing
geographically specific information
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while also reducing burden on
reporters. This approach also recognizes
the fact that gathering and boosting
facilities are more dispersed than
processing facilities and are
geographically similar to the Onshore
Petroleum and Natural Gas Production
segment in size and number of sources
because, by their nature, they are
needed to process and transport the
petroleum and natural gas produced in
a given basin. While some gathering and
boosting operations may span multiple
basins or may only be present in a
portion of a basin, as will some onshore
production operations, the EPA has
concluded that a basin-level facility
definition is the best reflection of how
this industry is organized operationally.
In ‘‘Greenhouse Gas Reporting Rule:
Technical Support for 2015 Revisions
and Confidentiality Determinations for
Petroleum and Natural Gas Systems;
Proposed Rule’’ (Docket Item No. EPA–
HQ–OAR–2014–0831–0018), we
evaluated the option of using the
definition of ‘‘facility’’ found in 40 CFR
98.6 for gathering and boosting
facilities, and we found that this
definition would provide limited data
on the proposed Onshore Petroleum and
Natural Gas Gathering and Boosting
segment compared to the basin-level
approach, due to the fact that fewer
facilities would exceed the 25,000
metric tons CO2e reporting threshold. It
would also likely be more burdensome
overall to reporters, because a larger
number of facilities would have to be
evaluated to determine whether they
exceed the 25,000 metric tons CO2e
reporting threshold, and a larger number
of ‘‘facility’’ reports would be required
for each owner or operator. The
commenters did not provide any new
information that would enable us to reevaluate this conclusion. A county- or
parish-level approach would similarly
result in a larger number of smaller
facilities to be evaluated to determine
whether they exceed the reporting
threshold than the basin-level approach.
This approach would result in fewer
facilities reporting than a basin-level
definition, especially if an equipment
threshold were defined as requested by
the commenter, as well as a higher
burden for owners or operators with
multiple facilities in a basin that exceed
the 25,000 metric tons CO2e reporting
threshold. Therefore, the EPA
concluded that these options would not
achieve the goals that were articulated
in the preamble to the proposed rule of
‘‘having a thorough data set and
transparent, complete information for
this sector while minimizing burden to
reporters’’ (79 FR 73156; December 9,
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2014). For more detail on this analysis,
see ‘‘Greenhouse Gas Reporting Rule:
Technical Support for Final 2015
Revisions and Confidentiality
Determinations for Petroleum and
Natural Gas Systems’’ in Docket ID No.
EPA–HQ–OAR–2014–0831. We disagree
with the comment that aggregation of
data would not provide a data set that
the EPA can use to inform future policy
decisions. The purpose of this rule is to
collect emissions and activity data for
this industry and understand the
relative emission sources, which we
anticipate the aggregated data will help
to promote. Therefore, the aggregated
data can still inform future GHG policy.
As we have pointed out previously, the
EPA’s definition of ‘‘facility’’ for
purposes of part 98 in no way impacts
the ‘‘facility’’ definition for similar
sources under existing CAA programs.6
Information collected under part 98 can
inform a number of different CAA
programs and the Agency’s authority
under CAA section 114 as the basis for
part 98 is independent from the EPA’s
authority for other CAA programs.
To address the commenters’ question
about reporting a system in two basins,
we are confirming in this response that
reporters should submit one report per
basin (i.e., per facility as it is defined in
subpart W) and that the 25,000 metric
tons CO2e per year reporting threshold
applies to each basin/facility separately.
In other words, the reporter should
determine the emissions from the
portion of gathering and boosting
system associated with each basin. If the
total emissions in each basin exceed the
25,000 metric tons CO2e per year
reporting threshold, then the reporter
submits two reports. If the total
emissions in one basin exceed the
25,000 metric tons CO2e threshold, but
the emissions in the other basin are
below the threshold, then the reporter
submits one report (for the facility that
exceeds the threshold).
Regarding the commenter’s question
regarding the reasonableness of
collecting data at the basin-level under
the CAA, the EPA established its basis
for collecting basin-level data in the
final subpart W rule, when the EPA
finalized the requirements for the
Onshore Petroleum and Natural Gas
Production segment. Additionally, as
noted earlier in this section, more
granular collection of data for this
segment would result in higher burden
for owners or operators with multiple
operations in a basin that exceed the
6 Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Subpart W:
Petroleum and Natural Gas Systems, Docket Id. No.
EPA–HQ–OAR–2009–0923.
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25,000 metric tons CO2e reporting
threshold. See also, ‘‘Greenhouse Gas
Emissions Reporting from the Petroleum
and Natural Gas Industry, Background
Technical Support Document (Docket
Item No. EPA–HQ–OAR–2009–0923–
3610) and ‘‘Mandatory Greenhouse Gas
Reporting Rule Subpart W—Petroleum
and Natural Gas: EPA’s Response to
Public Comments’’ (Docket Item No.
EPA–HQ–OAR–2009–0923–3608).
3. Blowdown Vent Stacks
a. Summary of Final Amendments
The EPA is finalizing the
requirements for blowdowns of
equipment in the Onshore Petroleum
and Natural Gas Gathering and Boosting
segment with some clarifications from
proposal. Emissions should be
calculated using the same methods that
are used for the Onshore Natural Gas
Processing segment. The same
exemptions, including those for
volumes less than 50 cubic feet (ft3) and
for desiccant dehydrator reloading,
apply to the Onshore Petroleum and
Natural Gas Gathering and Boosting
segment. In response to comments that
the segment is geographically dispersed
and blowdowns may occur without
personnel on-site or nearby, making it
difficult to determine emissions from a
blowdown event, the final amendments
specify that for emergency blowdowns,
reporters may use engineering estimates
based on best available information to
determine the temperature and pressure
used in Equation W–14A.
b. Summary of Comments and
Responses
Comment: Commenters stated that the
EPA should not include reporting of
blowdown vent stack emissions due to
the large burden on the reporter.
Instead, the commenters stated,
blowdowns in the Onshore Petroleum
and Natural Gas Gathering and Boosting
segment should be treated similarly to
blowdowns in the Onshore Petroleum
and Natural Gas Production segment,
where they are excluded because they
are not located at consolidated facility
sites and are not manned. Commenters
also stated that blowdowns from
gathering and boosting systems
contribute minimally to overall GHG
emissions. One commenter noted that
while there is an exemption for any
blowdown of a volume less than 50 ft3,
there is also a burden to determine if the
physical volume meets this reporting
threshold. To reduce the burden, some
commenters suggested only including
emissions from blowdown vent stacks
located at a facility site (e.g., compressor
station, central tank battery). Other
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commenters stated if blowdowns remain
in the segment, the EPA should allow
reporters to use an emission factor
approach to calculate emissions.
Another commenter stated that the
EPA’s supporting documentation
focuses on gathering pipeline
blowdowns, but the regulatory text
appears to include all the blowdowns
occurring within a basin, including
individual equipment blowdowns. The
commenter requested that the EPA
clarify its intent if blowdowns remain in
the segment.
Response: The EPA has evaluated
these comments and has decided to
finalize the reporting requirements for
blowdowns in the Onshore Petroleum
and Natural Gas Gathering and Boosting
segment with some revisions to address
the commenters’ concerns. While the
EPA does recognize that many gathering
and boosting systems are geographically
dispersed, as noted by the commenters,
the nature of the Onshore Petroleum
and Natural Gas Gathering and Boosting
segment is such that the amount of fluid
passing through a gathering and
boosting system will be much greater
than the amount of fluid at individual
well pads. Therefore, the EPA has
determined that the potential for
emissions from blowdowns in the
Onshore Petroleum and Natural Gas
Gathering and Boosting segment is
higher than blowdowns in the Onshore
Petroleum and Natural Gas Production
segment, and they should not be
excluded. However, the EPA
acknowledges that the geographic
dispersion of the segment, and the fact
that some blowdowns occur without
facility personnel on site, may make it
difficult to measure emissions from
blowdowns, particularly emergency
blowdowns. Therefore, the final
amendments include a provision
specifying that for emergency
blowdowns, reporters may use
engineering estimates based on best
available information to determine the
temperature at actual conditions in the
unique physical volume and absolute
pressure at actual conditions in the
unique physical volume for use in
Equation W–14A.
To respond to the commenter’s
request regarding whether only
gathering pipeline blowdowns or all
equipment blowdowns should be
included, the EPA is clarifying that the
intent is to include emissions from the
‘‘blowdown vent stacks’’ source type as
defined in subpart A of part 98. The
focus on blowdown vent stacks located
on gathering pipelines in the supporting
documentation was not intended to
imply that only gathering pipeline
blowdowns should be reported. On the
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contrary, the proposal supporting
documentation reflects the fact that the
EPA expected that blowdown vent
stacks located at boosting stations
would be similar to blowdown vent
stacks in other industry segments and
conducted a separate evaluation to
determine whether the same calculation
methods would be appropriate for
gathering pipeline blowdown vent
stacks. The final rule supporting
documentation more clearly reflects this
intent. The EPA also notes that while
measuring equipment to determine
whether it exceeds the 50 ft3 physical
volume threshold for reporting may
create an initial burden on reporters, the
threshold will lead to a burden
reduction as reporters become familiar
with the identification process.
4. Storage Tank Vented Emissions
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a. Summary of Final Amendments
The EPA is finalizing the same
methods for calculating emissions for
atmospheric storage tanks located in the
Onshore Petroleum and Natural Gas
Gathering and Boosting segment as in
the Onshore Petroleum and Natural Gas
Production segment, as proposed but
with a few clarifications. Specifically,
the EPA is clarifying some of the
language within 40 CFR 98.233(j) and 40
CFR 98.236(j) that was originally written
to apply to Onshore Petroleum and
Natural Gas Production facilities and
not proposed to be amended to also
apply to storage tanks in the Onshore
Petroleum and Natural Gas Gathering
and Boosting segment. In particular,
references to a ‘‘wellhead separator’’
have been clarified to refer simply to a
‘‘separator,’’ which is a defined term in
40 CFR 98.238. To accommodate
Onshore Petroleum and Natural Gas
Gathering and Boosting storage tanks
that do not receive hydrocarbon liquids
from a separator or well, Calculation
Methods 1 and 2 have been amended to
specify how to estimate emissions if
liquids are received from non-separator
equipment. In addition, certain
instances of ‘‘sub-basin’’ have been
amended to refer to ‘‘county’’ to clarify
the requirements for Onshore Petroleum
and Natural Gas Gathering and Boosting
reporters. All other provisions in 40
CFR 98.233(j) apply to the Onshore
Petroleum and Natural Gas Gathering
and Boosting segment, including the 10
barrels per day threshold for
determining which calculation method
may be used for estimating emissions.
b. Summary of Comments and
Responses
Comment: One commenter stated that
combining the requirements for storage
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tanks in the Onshore Petroleum and
Natural Gas Gathering and Boosting
segment and the Onshore Petroleum and
Natural Gas Production segment results
in confusing terminology and unclear
requirements. In particular, the
commenter noted that the terms
‘‘separator(s),’’ ‘‘gas-liquid separator(s),’’
‘‘wellhead separator(s),’’ and ‘‘wellhead
gas-liquid separator(s),’’ appear
throughout the storage tank
requirements. The commenter asked
whether the EPA intended all of these
terms to refer to the same equipment.
The commenter also noted that not all
gathering and boosting system storage
tanks receive liquids directly from
separators, and no gathering and
boosting storage tanks receive liquids
directly from wellhead separators.
Therefore, the commenter stated, the
requirements for storage tanks in the
Onshore Petroleum and Natural Gas
Gathering and Boosting segment are
unclear.
The commenter also noted
inconsistency between use of the terms
‘‘oil,’’ ‘‘sales oil,’’ and ‘‘stabilized oil’’ in
40 CFR 98.233(j) and 40 CFR 98.236(j).
The commenter stated that Onshore
Petroleum and Natural Gas Gathering
and Boosting facilities may process
condensate but not oil, and the
commenter asked the EPA to clarify
how those terms should be applied to
the Onshore Petroleum and Natural Gas
Gathering and Boosting segment.
Finally, the commenter noted that
Calculation Method 1 for storage tanks
requires use of the latest available
analysis that is representative of
produced crude oil or condensate from
the sub-basin category. The commenter
stated that the term ‘‘sub-basin’’ has no
relevance to the Onshore Petroleum and
Natural Gas Gathering and Boosting
segment because the composition of
condensate processed at a compressor
station may have little relationship to
the oil or gas formation below the
compressor station.
Response: The EPA agrees that the
language in 40 CFR 98.233(j) and 40
CFR 98.236(j) should be clear for all
Onshore Petroleum and Natural Gas
Production facilities and all Onshore
Petroleum and Natural Gas Gathering
and Boosting facilities to which it
applies. The existing definition of
‘‘separator’’ in 40 CFR 98.238 is a vessel
in which streams of multiple phases are
gravity separated into individual
streams of single phase. This general
definition and the general term ‘‘gasliquid separator’’ apply to both Onshore
Petroleum and Natural Gas Production
facilities and all Onshore Petroleum and
Natural Gas Gathering and Boosting
facilities. Therefore, the EPA has
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reviewed the language and is amending
references to a ‘‘well,’’ ‘‘well pad,’’ or
‘‘wellhead,’’ which are terms that are
not expected to apply to most Onshore
Petroleum and Natural Gas Gathering
and Boosting facilities. The final
provisions in 40 CFR 98.233(j) and 40
CFR 98.236(j) refer more generally to
separators or gas-liquid separators. To
address the comment that not all
gathering and boosting system storage
tanks receive liquids directly from
separators, the EPA has amended 40
CFR 98.233(j)(1) and (2) to specify how
those calculation methodologies may be
used for Onshore Petroleum and Natural
Gas Gathering and Boosting storage
tanks receiving hydrocarbon liquids
from non-separator equipment (i.e.,
without a well or separator directly
upstream of the storage tank).
Regarding the particular material
being stored in storage tanks, the EPA
agrees that there is inconsistency in
some of the terms that could cause some
confusion. The EPA is clarifying in this
response that for the Onshore Petroleum
and Natural Gas Gathering and Boosting
segment, the intent is for ‘‘oil’’ to refer
more generally to hydrocarbon liquids,
which is consistent with the statement
in 40 CFR 98.233(j) that reporters are
required to calculate emissions ‘‘from
atmospheric pressure fixed roof storage
tanks receiving hydrocarbon produced
liquids.’’ The proposed separate
reporting requirements for quantity of
produced oil throughput and produced
condensate throughput in 40 CFR
98.236(aa)(10) have been revised, and
the final rule requires reporting of the
hydrocarbon liquids received by the
facility and the hydrocarbon liquids
leaving the facility. Finally, the EPA
notes that the term ‘‘sales oil’’ is already
defined in Subpart A to include
‘‘produced crude oil or condensate,’’ so
there is no further clarification needed.
Regarding the term ‘‘sub-basin,’’ the
EPA agrees with the commenter that the
definition of ‘‘sub-basin category, for
onshore natural gas production’’ in 40
CFR 98.238 is not relevant for Onshore
Petroleum and Natural Gas Gathering
and Boosting facilities. The EPA also
agrees that the operations within a
section of a gathering and boosting
system may not be related to the
formation type below the surface of the
ground at that location, especially as the
material travels further from the wells
supplying gas and hydrocarbon liquids
to the system. As a result of this
comment, the EPA reviewed the use of
the term ‘‘sub-basin’’ as it was proposed
to apply to Onshore Petroleum and
Natural Gas Gathering and Boosting
facilities. In 40 CFR 98.233(j), the
calculation methods provide options to
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estimate unknown parameters using
information from a previous analysis of
the composition in the sub-basin
category. In these cases, the intent is to
estimate unknown parameters from a
representative unit (e.g., well,
separator). To reflect a similar intent for
Onshore Petroleum and Natural Gas
Gathering and Boosting facilities, 40
CFR 98.233(j)(1)(vii)(B) and 40 CFR
98.233(j)(1)(vii)(C) in Calculation
Method 1 clarify that representative
separators or non-separator equipment
are located within the same county for
Onshore Petroleum and Natural Gas
Gathering and Boosting reporters. For
Calculation Method 2, the term ‘‘subbasin category’’ is used to describe
calculation of emissions for flow to
storage tanks directly from wells. The
final rule includes a new paragraph 40
CFR 98.233(j)(2)(iii) to address
calculation of emissions from flow to a
tank from equipment other than a well
or separator (such as a stabilizer or slug
catcher), and this paragraph also
clarifies that representative analyses
should come from other non-separator
equipment located within the same
county. Finally, there are reporting
requirements for a ‘‘sub-basin ID’’ in 40
CFR 98.236. The final rule specifies that
for Onshore Petroleum and Natural Gas
Gathering and Boosting, the information
to be reported is the county in which
the equipment is located.
5. Gathering Pipelines
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a. Summary of Final Amendments
The EPA is finalizing the
requirements for calculating emissions
from gathering pipelines defined to be
included in the Onshore Petroleum and
Natural Gas Gathering and Boosting
segment as proposed. The methodology
is similar to the approach used for
equipment leaks in the Onshore
Petroleum and Natural Gas Production
segment. For gathering lines, reporters
use the population count and emission
factor approach in 40 CFR 98.233(r).
The emission factors in Table W–1A for
gathering pipelines are whole gas
emission factors based on the U.S. GHG
Inventory. The population count is the
miles of gathering pipeline, similar to
the approach used for calculating
emissions from natural gas distribution
pipelines in the Natural Gas
Distribution segment. As noted in
section II.B.1.a of this preamble,
gathering pipelines with a GOR less
than 300 scf/STB are not included in
this segment.
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b. Summary of Comments and
Responses
Comment: One commenter asserted
that the EPA should revise the proposed
emission factor of 2.81 standard cubic
feet (scf)/hour/mile for leaks from
gathering pipelines to be based on
characteristics of currently operating
gathering pipelines rather than
distribution pipelines or older data on
gathering pipelines. The commenter
also noted that this emission factor is
not applicable to gathering pipelines
that carry primarily liquids, as there is
no gas stream until after separation. The
commenter identified gathering
pipeline-specific data from PHMSA and
used the data to calculate a suggested
emission factor of 2.23 scf/hour/mile.
Response: We reviewed the
underlying data used to develop the
proposed emission factor, and we agree
with the commenter that the proposed
emission factor could better account for
differences between pipeline types and
for currently operating gathering
pipelines. In the 1996 Gas Research
Institute (GRI)/EPA report that is the
basis of the emission factor, materialspecific emissions factors for gathering
lines were developed using data from
direct measurement of distribution
pipelines conducted in the 1990s, not
gathering pipelines. These materialspecific emission factors are the same
emission factors used by the commenter
as the starting point for their revised
emission factor.
We agree with the commenter that the
emission factors should better represent
currently operating gathering pipelines;
however, there is significant variability
in gathering pipelines and gathering
system configurations. Owners and
operators currently report the mileage of
pipeline by gathering pipeline type to
PHMSA.7 Therefore, rather than
calculate a single emission factor for
gathering pipelines based on a
distribution of gathering pipeline
materials, as was done at proposal, the
EPA determined that the most
appropriate approach is to develop
gathering pipeline emission factors for
four pipeline material types: Protected
steel, unprotected steel, plastic, and cast
iron. (For more information about the
development of these emission factors,
see ‘‘Greenhouse Gas Reporting Rule:
Technical Support for Final 2015
Revisions and Confidentiality
Determinations for Petroleum and
7 U.S. Department of Transportation Pipeline and
Hazardous Materials Safety Administration. Natural
and Other Gas Transmission and Gathering Pipeline
Systems: Annual Report for Calendar Year. Form
PHMSA F 7100.2–1 (rev 10–2014). OMB No. 2137–
0522, Expires: 10/31/2016.
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Natural Gas Systems’’ in Docket ID No.
EPA–HQ–OAR–2014–0831.) The final
amendments require reporters to
estimate emissions using materialspecific emission factors provided in the
rule and to report gathering pipeline
mileage by material type.
The EPA also notes that reporters will
not need to calculate emissions from
gathering pipelines that carry
hydrocarbon liquids if they are below
the minimum GOR threshold for the
Onshore Petroleum and Natural Gas
Gathering and Boosting segment.
6. Other Emission Sources
a. Summary of Final Amendments
The EPA is finalizing the
requirements for natural gas pneumatic
devices and pneumatic pumps located
in the Onshore Petroleum and Natural
Gas Gathering and Boosting segment as
proposed. Gathering and boosting
reporters will use the same methods for
calculating emissions as in the Onshore
Petroleum and Natural Gas Production
segment. The EPA is also finalizing the
requirements for acid gas removal units,
dehydrators, and flare stacks as
proposed. The methods are the same as
the methods for these sources in both
the Onshore Petroleum and Natural Gas
Production segment and the Onshore
Natural Gas Processing segment. The
EPA is also finalizing the requirements
for compressors and equipment leaks as
proposed, with one clarification
regarding how to count ‘‘meters/piping’’
for equipment leaks. Gathering and
boosting reporters use the same method
as in the Onshore Petroleum and
Natural Gas Production segment.
Specifically, a reporter will need to
establish an inventory of the
components or equipment subject to the
population counts, apply the emission
factors, and then update the inventory
each year to account for new or retired
components or equipment.
b. Summary of Comments and
Responses
Comment: Two commenters stated
that the major equipment categories for
calculating equipment leaks by
population count are not clear for the
Onshore Petroleum and Natural Gas
Gathering and Boosting segment. Both
commenters requested that the EPA
clarify how to count ‘‘meters/piping’’ for
the Onshore Petroleum and Natural Gas
Gathering and Boosting segment. One
commenter also requested clarification
regarding separators, compressors, and
in-line heaters (specifically, whether
small heating systems used to ensure a
temperate environment for a meter are
considered in-line heaters). The
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commenter also noted that there was
limited time to evaluate the
appropriateness of the emission factors
in Table W–1A and the component
counts in Table W–1B for gathering and
boosting systems.
Response: The categories in Table W–
1B represent the types of equipment that
are generally expected to be found in
the field for Onshore Petroleum and
Natural Gas Production and Onshore
Petroleum and Natural Gas Gathering
and Boosting facilities.8 For the Onshore
Petroleum and Natural Gas Gathering
and Boosting segment, the EPA realizes
that reporters will only use those
categories that apply (e.g., reporters will
not include wellheads, as that
equipment type is specific to Onshore
Petroleum and Natural Gas Production
facilities).
Most of the major equipment
categories are described by function in
the rule. For the example of a separator,
40 CFR 98.238 defines a separator as ‘‘a
vessel in which streams of multiple
phases are gravity separated into
individual streams of single phase.’’
Any device meeting this functional
definition will fall into this major
equipment category. Other major
categories are described in the rule by
their functional role, including
dehydrators and compressors. For the
in-line heater example for which the
commenter requested clarification, the
equipment described is not located in
line with the fluid flow and therefore
would not be considered in this
equipment category.
The EPA agrees with both
commenters that the measurement of
meters/piping in the Onshore Petroleum
and Natural Gas Gathering and Boosting
segment was not clear as proposed. The
final rule specifies that reporters in the
Onshore Petroleum and Natural Gas
Gathering and Boosting segment should
count the number of meters in the
facility and use that as the count for
‘‘meters/piping.’’
Comment: Two commenters
supported the use of calculation
methods that include emission factors
for the Onshore Petroleum and Natural
Gas Gathering and Boosting segment
because they are less burdensome to the
industry. However, the commenters also
requested that the EPA allow reporters
the option to use any available data/
information that provides the best
representation of emissions from their
specific sources, including
manufacturer data, test data,
8 See the memorandum ‘‘Equipment-Level
Population Emission Factors for Onshore
Production,’’ Docket Item No. EPA–HQ–OAR–
2009–0923–3582, for more information regarding
the derivation of this table.
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measurement and/or monitoring data.
The commenters compared this option
to the approach in state-level emissions
inventories that require an emissions
reporting hierarchy. The commenters
noted that this approach will provide
the EPA with more accurate emissions
data that could be used to update the
emission factors for the Onshore
Petroleum and Natural Gas Gathering
and Boosting segment.
Response: The calculation methods
provided in subpart W were selected to
minimize burden on industry while
maintaining the necessary quality and
consistency of data to inform policy.
Therefore, outside of the BAMM
provisions being finalized in this
rulemaking, the EPA does not agree to
allow reporters to use customized,
individual information for their
emission sources at this time. The EPA
is currently investigating additional
calculation methods for subpart W
sources and may propose additional
calculation methods in the future.
C. Summary of Final Amendments for
the Onshore Natural Gas Transmission
Pipeline Segment
1. Summary of Final Amendments
The EPA is finalizing the proposal to
add reporting requirements for
emissions from natural gas transmission
pipeline blowdowns between
compressor stations in a new Onshore
Natural Gas Transmission Pipeline
segment. Commenters generally had no
objections to the merit of including this
segment in subpart W but did suggest
technical edits and clarifications for
targeted provisions. As noted in the
preamble to the proposed amendments,
a blowdown is the release of gas from
transmission pipelines that causes a
reduction in system pressure or a
complete depressurization. The EPA is
clarifying that for the purposes of the
Onshore Natural Gas Transmission
Pipeline segment, the blowdowns that
must be reported are blowdowns of a
pipeline or section of pipeline.
The EPA is finalizing clarifications to
the proposed definition of onshore
natural gas transmission pipeline owner
or operator. For interstate pipelines, the
onshore natural gas transmission
pipeline owner or operator is the person
identified as the transmission pipeline
owner or operator on the Certificate of
Public Convenience and Necessity
issued under 15 U.S.C. 717f, as
proposed. For intrastate pipelines, the
onshore natural gas transmission
pipeline owner or operator is the person
identified as the owner or operator on
the transmission pipeline’s Statement of
Operating Conditions under section 311
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of the Natural Gas Policy Act (NGPA).
If the intrastate pipeline is not subject
to section 311 of the NGPA, the onshore
natural gas transmission pipeline owner
or operator is the person identified as
the owner or operator on reports to the
state regulatory body regulating rates
and charges for the sale of natural gas
to consumers. Finally, the owner or
operator of a pipeline that falls under
the ‘‘Hinshaw Exemption’’ is the person
identified as the owner or operator on
blanket certificates issued under 18 CFR
284.224.
The EPA is finalizing the definition of
facility for the new Onshore Natural Gas
Transmission Pipeline segment as
proposed; the facility is the total U.S.
mileage of natural gas transmission
pipelines owned or operated by an
onshore natural gas transmission
pipeline owner or operator. If an owner
or operator has multiple pipelines in the
United States, the facility is considered
the aggregate of those pipelines, even if
they are not interconnected.
The EPA is finalizing the requirement
that reporters use the methods in 40
CFR 98.233(i) to calculate or measure
emissions from pipeline blowdown
events as proposed. One method allows
a reporter to calculate emissions based
on the volume of the pipeline segment
between isolation valves that is blown
down and the pressure and temperature
of the gas within the pipeline. The
second method allows the reporter to
measure the emissions from the
blowdown using a flow meter on the
blowdown vent stack. In both methods,
the reporter calculates both CH4 and
CO2 emissions from the volume of
natural gas vented using either default
gas composition or engineering
estimates of composition as specified in
40 CFR 98.233(u)(2)(iii).
The EPA is not finalizing the
proposed requirement to report the
emissions and location (latitude and
longitude) of each blowdown event.
Instead, the EPA is requiring that
Onshore Natural Gas Transmission
Pipeline reporters report the total CH4
and CO2 emissions in each state, the
number of blowdowns in each state, and
the miles of pipeline in each state. In
addition, instead of requiring Onshore
Natural Gas Transmission Pipeline
reporters to use the same equipment and
event type categories as other industry
segments reporting blowdown
emissions, the EPA is including
reporting categories specific to the
Onshore Natural Gas Transmission
Pipeline segment.
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2. Summary of Comments and
Responses
Comment: Several commenters noted
that not all intrastate pipelines are
subject to section 311 of the NGPA and
asked the EPA to clarify which
intrastate pipelines are subject to
reporting. One commenter requested
that the EPA clarify that intrastate
pipelines not subject to the NGPA are
not required to report under subpart W.
Another commenter suggested revising
the definition of owner or operator to
state that if section 311 of the NGPA
does not apply, the intrastate
transmission pipeline owner or operator
is the owner or operator identified on
required reports with the appropriate
state agency.
Response: It was our intent to include
transmission pipelines (including
intrastate pipelines) that meet the
already existing subpart W definition of
‘‘transmission pipeline’’ in the Onshore
Natural Gas Transmission Pipeline
segment. A transmission pipeline in
subpart W is defined in 40 CFR 98.238
as a Federal Energy Regulatory
Commission (FERC) rate-regulated
Interstate pipeline, a state rate-regulated
Intrastate pipeline, or a pipeline that
falls under the ‘‘Hinshaw Exemption’’ as
referenced in section 1(c) of the Natural
Gas Act, 15 U.S.C. 717–717 (w)(1994).
After reviewing the comments on the
proposed rule, we re-reviewed section
311 of the NGPA and found that only
operators of some intrastate pipelines,
including those that transport natural
gas on behalf of an interstate pipeline or
sell natural gas to an interstate pipeline,
are required to prepare a Statement of
Operating Conditions for compliance
under section 311 of the NGPA.
Therefore, to clarify how to determine
the owner and operator of intrastate
transmission pipelines, the finalized
definition of ‘‘onshore natural gas
transmission pipeline owner or
operator’’ specifies that for intrastate
transmission pipelines not subject to
section 311 of the NGPA, the owner or
operator is the person identified as the
owner or operator on reports to the state
regulatory body regulating rates and
charges for the sale of natural gas to
consumers. The EPA also found that the
proposed definition of ‘‘onshore natural
gas transmission pipeline owner or
operator’’ did not specify how to
determine the owner or operator of
pipelines that fall under the ‘‘Hinshaw
Exemption.’’ The EPA notes that similar
to intrastate pipelines, pipelines that fall
under the ‘‘Hinshaw Exemption’’ must
apply for a ‘‘blanket certificate’’ under
18 CFR 284.224 in order to transport
petroleum or natural gas on behalf of
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interstate pipelines. Therefore, the
finalized definition of ‘‘onshore natural
gas transmission pipeline owner or
operator’’ also specifies that for a
pipeline that falls under the ‘‘Hinshaw
Exemption,’’ the owner or operator is
the person identified as the owner or
operator on blanket certificates issued
under 18 CFR 284.224.
Comment: Commenters appreciated
that the EPA provided a threshold of 50
ft3 of physical volume for blowdown
emissions reporting but requested
several changes. Commenters requested
that the EPA include a list of ancillary
equipment, such as metering and/or
regulating stations, pipeline
interconnects, and pig launchers and
receivers, that would be excluded from
reporting of blowdown emissions. One
commenter suggested that, alternatively,
the physical volume threshold could be
increased to 3,000 thousand cubic feet
to clearly exclude blowdowns of
ancillary facilities along the pipeline.
Another commenter stated that it is not
feasible to establish a specific de
minimis volume threshold to exclude all
ancillary equipment.
Response: The EPA is finalizing the
reporting threshold of 50 ft3 of physical
volume for blowdowns in the Onshore
Natural Gas Transmission Pipeline
segment as proposed. This threshold
excludes smaller blowdown sources that
have little contribution to emissions,
consistent with other industry segments
within subpart W that must report
blowdown stack vent emissions. The
EPA is not increasing the physical
volume reporting threshold to account
for blowdowns from ancillary
equipment, as this would be
inconsistent with the EPA’s previous
analysis in ‘‘Equipment Threshold for
Blowdowns’’ (see Docket Item No. EPA–
HQ–OAR–2009–0923–3581), and
commenters were divided on whether
increasing the threshold would even
address their primary concern.
The EPA agrees that the emphasis for
the Onshore Natural Gas Transmission
Pipeline segment is on calculating and
reporting blowdown emissions from
pipeline segments, not ancillary
equipment. However, any list of
ancillary equipment that would be
excluded from blowdown reporting
could be incomplete, resulting in
reporting of emissions from other
equipment that is ancillary but not on
the list in the rule. In addition, some of
the equipment identified as ‘‘ancillary’’
in this segment is not considered
ancillary in other industry segments,
which could lead to confusion among
reporters. Instead, the final rule clarifies
that facilities in the Onshore Natural
Gas Transmission Pipeline segment
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64275
report pipeline blowdown emissions
from blowdown vent stacks. If the
blowdown does not include a pipeline
segment or has a physical volume of less
than 50 ft3, then that blowdown is not
required to be reported.
Comment: Several commenters stated
that the blowdown equipment and event
type categories in 40 CFR 98.233(i)(2)
were developed for compressor station
blowdowns and would not provide
meaningful information regarding
pipeline blowdowns in the Onshore
Natural Gas Transmission Pipeline
segment. The commenters provided
suggestions for categories that would be
more applicable to Onshore Natural Gas
Transmission Pipeline blowdowns and
would provide more valuable
information than relying on the
categories in the existing rule.
Response: The EPA agrees with the
commenters that the rule should
include blowdown categories specific to
blowdowns in the Onshore Natural Gas
Transmission Pipeline segment. The
final rule specifies that blowdowns
must be grouped into one of the
following categories: Pipeline integrity
work (e.g., the preparation work of
modifying facilities, ongoing
assessments, maintenance or
mitigation), traditional operations or
pipeline maintenance, equipment
replacement or repair (e.g., valves), pipe
abandonment, new construction or
modification of pipelines including
commissioning and change of service,
operational precaution during activities
(e.g. excavation near pipelines),
emergency shutdowns including
pipeline incidents as defined by
PHMSA, and all other pipeline
segments with a physical volume greater
than or equal to 50 ft3.
Comment: Commenters requested that
the EPA not finalize the requirement to
report latitude and longitude for each
blowdown event. The commenters
indicated this requirement would be
burdensome, such data are not currently
collected, the requirement is
inconsistent with the Paperwork
Reduction Act, and the data would not
be useful in determining the inventory.
Some commenters also suggested
aggregating emissions at the state level
or only at the national/facility level.
Response: The requirement to report
latitude and longitude of each
blowdown was included in the
proposed rule to help characterize the
emissions from the new Onshore
Natural Gas Transmission Pipeline
segment on a more granular level than
the nationwide facility. The EPA
evaluated this comment and has noted
the commenters’ assertion that the
latitude and longitude of each
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blowdown is not information currently
reported elsewhere and may result in
additional burden. Therefore, the EPA is
not finalizing the requirement to report
the emissions or latitude and longitude
for each individual blowdown. Instead,
the EPA is finalizing requirements for
reporters to aggregate blowdown
emissions by state and report the
number of blowdowns and mileage of
pipeline per state.
Comment: Two commenters
questioned the requirement to report the
data elements in proposed 40 CFR
98.236(aa)(11). Two commenters noted
that the quantities of natural gas in this
section are duplicative of information
reported to FERC annually in FERC
Form 2, although the units of measure
are dekatherms rather than thousand
standard cubic feet. One commenter
noted that for the GHGRP reporting,
they would assume 1 dekatherm is
equivalent to 1,000 scf of natural gas,
based on the approximate heat value of
natural gas. The other commenter
opposed these reporting requirements
because they are duplicative and
inconsistent with the requirements of
the PRA, which is intended to reduce
the information burden imposed by the
federal government by requiring that
agencies ensure that reported
information is not duplicative of other
available data and has a practical utility.
This commenter stated that the EPA has
not followed the PRA. The commenter
also stated that the requested
information is irrelevant to assisting
EPA in verifying pipeline blowdown
emissions; in particular, the information
cannot be used to calculate pipeline
blowdown volumes.
Response: As the EPA has noted
elsewhere, the data collected in the
GHGRP will be used to inform future
policy decisions. As such, information
regarding emissions and the inputs
needed to verify those emissions is only
part of the information that is needed.
It is important to understand that, to
inform future policy, activity data is
often as useful as emissions estimates.
The EPA has determined that data
elements in 40 CFR 98.236(aa)(11) are
activity data that will be used to
determine how to use the emissions
data to inform future policy decisions.
It is essential that reporters provide and
certify the data they gather under this
rule so that EPA has a complete
inventory from all sources under this
rule and can directly relate the activity
data to the emissions data reported,
which will provide for appropriate
verification of the emissions data
reported.
The EPA agrees with the first
commenter that for purposes of
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reporting the data elements in 40 CFR
98.236(aa)(11), reporters may consider 1
dekatherm equal to 1,000 scf.
Comment: Several commenters
asserted that the EPA has not been
consistent in its decisions on whether to
include pipeline leaks across the
subpart W industry segments. Some
commenters supported the EPA’s
proposal not to include leaks from
transmission pipelines and noted the
decision was consistent with the
Onshore Petroleum and Natural Gas
Production segment. Conversely, one
commenter stated that transmission
pipeline leaks should be reported,
consistent with the new Onshore
Petroleum and Natural Gas Gathering
and Boosting segment. This commenter
noted that accidental leaks at these
facilities can be a significant source of
CH4 emissions, as evidenced by the
magnitude of emissions from pipeline
incidents reported to PHMSA, and leaks
at remote locations may not be noticed
or repaired immediately.
Response: The EPA previously
considered fugitive emissions that result
from leaks in transmission pipelines in
the re-proposal of subpart W in April
2010 (75 FR 18616; April 12, 2010) but
did not include provisions for these
emissions in either the proposed or final
rules. The April 2010 preamble
explained that the EPA did not propose
reporting requirements for fugitive
emissions from leaks in natural gas
pipeline segments between compressor
stations due to the dispersed nature of
the fugitive emissions and the fact that,
once fugitives are found, the leaks
causing the emissions are usually
addressed quickly for safety reasons (75
FR 18616; April 12, 2010). The EPA also
noted in the proposal preamble for these
amendments (79 FR 76267; December 9,
2014) that larger fugitive leaks are
currently reported to PHMSA as part of
49 CFR 191.3. Under this provision, any
pipeline incident that results in
unintentional gas loss of 3 million ft3 or
more must be reported. The commenter
that noted that emissions can be
significant cited the emissions reported
to PHMSA under this provision, and the
EPA does not find it necessary to
require owners and operators to report
this same information under the
GHGRP. The focus of the PHMSA
reporting requirements is to identify
major safety-related incidents that are
not a part of typical operations.
Therefore, the EPA is not finalizing a
requirement to report fugitive emissions
from transmission pipeline leaks but
will continue to review this source as
part of the EPA’s ongoing effort to
ensure comprehensive, high quality data
in subpart W.
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D. Summary of Final Amendments for
Well Identification Numbers
1. Summary of Final Amendments
The EPA is finalizing some of the
proposed amendments to 40 CFR 98.236
to add reporting requirements for well
identification numbers to improve data
quality by enabling identification of
wells. These well identification
numbers will be reported for the first
time in the report covering 2016
emissions; reporters will not be required
to report well identification numbers for
previous years. For the majority of
wells, the well identification number
reported will be the US Well Number
(formerly referred to as the API Well
Number, or API Number).9 For any well
that does not already have a US Well
Number, the reporter will be required to
provide the unique well number
assigned by the permitting authority for
drilling of oil and gas wells.
Commenters varied in their level of
support for the proposed provisions
regarding well identification numbers.
The EPA is adjusting the final
provisions in response to concerns
about these reporting provisions raised
in comments.
The EPA is requiring the reporting of
well identification numbers for the
Onshore Petroleum and Natural Gas
Production segment only for
information related specifically to wells.
For reporters in the Onshore Petroleum
and Natural Gas Production segment
that report emissions using input data
that are calculated from measurements
at individual wells or equipment
associated with individual wells (e.g., if
Equation W–10A was used to calculate
emissions from oil well completions
and workovers with hydraulic
fracturing, well testing emissions), the
report must include the well
identification number for which those
measurements were made and the well
identification number(s) of other wells
to which the measurements will be
applied. This includes a list of the well
identification numbers by sub-basin for
the producing wells at the end of the
calendar year as well as lists of the well
identification numbers for the wells
acquired, divested, completed, and
permanently taken out of production
during the calendar year. The EPA is not
finalizing the proposed requirement that
reporters in the Onshore Petroleum and
Natural Gas Production segment report
a list of well identification numbers
associated with different emission
9 The Professional Petroleum Data Management
Association. The US Well Number Standard: An
Identifier for Petroleum Industry Wells in the USA.
Version 2013 rev 1, published June 19, 2014.
Available at https://dl.ppdm.org/dl/1147.
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sources for all wells in a sub-basin
included in the reported emissions data.
The EPA is finalizing the proposed
change to update references to the ‘‘API
well number’’ in subpart W to ‘‘well
identification number.’’ The EPA is not
otherwise changing the well
identification reporting requirements
finalized in 2014 (79 FR 70352;
November 25, 2014). Reporters will still
need to report well identification
numbers for liquids unloading and for
any exploratory wells for which
reporting has been delayed for 2 years.
2. Summary of Comments and
Responses
Comment: While one commenter
supported the addition of well
identification number reporting, most
commenters opposed the proposal to
require reporting of well identification
numbers. These commenters asserted
that requiring reporting of well
identification numbers is an overreach
of the EPA’s authority for the reporting
program under CAA section 114 and
that the EPA has not provided a
reasoned basis for the departure from
the previous EPA approach that wellspecific data was not necessary under
Subpart W. Commenters also noted that
well identification numbers are not
needed to validate reported emissions.
One commenter noted that the EPA has
not questioned the data collected from
wells thus far; nor has the EPA stated
that the data already collected are
insufficient to inform policy without
addition of well identification numbers,
so with this proposal, the EPA is no
longer balancing data collection with
reporting burdens. Commenters stated
that mapping and maintaining a
database of well identification numbers
is more burdensome than the EPA
estimated, and one commenter stated
that it would be arbitrary and capricious
to require companies to expend the
resources necessary to report these data.
Commenters also noted that it is not
clear how to interpret the term
‘‘associated with’’ in all cases. One
commenter stated that matching specific
wells with emissions in the GHGRP
could cause security concerns.
Response: The EPA disagrees that
requiring reporting of well identification
numbers is an overreach of our
authority. The EPA has determined that
these data elements are useful and
necessary for the verification of existing
data and for characterizing the
emissions from the industry segment.
This final revision will allow the EPA
to link the GHGRP data to other
databases (i.e. state permitting
databases) to more easily match the data
reported under the GHGRP with other
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data sources and will improve the
accuracy and transparency of subpart
W. Additionally, being able to match the
GHGRP data to other data sources will
provide the EPA with more options for
analysis of the GHGRP data to better
inform future policy decisions related to
GHG emissions from the oil and natural
gas production sector. The reporting of
the well identification numbers will
also allow the EPA to assess the
completeness and representativeness of
the data collected under the GHGRP as
a portion of all activity in the oil and
natural gas production sector. The EPA
reiterates that CAA section 114 provides
the EPA with the authority to collect
emissions data, which includes
information about the location of the
source of emissions. Section 114
generally authorizes the EPA to gather
information from any person who owns
or operates an emissions source, who is
subject to a requirement of the CAA,
who manufactures control or process
equipment, or who the Administrator
believes has information necessary for
the purposes of section 114(a). The EPA
may gather information for purposes of
establishing implementation plans or
emissions standards, determining
compliance, or ‘‘carrying out any
provision’’ of the CAA. For these
reasons, the Administrator may request
that a person, on a one-time, periodic or
continuous basis, establish and
maintain records, make reports, install
and operate monitoring equipment and,
among other things, provide such
information the Administrator may
reasonably require. This language has
been interpreted to grant the EPA broad
authority. See, e.g., Dow Chemical Co. v.
U.S., 467 U.S. 227, 233 (1986)
(‘‘Regulatory and enforcement authority
generally carries with it all modes of
inquiring and investigation traditionally
employed or useful to execute the
authority granted.’’). See, generally
Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Volume No.: 9, Legal Issues
(Docket Item No. EPA–HQ–OAR–2008–
0508–2264). The requirement to report
well identification numbers for wellspecific data clearly fits within EPA’s
statutory authority. We also believe, for
the reasons stated above, that we are
exercising this authority reasonably in
furtherance of the purposes of the Clean
Air Act. Further, the EPA disagrees that
this is a deviation from our previous
approach to collecting data. As
discussed in section II.B of this
preamble, the EPA is finalizing the
requirement to report Onshore
Petroleum and Natural Gas Gathering
and Boosting facilities at the basin-level,
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which is consistent with our previous
approach to the Onshore Petroleum and
Natural Gas Production segment.
Therefore, the EPA is finalizing the
requirements to report the well
identification number for well-specific
data as proposed. Specifically, for
reporters in the Onshore Petroleum and
Natural Gas Production segment that
report emissions using input data that
are calculated from measurements at
individual wells or equipment or
operations associated with individual
wells (e.g., if Equation W–10A is used
to calculate emissions from oil well
completions and workovers with
hydraulic fracturing, well testing
emissions, liquids unloading), the report
must include the well identification
number for which those measurements
were made, or for which the equipment
or operations are associated. In addition,
the EPA is finalizing the requirements
in 40 CFR 98.236(aa)(1)(ii)(D) through
(H) to include a list of the well
identification numbers by sub-basin for
the producing wells at the end of the
calendar year and lists of the well
identification numbers for the wells
acquired, divested, completed, and
permanently taken out of production
during the calendar year. The EPA
continues to expect that this is a low
burden to reporters because reporters
already track and maintain well
identification numbers associated with
measurements used for the GHGRP
input data.
To respond to the comment that well
identification numbers may not be
available for or assigned to equipment
other than wells, the EPA reviewed the
permits and requirements in seven
different states. Although most of the
states assign unique identifiers to each
emission source, the EPA found that
only two of the seven states have a
tracking system that links individual
emission sources to specific wells and
well identification numbers, and these
two states are not consistent in their
approach. (See ‘‘Greenhouse Gas
Reporting Rule: Technical Support for
2015 Revisions and Confidentiality
Determinations for Petroleum and
Natural Gas Systems; Final Rule’’ in
Docket ID No. EPA–HQ–OAR–2014–
0831 for more information on this
analysis.) While it may be
straightforward to assign some emission
sources directly to one well, particularly
if there is only one well on the single
well pad and the reporter does not
operate any other wells nearby, the
EPA’s review of state requirements
shows that there may be multiple
scenarios in which a reporter does not
know which well or wells are associated
with a particular emission source. For
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example, there may be multiple wells
on a single well pad and multiple
storage tanks associated with that well
pad, and the tanks may have the ability
to receive hydrocarbon liquids from
several of those wells. Therefore, in
light of the potential burden of requiring
facilities to develop new tracking
systems that would assign and track
emissions to well identification
numbers for the purposes of part 98, the
EPA is not requiring facilities in this
rulemaking to report well identification
numbers for every emission source in a
facility in the Onshore Petroleum and
Natural Gas Production segment.
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E. Summary of Final Amendments to
Best Available Monitoring Methods
1. Summary of Final Amendments
As proposed, reporters will be
allowed to use BAMM for the 2016
reporting year for the new industry
segments and emission sources
included in this action. These include
calculating and reporting emissions
from oil well completions and
workovers with hydraulic fracturing,
from onshore petroleum and natural gas
gathering and boosting systems, and for
transmission pipeline blowdown
emissions. Reporters are allowed to use
BAMM to estimate inputs to emission
equations for the newly finalized
emission sources for cases where the
monitoring of these inputs would not be
possible beginning on January 1, 2016.
The use of BAMM is not allowed for the
reporting of well identification numbers
because reporters should already have
well identification numbers readily
available for all wells and associated
equipment to which this reporting
requirement applies and because the
well identification number is not a
parameter that requires monitoring
equipment to be measured and,
therefore, does not meet the
requirements for BAMM.
For these sources, the EPA is
finalizing a longer timeline for BAMM
than was proposed. Reporters have the
option of using BAMM for the new
industry segments and emission sources
included in this action from January 1,
2016, to December 31, 2016, without
seeking prior EPA approval. The
provision providing a set amount of
automatic transitional BAMM will allow
reporters to prepare for data collection
while automatically being able to use
BAMM, which is consistent with the
approach of prior part 98 rulemakings.
This additional time for reporters to
comply with the revised monitoring
methods in subpart W will allow
facilities to install the necessary
monitoring equipment during other
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planned (or unplanned) process unit
downtime, thus avoiding process
interruptions, and is responsive to
comments received on the proposed
rule provisions.
The EPA is not finalizing the
proposed provision to allow reporters
the opportunity to request an extension
for the use of BAMM. The EPA will not
accept requests for an extension for the
use of BAMM beyond the time periods
listed above. As proposed, the EPA also
is not providing transitional BAMM for
these new requirements beyond
December 31, 2016.
The EPA is not allowing the use of
BAMM beyond 2016 and does not
anticipate that BAMM will be needed
beyond 2016 for the new segments and
emissions sources being finalized in this
rule.
2. Summary of Comments and
Responses
Comment: Several commenters stated
that only 3 months of automatic BAMM
and 1 year of transitional BAMM is not
enough time to implement the
monitoring and measurement
requirements for facilities newly subject
to subpart W and newly added emission
sources. The commenter stated that
adding a new segment is a significant
amendment and the EPA has set the
precedent of providing at least 1 year of
automatic BAMM when adding a new
segment to subpart W. The commenters
noted that not all gathering and boosting
reporters are already reporting as
Onshore Petroleum and Natural Gas
Production facilities, so they will not
necessarily all be familiar with the
monitoring and calculation
methodologies. The commenters also
noted that nearly all reporters will be
spending the first month working on
BAMM requests for the rest of 2016.
The commenters had a variety of
suggestions for how long the EPA
should provide BAMM for these new
emission sources. Several commenters
suggested 1 year (through the end of
2016) for automatic BAMM. Another
commenter suggested March 31, 2017
(i.e., 1 year in addition to the EPA’s
proposed 3 months), and another stated
that 3 years would be consistent with
the length of time provided when the
Onshore Petroleum and Natural Gas
Production segment was added to
subpart W. Some commenters addressed
the length of transitional BAMM with
the EPA’s approval. One commenter
noted that a new reporter/facility could
become subject to one of the new
segments beyond the end of 2016, so
there should be no deadline for
submitting a request for BAMM to the
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EPA. Another requested transitional
BAMM through the end of 2018.
Response: The EPA recognizes that
most of the amendments being finalized
in this rulemaking are new requirements
rather than clarifications of existing
reporting requirements for facilities
already subject to subpart W and may
require the development and
implementation of new systems of data
collection and monitoring. Therefore,
the EPA is finalizing 1 year of automatic
transitional BAMM in place of the
proposed 3 months of automatic
transitional BAMM. This additional
time for reporters to comply with the
revised monitoring methods in subpart
W will allow facilities to install the
necessary monitoring equipment and
implement any new systems of data
collection that may be required. Because
the amount of time for which automatic
BAMM is available should be sufficient
time to comply with the requirements of
subpart W for the new segments and
emission sources, the EPA will not
provide additional BAMM beyond the
automatic BAMM provisions in 40 CFR
98.234(g).
We note that 40 CFR 98.235(e) and(f)
provides 6 months of reporting
flexibility for facilities that become
subject to subpart W or acquire new
sources after reporting year 2016.
Reporters may also refer to the
provisions of 40 CFR 98.235 after
reporting year 2016 for guidance on
reporting emissions if certain required
data are not collected.
III. Confidentiality Determinations
A. Summary of Final Confidentiality
Determinations for New Subpart W Data
Elements
In the proposed rule, we assigned new
data elements to the appropriate direct
emitter data categories created in the
2011 Final CBI Rule based on the type
and characteristics of each data
element.10 For data elements the EPA
assigned to a direct emitter category
with a categorical determination, the
EPA proposed that the categorical
determination for the category be
applied to the proposed new data
element. For data elements assigned to
the ‘‘Unit/Process ‘Static’ Characteristics
that Are Not Inputs to Emission
Equations’’ and ‘‘Unit/Process Operating
Characteristics that Are Not Inputs to
Emission Equations,’’ we proposed
confidentiality determinations on a
case-by-case basis taking into
10 ‘‘Confidentiality Determinations for Data
Required Under the Mandatory Greenhouse Gas
Reporting Rule and Amendments to Special Rules
Governing Certain Information Obtained Under the
Clean Air Act’’ (76 FR 30782, May 26, 2011).
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consideration the criteria in 40 CFR
2.208, consistent with the approach
used for data elements previously
assigned to these two data categories.
We also proposed individual
confidentiality determinations for six
new data elements without making a
data category assignment. Refer to the
preamble to the proposed rule (79 FR
76267; December 9, 2014) for additional
information regarding the proposed
confidentiality determinations.
With consideration of the data
provided by commenters, the EPA is
finalizing the confidentiality
determinations as proposed.
Specifically, the EPA is finalizing the
proposed decision to require each of the
new data elements to be designated as
‘‘not CBI.’’
The EPA proposed to provide
reporters with the option to delay
reporting of five data elements for 2
reporting years in situations where
exploratory wells are the only wells in
a sub-basin. We received comment
requesting that the EPA provide the
same 2-year delay for additional data
elements associated with exploratory
wells. The comment and the EPA’s
response are included in section III.B of
this preamble. Based on consideration
of the comment and consistent with the
EPA’s previous decisions related to
exploratory wells under part 98 (79 FR
63750, October 24, 2014; 79 FR 70352,
November 25, 2014), the EPA is
finalizing provisions to provide
reporters with the option to delay
reporting of five data elements as
proposed and, based on comments
received, an additional two data
elements for 2 reporting years in
situations where exploratory wells are
the only wells in a sub-basin. For a
given sub-basin, in situations where
wildcat wells and/or delineation wells
are the only wells in a sub-basin that
can be used for the required
measurement, the following seven data
elements associated with the
delineation or wildcat well may be
delayed for 2 reporting years: (1) The
cumulative gas flowback time, in hours,
for each sub-basin, from when gas is
first detected until sufficient quantities
are present to enable separation (40 CFR
98.236(g)(5)(i)); (2) the cumulative
flowback time, in hours, for each subbasin, after sufficient quantities of gas
are present to enable separation (40 CFR
98.236(g)(5)(i)); (3) the measured
flowback rate, in standard cubic feet per
hour, for each sub-basin (40 CFR
98.236(g)(5)(ii)); (4) the gas to oil ratio
for the well (40 CFR 98.236(g)(5)(iii)(A));
(5) the volume of oil produced during
the first 30 days of production after
completions of each newly drilled well
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or well workover using hydraulic
fracturing (40 CFR 98.236(g)(5)(iii)(B));
(6) the total annual gas-liquid separator
oil volume that is sent to applicable
onshore storage tanks, in barrels (40
CFR 98.236(j)(1)(iii)); and (7) the total
annual oil throughput that is sent to all
atmospheric tanks, in barrels (40 CFR
98.236(j)(2)(i)(A).
Four of the seven data elements for
which reporting may be delayed by 2
years are inputs to emission equations
and the EPA provided the same option
in the EPA’s previous decisions related
to exploratory wells under part 98 (79
FR 63750, October 24, 2014). Two of the
seven data elements are inputs only
when the applicable data are related to
a single well (the two data elements in
40 CFR 98.236(g)(5)(i)), and one data
element is never an input (40 CFR
98.236(j)(2)(i)(A)). Where the EPA agrees
that there are early disclosure concerns
related to exploratory wells, the EPA
decided to treat those early disclosure
concerns consistently throughout
subpart W by providing the option to
delay reporting by 2 years to all seven
data elements listed above.
At proposal, in cases where the two
data elements in 40 CFR 98.236(g)(5)(i))
are not inputs to equations, they were
assigned to the ‘‘Unit/Process Operating
Characteristics that are Not Inputs to
Emission Equations’’ category and were
proposed to be ‘‘not CBI.’’ The EPA is
finalizing this determination as
proposed. Specifically, the ‘‘not CBI’’
determination applies to all situations
except for when the data elements are
inputs to equations.
For the situations when the data
elements are used as inputs to
equations, the EPA is assigning them to
the ‘‘Inputs to Emission Equations’’ data
category and is not making
confidentiality determinations for these
data. The EPA evaluated and
summarized any potential disclosure
concerns with the reporting of the data
elements assigned to the ‘‘Inputs to
Emission Equations’’ data category in
the memo titled ‘‘Review for Potential
Disclosure Concerns for Inputs to
Emission Equations Affected by the
2015 Revisions and Confidentiality
Determinations for Petroleum and
Natural Gas Systems’’ available in
Docket ID No. EPA–HQ–OAR–2014–
0831. Other than the exception of the
early disclosure concerns for certain
data elements related to exploratory
wells discussed earlier in this section,
the EPA has concluded that there are no
disclosure concerns with the reporting
of these data elements.
The data element collected under 40
CFR 98.236(j)(2)(i)(A) was proposed as
‘‘not CBI’’ and was not assigned to a
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data category. The EPA is finalizing this
determination as proposed as well. For
the data elements reported under 40
CFR 98.236(g)(5)(i)) (in cases where they
are not inputs to equations) and 40 CFR
98.236(j)(2)(i)(A), the ‘‘not CBI’’
determinations will apply once the data
are reported to the EPA following the 2year delay.
B. Summary of Comments and
Responses
This section summarizes the major
comments and responses related to the
proposed categorical assignments and
confidentiality determinations. See
‘‘Response to Public Comments on
Greenhouse Gas Reporting Rule: 2015
Revisions and Confidentiality
Determinations for Petroleum and
Natural Gas Systems’’ in Docket ID No.
EPA–HQ–OAR–2014–0831 for a
complete listing of all comments and
responses. See the memorandum ‘‘Final
Data Category Assignments and
Confidentiality Determinations for Data
Elements (excluding inputs to emission
equations) in the ‘Greenhouse Gas
Reporting Rule: 2015 Revisions and
Confidentiality Determinations for
Petroleum and Natural Gas Systems;
Final Rule’ ’’ in Docket ID No. EPA–HQ–
OAR–2014–0831 for a complete listing
of final data category assignments and
confidentiality determinations, and a
discussion of changes since proposal.
Comment: One commenter requested
that the EPA reconsider the
determination that the quantity of
produced gas throughput in the
calendar year and the quantity of
produced gas consumed by the facility
in the calendar year are ‘‘not CBI.’’ The
commenter noted that the quantity of
natural gas received and the quantity of
processed gas leaving processing plants
was maintained as CBI in the 2014
amendments (79 FR 70352; November
25, 2014). The commenter also stated
that information on fuel consumed at
gathering and boosting facilities is not
typically publically available, and when
this information is combined with the
quantity of produced gas throughput, it
directly indicates the fuel efficiency of
a station. The commenter noted that
while the EPA is correct that the
agreements are long-term for a given
well, revealing information about one
facility’s fuel efficiency could cause
competitive harm by affecting contracts
for other facilities owned by that
company, especially if there are smaller
gathering and boosting facilities in the
area that do not have to report this
information to the GHGRP.
The commenter also requested that
the EPA clarify a number of the
reporting elements in 40 CFR
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98.236(aa)(10). Specifically, the
commenter requested clarification of the
terms ‘‘produced gas,’’ ‘‘produced
condensate,’’ ‘‘produced oil,’’
‘‘throughput,’’ and ‘‘consumed’’ as they
are used in proposed 40 CFR
98.236(aa)(10). The commenter also
asserted that the data element in 40 CFR
98.236(aa)(10)(ii) (‘‘quantity of produced
gas consumed’’) would be redundant
with subpart C and should not be
finalized. Finally, the commenter stated
that the requirement to report the
‘‘quantity of gas flared, vented and/or
unaccounted for in the calendar year’’ in
40 CFR 98.236(10)(aa)(v) would
undermine over 5 years of rule
development, public comment,
reconsiderations, and petitioner
negotiations because it would require
reporting of emissions that are
otherwise exempted (e.g., blowdowns
below 50 ft3).
Response: The EPA reviewed these
comments and has clarified the
reporting elements in 40 CFR
98.236(aa)(10) for the final rule. The
final reporting requirements include: (1)
The quantity of gas received by the
gathering and boosting facility in the
calendar year, in thousand standard
cubic feet; (2) the quantity of gas
transported to a natural gas processing
facility, a natural gas transmission
pipeline, a natural gas distribution
pipeline, or another gathering and
boosting facility in the calendar year, in
thousand standard cubic feet; (3) the
quantity of all hydrocarbon liquids
received by the gathering and boosting
facility in the calendar year, in barrels;
and (4) the quantity of all hydrocarbon
liquids transported to a natural gas
processing facility, a natural gas
transmission pipeline, a natural gas
distribution pipeline, or another
gathering and boosting facility in the
calendar year, in barrels. The EPA has
determined that these quantities will be
easily accessible for all reporters and are
more consistent with the reporting
requirements for the Onshore Natural
Gas Processing segment. The EPA is
finalizing the CBI determinations for
these quantities as ‘‘not CBI,’’ as
proposed.
The final reporting requirements do
not include the terms ‘‘produced gas,’’
‘‘produced condensate,’’ ‘‘produced
oil,’’ ‘‘throughput,’’ or ‘‘consumed,’’ so
no clarification regarding the use of
those terms is needed. In particular, the
final rule does not include a
requirement to report the quantity of
produced gas consumed by the facility.
The difference between the quantities
received by a gathering and boosting
facility and the quantities exiting the
gathering and boosting facility is
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expected to include the quantity of gas
consumed by the facility as well as the
quantity of gas flared or vented in one
lump sum. Therefore, the reporting
requirements do not directly indicate
the fuel efficiency of the stations in a
gathering and boosting facility.
Comment: One commenter reiterated
previously stated concerns over the
disclosure of information for
exploratory wells, especially when they
are located in stepout areas where no
prior reporting exists for a given subbasin. The commenter supported the
EPA’s proposal to defer reporting of data
elements related to oil well completions
and workovers with hydraulic fracturing
for exploratory wells, but expressed
concern that EPA has not provided such
a delay in reporting for all emissions
data and data elements that are
associated with exploratory wells.
Specifically, the commenter stated that
the EPA failed to provide a necessary 2year deferral in reporting for the
following data elements, which are as
business sensitive and confidential as
the other information for which the EPA
proposed to defer reporting for 2 years:
• 40 CFR 98.236(g)(5)(iii)(A)—If you used
Equation W–12C to calculate the average gas
production rate for an oil well, the gas to oil
ratio for the well in standard cubic feet of gas
per barrel of oil.
• 40 CFR 98.236(g)(5)(iii)(B)—If you used
Equation W–12C to calculate the average gas
production rate for an oil well, the volume
of oil produced during the first 30 days of
production after completions of each newly
drilled well or well workover using hydraulic
fracturing, in barrels.
• 40 CFR 98.236(g)(6)(i)—If you used
Equation W–10B to calculate annual
volumetric total gas emissions for
completions that vent gas to the atmosphere,
the vented natural gas volume, in standard
cubic feet, for each well in the sub-basin.
• 40 CFR 98.236(g)(6)(ii)—If you used
Equation W–10B to calculate annual
volumetric total gas emissions for
completions that vent gas to the atmosphere,
the flow rate at the beginning of the period
of time when sufficient quantities of gas are
present to enable separation, in standard
cubic feet per hour, for each well in the subbasin.
• 40 CFR 98.236(g)(7)—For each oil well
completion or workover and well type
combination, annual gas emissions.
• 40 CFR 98.236(g)(8)—For each oil well
completion or workover and well type
combination, annual CO2 emissions.
• 40 CFR 98.236(g)(9)—For each oil well
completion or workover and well type
combination, annual CH4 emissions.
• 40 CFR 98.236(g)(10)—For each oil well
completion or workover and well type
combination, the total N2O emissions, if the
well emissions were vented to a flare.
Response: The EPA reviewed the data
elements identified by the commenter as
having disclosure concerns for
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exploratory wells (delineation wells and
wildcat wells). Consistent with the
EPA’s previous decisions related to
exploratory wells under part 98 (79 FR
63750, October 24, 2014; 79 FR 70352,
November 25, 2014), the EPA has
determined that, for gas well
completions or workovers with
hydraulic fracturing of wildcat wells
and/or delineation wells, early public
disclosure of some of the additional data
elements identified by the commenter
could reveal the well productivity of
wildcat wells and/or delineation wells,
thereby resulting in the loss of
investment value.
The additional data elements that
could reveal well productivity for
wildcat and/or delineation wells are as
follows:
• The gas to oil ratio for the well (40 CFR
98.236(g)(5)(iii)(A))
• The volume of oil produced during the
first 30 days of production after completions
of each newly drilled well or well workover
using hydraulic fracturing (40 CFR
98.236(g)(5)(iii)(B))
As the EPA has previously noted (79
FR 70352, November 25, 2014), in the
interim period before these data are
reported to the EPA, the EPA will be
able to verify the majority of the
emissions using data elements that will
be reported to the EPA. For the seven
total data elements that may be delayed
for 2 years, the EPA will verify
emissions using other data reported to
the EPA, and will conclude verification
upon receipt of the data. The EPA agrees
with the commenter that a 2-year delay
of reporting is sufficient to prevent early
public disclosure of these data and will
provide sufficient time for the reporter
to thoroughly conduct an assessment of
the well. Given the results of this
evaluation, the EPA determined that, for
these data elements, in those cases
where delineation wells or wildcat
wells are the only wells in a sub-basin,
reporters should be provided an option
to delay reporting of the given data
element for 2 reporting years starting in
2015. In such cases, if the 2-year delay
in reporting is used, the reporter must
indicate for each delayed reporting
element that wildcat wells and/or
delineation wells are the only wells in
a sub-basin that can be used for the
measurement in the current reporting
year. In addition, when reporters report
the delayed data elements after the 2year delay, they must also report the
well identification numbers for the
applicable wildcat and/or delineation
wells in the sub-basin for which the
reporting element was delayed. For
example, if a delineation or wildcat well
is completed in 2015 in a sub-basin that
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has only delineation or wildcat wells or
these are the only wells for which
measurements can be made, then the
reporter may: (1) Elect to report these
seven data elements in their 2016
annual report submitted by March 31,
2017, or (2) elect to delay reporting of
these data elements for up to 2 years. If
the reporter elects to delay reporting,
then the well identification numbers for
the wildcat and delineation wells in the
sub-basin for which reporting has been
delayed and the data elements delayed
from reporting must be reported no later
than March 31, 2019.
The following inputs meet the
definition of emission data in 40 CFR
2.301(a)(2)(i) because they indicate the
amount or frequency of gas emitted by
the facility: Volume of natural gas
vented (reported under 40 CFR
98.236(g)(6)(i)) and flow rate at the
beginning of the period of time when
sufficient quantities of gas are present to
enable separation (reported under 40
CFR 98.236(g)(6)(ii)). Without
corresponding activity data, such as a
count of the exploratory wells in a subbasin or production or flow rate data for
a sub-basin containing only exploratory
wells, there is no potential to disclose
business sensitive information based on
these data elements. Therefore, the EPA
is not providing an option to delay
reporting of these data elements for 2
reporting years.
Similarly, the data element annual gas
emissions (reported under 40 CFR
98.236(g)(7)) meets the definition of
emission data in 40 CFR 2.301(a)(2)(i)
and is assigned to the ‘‘Emissions’’ data
category because it indicates the amount
of gas emitted by the facility. In
addition, the following data elements
meet the definition of emission data in
40 CFR 2.301(a)(2)(i) and are assigned to
the ‘‘Emissions’’ data category because
they are emissions of pollutants emitted
by the source: annual CO2 emissions
(reported under 40 CFR 98.236(g)(8)),
annual CH4 emissions (reported under
40 CFR 98.236(g)(9)), and annual nitrous
oxide (N2O) emissions if the well
emissions were vented to a flare
(reported under 40 CFR 98.236(g)(10)).
For these data elements that are
assigned to the ‘‘Emissions’’ data
category, the commenter did not claim
or provide any justification for why
these data elements do not meet the
definition of emission data. Without
corresponding activity data, such as a
count of the exploratory wells in a subbasin or production or flow rate data for
a sub-basin containing only exploratory
wells, there is no potential to disclose
business sensitive information based on
these data elements. Therefore, the EPA
is not providing an option to delay
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reporting of these data elements for 2
reporting years.
IV. Impacts of the Final Amendments to
Subpart W
A. Impacts of the Final Amendments
The final amendments to subpart W
add monitoring and reporting
requirements for reporters in three
industry segments: Onshore Petroleum
and Natural Gas Production, Onshore
Petroleum and Natural Gas Gathering
and Boosting, and Onshore Natural Gas
Transmission Pipeline. The EPA is
adding 213 new data elements to the
reporting requirements. The new data
elements impose additional burden and
costs because, for each of the new data
elements that are required to be
reported, reporters are required to
calculate the data element using readily
available data and report the value to
the EPA via e-GGRT as part of the
annual report currently required under
part 98.
The EPA calculated the increase in
reporting and recordkeeping burden
associated with the new data elements
by adjusting labor hours upwards per
reporter for all affected industry
segments. For all three segments, an
estimate of 10 hours per year per
reporter was allotted for reporting via eGGRT and 10 hours per year per
reporter was allotted for recordkeeping.
Costs to reporters associated with this
rulemaking are expressed as labor costs
(i.e., the cost of labor by facility staff to
comply with the amendments), capital
costs for equipment and travel, and
operation and maintenance (O&M)
costs.
Reporters in the Onshore Petroleum
and Natural Gas Production segment
have to monitor and report emissions
and data elements associated with oil
well completions and workovers with
hydraulic fracturing. Reporters in this
segment also have to report the well
identification numbers associated with
individual oil and gas wells. The
addition of the requirement to report
emissions associated with oil well
completions and workovers with
hydraulic fracturing is expected to cause
an increase in the amount of emissions
that count towards determining
applicability under subpart W. The
addition of reporting requirements for
oil wells with hydraulic fracturing is
expected to affect 246 existing reporters
and to cause approximately 50 new
reporters to exceed the reporting
threshold for the onshore petroleum and
natural gas production facility. These
numbers have not changed from
proposal.
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The 50 new reporters will be required
to estimate and report emissions data
and related data elements associated
with several different emission sources
within this new industry segment,
including acid gas removal units,
associated natural gas venting and
flaring, storage tanks, dehydrators,
equipment leaks, liquids unloading, and
pneumatic devices.
Reporters in the Onshore Petroleum
and Natural Gas Gathering and Boosting
segment must estimate and report
emissions data and related data
elements associated with several
different emission sources within this
new industry segment, including acid
gas removal units, storage tanks,
blowdown vents, dehydrators,
equipment leaks, flare stacks, and
pneumatic devices. Approximately 200
new reporters are expected to be subject
to subpart W due to the amendments for
the Onshore Petroleum and Natural Gas
Gathering and Boosting segment in this
rulemaking. This number has not
changed from proposal.
Reporters in the Onshore Natural Gas
Transmission Pipeline segment will
need to estimate and report emissions
data and related data elements
associated with transmission pipeline
blowdown activities. Approximately
183 new reporters in this segment are
expected to be subject to subpart W.
This number increased from 150 to 183
since proposal due to public comment.
The EPA received multiple comments
regarding the impacts of the proposed
amendments. After evaluating these
comments and reviewing other changes
from proposal, the EPA revised the
impacts assessment slightly from
proposal. The final amendments to
subpart W are not expected to
significantly change the burden
calculated at proposal.
The EPA has determined that the cost
associated with this final action will be
$7,190,235 each year and has worked to
minimize burden to reporters where
practicable. See the memorandum,
‘‘Assessment of Impacts of the 2015
Final Revisions to Subpart W’’ in Docket
ID No. EPA–HQ–OAR–2014–0831 for
additional information.
B. Summary of Comments and
Responses
This section summarizes the major
comments and responses related to the
impacts of the proposed amendments to
subpart W of part 98. We note that
numerous commenters asserted that the
burden was underestimated, and some
provided suggestions for improvement,
but most of those comments did not
include the detailed information the
EPA needed to assess the comment
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fully, such as a suggestion for a revised
burden estimate, support for the
suggestion, and an explanation of why
the suggested value is representative of
all sources subject to the same
requirements. See ‘‘Response to Public
Comments on Greenhouse Gas
Reporting Rule: 2015 Revisions and
Confidentiality Determinations for
Petroleum and Natural Gas Systems’’ in
Docket ID No. EPA–HQ–OAR–2014–
0831 for a complete listing of all
comments and responses.
Comment: One commenter asked for
an explanation for the estimate of 200
respondents in the Onshore Petroleum
and Natural Gas Gathering and Boosting
segment. The commenter noted that the
EPA estimated the number of reporters
in the Onshore Natural Gas Processing
industry segment as 291 reporters. The
commenter stated by the nature of the
industry, any company with a
processing plant will most likely also
have an associated gathering system
subject to reporting and suggested that
the number of reporters in the Onshore
Petroleum and Natural Gas Gathering
and Boosting industry segment should
total 291, at minimum, but potentially
more.
Response: Due to differences in the
definitions of the two industry
segments, the EPA disagrees that the
number of reporters in the Onshore
Petroleum and Natural Gas Gathering
and Boosting segment should match the
number of reporters in the Onshore
Natural Gas Processing segment. The
EPA estimate of 200 respondents was
based on the regulatory analysis for
Office of Pipeline Safety (OPS) safety
regulations. In the analysis, it was
estimated that 50 percent of the 400
natural gas gathering pipeline operators
under regulation are small entities
operating small diameter, low pressure
(Type B) gathering lines and fifty
percent are large diameter, high
pressure lines (Type A) potentially
subject to the safety regulation
(depending upon proximity to
population centers).11
Comment: One commenter noted that
the EPA estimated that there are 150
reporters for Onshore Natural Gas
Transmission Pipeline facilities at
proposal. However, the commenter
stated that the EPA should expect 183
reporters in the segment based on the
number of operators that are required to
complete a PHMSA annual report
11 U.S. Department of Transportation. Pipeline
and Hazardous Materials Safety Administration.
Draft Regulatory Evaluation, Regulated Natural Gas
Gathering Lines, Regulatory Analysis, Docket
RSPA–1998–4868. Available at www.viadata.com/
pipeliner/library_docs/Gatheringanalysis.pdf.
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(PHMSA F–7100–2) or are regulated by
FERC under section 311 of the NGPA.
Response: The EPA agrees with the
suggested change. The preamble to the
final amendments, the final Supporting
Statement, and the memorandum
‘‘Assessment of Impacts of the 2015
Final Revisions to Subpart W’’ (see
Docket ID No. EPA–HQ–OAR–2014–
0831) have been updated to reflect the
change from 150 reporters to 183
reporters in the Onshore Natural Gas
Transmission Pipeline segment.
Comment: Two commenters objected
to the collection of well identification
numbers. One commenter noted that
collection would require significant
resources and would be unduly
burdensome on operators. The other
commenter stated that the burdens
associated with collecting and reporting
this data far outweigh any minimal
benefits in data quality.
Response: The EPA is finalizing the
well identification number reporting
requirements for well-specific data as
proposed, but the EPA is not requiring
well identification numbers to be
reported in this rulemaking for
equipment other than wells. See section
II.D of this preamble for additional
discussion responding to this comment.
V. Statutory and Executive Order
Reviews
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
This action is not a significant
regulatory action and was therefore not
submitted to the Office of Management
and Budget (OMB) for review.
In addition, the EPA prepared an
analysis of the potential costs associated
with the final amendments to subpart
W. This analysis is contained in the
memorandum ‘‘Assessment of Impacts
of the 2015 Final Revisions to Subpart
W.’’ A copy of the analysis is available
in the docket for this action (see Docket
ID No. EPA–HQ–OAR–2014–0831) and
the analysis is briefly summarized in
section IV of this preamble.
B. Paperwork Reduction Act (PRA)
The information collection activities
in this rule have been submitted for
approval to the OMB under the PRA.
The Information Collection Request
(ICR) document that the EPA prepared
has been assigned EPA ICR number
2300.16. You can find a copy of the ICR
in the docket for this rule, and it is
briefly summarized here. The
information collection requirements are
not enforceable until OMB approves
them.
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This action adds monitoring and
reporting requirements for reporters in
three industry segments: Onshore
Petroleum and Natural Gas Production,
Onshore Petroleum and Natural Gas
Gathering and Boosting, and Onshore
Natural Gas Transmission Pipeline. Data
collection complements the Inventory of
U.S. Greenhouse Gas Emissions and
Sinks (Inventory) and provides a critical
tool for communities to identify nearby
sources of GHGs and provide
information to state and local
governments. The data can be used to
complement atmospheric GHG studies
and inform updates to emission
inventories. Various activity data are
collected that can be used to improve
understanding of the occurrence of
emissions from a variety of sources.
Data collected must be made available
to the public unless the data qualify for
CBI treatment under the CAA and EPA
regulations. All data determined by the
EPA to be CBI are safeguarded in
accordance with regulations in 40 CFR
chapter 1, part 2, subpart B.
Respondents/Affected Entities: The
respondents in this information
collection include owners and operators
of petroleum and natural gas systems
facilities that must report their GHG
emissions to the EPA to comply with
subpart W of part 98.
Respondent’s Obligation To Respond:
The respondent’s obligation to respond
is mandatory under the authority
provided in CAA section 114.
Estimated Number of Respondents:
Approximately 3,300 respondents per
year.
Frequency of Response: Annual.
Total Estimated Burden: 317,100
hours (per year). Burden is defined at 5
CFR 1320.3(b).
Total Estimated Cost: $29.2 million
(per year), includes $1.1 million
annualized capital and 2.8 million
operation & maintenance costs.
An agency may not conduct or
sponsor, and a person is not required to
respond to, a collection of information
unless it displays a currently valid OMB
control number. The OMB control
numbers for the EPA’s regulations in 40
CFR are listed in 40 CFR part 9. When
OMB approves this ICR, the Agency will
announce that approval in the Federal
Register and publish a technical
amendment to 40 CFR part 9 to display
the OMB control number for the
approved information collection
activities contained in this final rule.
C. Regulatory Flexibility Act (RFA)
I certify that this action will not have
a significant economic impact on a
substantial number of small entities
under the RFA. The small entities
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subject to the requirements of this
action are: (1) A small business as
defined by the Small Business
Administration’s regulations at 13 CFR
121.201; (2) a small governmental
jurisdiction that is a government of a
city, county, town, school district or
special district with a population of less
than 50,000; and (3) a small
organization that is any not-for-profit
enterprise which is independently
owned and operated and is not
dominant in its field.
The Agency has determined that a few
small businesses may experience an
insignificant impact. Details of this
analysis are presented in section IV.B of
the preamble to the proposed
amendments (79 FR 76267; December 9,
2014).
Although this final rule will not have
a significant economic impact on a
substantial number of small entities, the
EPA nonetheless has tried to reduce the
impact of this rule on small entities. As
part of the process of finalizing the
subpart W 2010 final rule, the EPA took
several steps to evaluate the effect of the
rule on small entities. For example, the
EPA determined appropriate thresholds
that reduced the number of small
businesses reporting. In addition, the
EPA supports a ‘‘help desk’’ for the rule,
which is available to answer questions
on the provisions in the rule. Finally,
the EPA continues to conduct
significant outreach on the GHG
reporting rule and maintains an ‘‘open
door’’ policy for stakeholders to help
inform the EPA’s understanding of key
issues for the industries.
D. Unfunded Mandates Reform Act
(UMRA)
This action does not contain an
unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C.
1531–1538, and does not significantly or
uniquely affect small governments. This
action imposes no enforceable duty on
any state, local, or tribal governments or
the private sector.
tkelley on DSK3SPTVN1PROD with RULES3
E. Executive Order 13132: Federalism
This action does not have federalism
implications. It will not have substantial
direct effects on the states, on the
relationship between the national
government and the states, or on the
distribution of power and
responsibilities among the various
levels of government.
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
This action has tribal implications.
However, it will neither impose
substantial direct compliance costs on
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federally recognized tribal governments,
nor preempt tribal law. This regulation
will apply directly to petroleum and
natural gas facilities that emit GHGs.
Although few facilities that will be
subject to the rule are likely to be owned
by tribal governments, the EPA has
sought opportunities to provide
information to tribal governments and
representatives during the development
of the proposed and final subpart W that
was promulgated on November 30, 2010
(75 FR 74458).
The EPA consulted with tribal
officials under the EPA Policy on
Consultation and Coordination with
Indian Tribes early in the process of
developing this regulation to permit
them to have meaningful and timely
input into its development. A summary
of that consultation is provided in
section IV.F of the preamble to the reproposal of subpart W published on
April 12, 2010 (75 FR 18608), and
section IV.F of the preamble to the
subpart W 2010 final rule published on
November 30, 2010 (75 FR 74458).
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
The EPA interprets Executive Order
13045 as applying only to those
regulatory actions that concern
environmental health or safety risks,
that the EPA has reason to believe may
disproportionately affect children, per
the definition of ‘‘covered regulatory
action’’ in section 2–202 of the
Executive Order. This action is not
subject to Executive Order 13045
because it does not concern an
environmental health risk or safety
risks.
H. Executive Order 13211: Actions That
Significantly Affect Energy Supply,
Distribution, or Use
This action is not subject to Executive
Order 13211, because it is not a
significant regulatory action under
Executive Order 12866.
I. National Technology Transfer and
Advancement Act (NTTAA)
This rulemaking does not involve
technical standards.
J. Executive Order 12898: Federal
Actions To Address Environmental
Justice in Minority Populations and
Low-Income Populations
The EPA believes the human health or
environmental risk addressed by this
action will not have potential
disproportionately high and adverse
human health or environmental effects
on minority, low-income or indigenous
populations because it does not affect
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64283
the level of protection provided to
human health or the environment.
Instead, this rule addresses information
collection and reporting procedures.
K. Congressional Review Act (CRA)
This action is subject to the CRA, and
the EPA will submit a rule report to
each House of the Congress and to the
Comptroller General of the United
States. This action is not a ‘‘major rule’’
as defined by 5 U.S.C. 804(2).
List of Subjects in 40 CFR Part 98
Environmental protection,
Administrative practice and procedure,
Greenhouse gases, Reporting and
recordkeeping requirements.
Dated: October 1, 2015.
Gina McCarthy,
Administrator.
For the reasons stated in the
preamble, title 40, chapter I, of the Code
of Federal Regulations is amended as
follows:
PART 98—MANDATORY
GREENHOUSE GAS REPORTING
1. The authority citation for part 98
continues to read as follows:
■
Authority: 42 U.S.C. 7401, et seq.
Subpart W—Petroleum and Natural
Gas Systems
2. Section 98.230 is amended by
adding paragraphs (a)(9) and (10) to read
as follows:
■
§ 98.230
Definition of the source category.
(a) * * *
(9) Onshore petroleum and natural
gas gathering and boosting. Onshore
petroleum and natural gas gathering and
boosting means gathering pipelines and
other equipment used to collect
petroleum and/or natural gas from
onshore production gas or oil wells and
used to compress, dehydrate, sweeten,
or transport the petroleum and/or
natural gas to a natural gas processing
facility, a natural gas transmission
pipeline or to a natural gas distribution
pipeline. Gathering and boosting
equipment includes, but is not limited
to gathering pipelines, separators,
compressors, acid gas removal units,
dehydrators, pneumatic devices/pumps,
storage vessels, engines, boilers, heaters,
and flares. Gathering and boosting
equipment does not include equipment
reported under any other industry
segment defined in this section.
Gathering pipelines operating on a
vacuum and gathering pipelines with a
GOR) less than 300 standard cubic feet
per stock tank barrel (scf/STB) are not
included in this industry segment (oil
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here refers to hydrocarbon liquids of all
API gravities).
(10) Onshore natural gas transmission
pipeline. Onshore natural gas
transmission pipeline means all natural
gas transmission pipelines as defined in
§ 98.238.
*
*
*
*
*
■ 3. Section 98.231 is amended by
revising paragraph (a) to read as follows:
§ 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 § 98.2(a)(2), except for
the industry segments in paragraphs
(a)(1) through (4) of this section.
(1) Facilities must report emissions
from the onshore petroleum and natural
gas production industry segment only if
emission sources specified in
§ 98.232(c) emit 25,000 metric tons of
CO2 equivalent or more per year.
(2) Facilities must report emissions
from the natural gas distribution
industry segment only if emission
sources specified in § 98.232(i) emit
25,000 metric tons of CO2 equivalent or
more per year.
(3) Facilities must report emissions
from the onshore petroleum and natural
gas gathering and boosting industry
segment only if emission sources
specified in § 98.232(j) emit 25,000
metric tons of CO2 equivalent or more
per year.
(4) Facilities must report emissions
from the onshore natural gas
transmission pipeline industry segment
only if emission sources specified in
§ 98.232(m) emit 25,000 metric tons of
CO2 equivalent or more per year.
*
*
*
*
*
■ 4. Section 98.232 is amended by:
■ a. Revising paragraphs (a) and (c)(6)
and (8);
■ b. Adding paragraph (j);
■ c. Revising paragraph (k); and
■ d. Adding paragraph (m).
The revisions and additions read as
follows:
tkelley on DSK3SPTVN1PROD with RULES3
§ 98.232
GHGs to report.
(a) You must report CO2, CH4, and
N2O emissions from each industry
segment specified in paragraphs (b)
through (j) and (m) of this section, CO2,
CH4, and N2O emissions from each flare
as specified in paragraphs (b) through (j)
of this section, and stationary and
portable combustion emissions as
applicable as specified in paragraph (k)
of this section.
*
*
*
*
*
(c) * * *
(6) Well venting during well
completions with hydraulic fracturing
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that have a GOR of 300 scf/STB or
greater (oil here refers to hydrocarbon
liquids produced of all API gravities).
*
*
*
*
*
(8) Well venting during well
workovers with hydraulic fracturing
that have a GOR of 300 scf/STB or
greater (oil here refers to hydrocarbon
liquids produced of all API gravities).
*
*
*
*
*
(j) For an onshore petroleum and
natural gas gathering and boosting
facility, report CO2, CH4, and N2O
emissions from the following source
types:
(1) Natural gas pneumatic device
venting.
(2) Natural gas driven pneumatic
pump venting.
(3) Acid gas removal vents.
(4) Dehydrator vents.
(5) Blowdown vent stacks.
(6) Storage tank vented emissions.
(7) Flare stack emissions.
(8) Centrifugal compressor venting.
(9) Reciprocating compressor venting.
(10) 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).
(11) Gathering pipeline equipment
leaks.
(12) You must use the methods in
§ 98.233(z) and report under this
subpart the emissions of CO2, CH4, and
N2O from stationary or portable fuel
combustion equipment that cannot
move on roadways under its own power
and drive train, and that is located at an
onshore petroleum and natural gas
gathering and boosting facility as
defined in § 98.238. Stationary or
portable equipment includes the
following equipment, which are integral
to the movement of natural gas: Natural
gas dehydrators, natural gas
compressors, electrical generators,
steam boilers, and process heaters.
(k) Report under subpart C of this part
(General Stationary Fuel Combustion
Sources) the emissions of CO2, CH4, and
N2O from each stationary fuel
combustion unit by following the
requirements of subpart C except for
facilities under onshore petroleum and
natural gas production, onshore
petroleum and natural gas gathering and
boosting, and natural gas distribution.
Onshore petroleum and natural gas
production facilities must report
stationary and portable combustion
emissions as specified in paragraph (c)
of this section. Natural gas distribution
facilities must report stationary
combustion emissions as specified in
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paragraph (i) of this section. Onshore
petroleum and natural gas gathering and
boosting facilities must report stationary
and portable combustion emissions as
specified in paragraph (j) of this section.
*
*
*
*
*
(m) For onshore natural gas
transmission pipeline, report pipeline
blowdown CO2 and CH4 emissions from
blowdown vent stacks.
■ 5. Section 98.233 is amended by:
■ a. Revising the parameters ‘‘EFt’’ and
‘‘GHGi’’ of Equation W–1 in paragraph
(a);
■ b. Revising paragraph (a)(2);
■ c. Revising the parameter ‘‘EF’’ of
Equation W–2 in paragraph (c);
■ d. Revising paragraph (d)(8)(iii);
■ e. Revising paragraphs (g)
introductory text, (g)(1) introductory
text, (g)(1)(i), and paragraph (g)(1)(ii)
heading;
■ f. Revising the parameters ‘‘FRMs,’’
‘‘FRs,p’’ and ‘‘PRs,p’’ of Equation W–12A
in paragraph (g)(1)(iii);
■ g. Revising the parameters ‘‘FRMi,’’
and ‘‘PRs,p’’ of Equation W–12B in
paragraph (g)(1)(iv);
■ h. Revising paragraphs (g)(1)(v) and
(vi);
■ i. Adding paragraph (g)(1)(vii);
■ j. Revising paragraph (g)(2)
introductory text;
■ k. Adding paragraph (g)(2)(iv);
■ l. Revising paragraph (g)(4)
introductory text;
■ m. Revising paragraph (i)(2)
introductory text;
■ n. Revising the parameters ‘‘Ta’’ and
‘‘Pa’’ of Equation W–14A in paragraph
(i)(2)(i);
■ o. Revising paragraphs (j) introductory
text, (j)(1) through (3), and (j)(6);
■ p. Revising paragraph (n)(2)(i);
■ q. Revising paragraphs (o)
introductory text and (o)(10);
■ r. Revising paragraphs (p)
introductory text and (p)(10);
■ s. Revising paragraphs (r) introductory
text, (r)(2) introductory text, and
(r)(2)(i);
■ t. Revising paragraphs (u)(2)(i) and
(iii); and
■ x. Revising paragraphs (z)
introductory text and (z)(1)(ii).
The revisions and additions read as
follows:
§ 98.233
Calculating GHG emissions.
*
*
*
(a) * * *
*
*
*
*
*
*
*
EFt = Population emission factors for natural
gas pneumatic device vents (in standard
cubic feet per hour per device) of each
type ‘‘t’’ listed in Tables W–1A, W–3,
and W–4 of this subpart for onshore
petroleum and natural gas production,
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bleed) using engineering estimates
based on best available data.
*
*
*
*
*
(c) * * *
*
*
*
*
*
EF = Population emissions factors for natural
gas driven pneumatic pumps (in
standard cubic feet per hour per pump)
listed in Table W–1A of this subpart for
onshore petroleum and natural gas
production and onshore petroleum and
natural gas gathering and boosting
facilities.
*
*
*
*
(2) For the onshore petroleum and
natural gas production industry
segment, you have the option in the first
two consecutive calendar years to
determine ‘‘Countt’’ for Equation W–1 of
this section for each type of natural gas
pneumatic device (continuous high
bleed, continuous low bleed, and
intermittent bleed) using engineering
estimates based on best available data.
For the onshore petroleum and natural
gas gathering and boosting industry
segment, you have the option in the first
two consecutive calendar years to
determine ‘‘Countt’’ for Equation W–1
for each type of natural gas pneumatic
device (continuous high bleed,
continuous low bleed, and intermittent
*
*
*
*
(d) * * *
(8) * * *
(iii) If a continuous gas analyzer is not
available or installed, you may use the
outlet pipeline quality specification for
CO2 in natural gas.
*
*
*
*
*
(g) Well venting during completions
and workovers with hydraulic
fracturing. Calculate annual volumetric
natural gas emissions from gas well and
oil well venting during completions and
workovers involving hydraulic
fracturing using Equation W–10A or
Equation W–10B of this section.
Equation W–10A applies to well venting
when the gas flowback rate is measured
from a specified number of example
completions or workovers and Equation
W–10B applies when the gas flowback
vent or flare volume is measured for
Where:
Es,n = Annual volumetric natural gas
emissions in standard cubic feet from gas
venting during well completions or
workovers following hydraulic fracturing
for each sub-basin and well type
combination.
W = Total number of wells completed or
worked over using hydraulic fracturing
in a sub-basin and well type
combination.
Tp,s = Cumulative amount of time of
flowback, after sufficient quantities of
gas are present to enable separation,
where gas vented or flared for the
completion or workover, in hours, for
each well, p, in a sub-basin and well
type combination during the reporting
year. This may include non-contiguous
periods of venting or flaring.
Tp,i = Cumulative amount of time of flowback
to open tanks/pits, from when gas is first
detected until sufficient quantities of gas
are present to enable separation, for the
completion or workover, in hours, for
each well, p, in a sub-basin and well
type combination during the reporting
year. This may include non-contiguous
periods of routing to open tanks/pits but
does not include periods when the oil
well ceases to produce fluids to the
surface.
FRMs = Ratio of average gas flowback, during
the period when sufficient quantities of
gas are present to enable separation, of
well completions and workovers from
hydraulic fracturing to 30-day
production rate for the sub-basin and
well type combination, calculated using
procedures specified in paragraph
(g)(1)(iii) of this section.
FRMi = Ratio of initial gas flowback rate
during well completions and workovers
from hydraulic fracturing to 30-day gas
production rate for the sub-basin and
well type combination, calculated using
procedures specified in paragraph
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*
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each completion or workover.
Completion and workover activities are
separated into two periods, an initial
period when flowback is routed to open
pits or tanks and a subsequent period
when gas content is sufficient to route
the flowback to a separator or when the
gas content is sufficient to allow
measurement by the devices specified in
paragraph (g)(1) of this section,
regardless of whether a separator is
actually utilized. If you elect to use
Equation W–10A, you must follow the
procedures specified in paragraph (g)(1).
If you elect to use Equation W–10B, you
must use a recording flow meter
installed on the vent line, downstream
of a separator and ahead of a flare or
vent, to measure the gas flowback. For
either equation, emissions must be
calculated separately for completions
and workovers, for each sub-basin, and
for each well type combination
identified in paragraph (g)(2) of this
section. You must calculate CH4 and
CO2 volumetric and mass emissions as
specified in paragraph (g)(3) of this
section. If emissions from well venting
during completions and workovers with
hydraulic fracturing are routed to a
flare, you must calculate CH4, CO2, and
N2O annual emissions as specified in
paragraph (g)(4) of this section.
(g)(1)(iv) of this section, for the period of
flow to open tanks/pits.
PRs,p = Average gas production flow rate
during the first 30 days of production
after completions of newly drilled wells
or well workovers using hydraulic
fracturing in standard cubic feet per hour
of each well p, that was measured in the
sub-basin and well type combination. If
applicable, PRs,p may be calculated for
oil wells using procedures specified in
paragraph (g)(1)(vii) of this section.
EnFs,p = Volume of N2 injected gas in cubic
feet at standard conditions that was
injected into the reservoir during an
energized fracture job or during flowback
for each well, p, as determined by using
an appropriate meter according to
methods described in § 98.234(b), or by
using receipts of gas purchases that are
used for the energized fracture job or
injection during flowback. Convert to
standard conditions using paragraph (t)
of this section. If the fracture process did
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onshore natural gas transmission
compression, and underground natural
gas storage facilities, respectively.
Onshore petroleum and natural gas
gathering and boosting facilities must
use the population emission factors
listed in Table W–1A of this subpart.
GHGi = For onshore petroleum and natural
gas production facilities, onshore
petroleum and natural gas gathering and
boosting facilities, onshore natural gas
transmission compression facilities, and
underground natural gas storage
facilities, concentration of GHGi, CH4 or
CO2, in produced natural gas or
processed natural gas for each facility as
specified in paragraphs (u)(2)(i), (iii), and
(iv) of this section.
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not inject gas into the reservoir or if the
injected gas is CO2 then EnFs,p is 0.
FVs,p = Flow volume of vented or flared gas
for each well, p, in standard cubic feet
measured using a recording flow meter
(digital or analog) on the vent line to
measure gas flowback during the
separation period of the completion or
workover according to methods set forth
in § 98.234(b).
FRp,i = Flow rate vented or flared of each
well, p, in standard cubic feet per hour
measured using a recording flow meter
(digital or analog) on the vent line to
measure the flowback, at the beginning
of the period of time when sufficient
quantities of gas are present to enable
separation, of the completion or
workover according to methods set forth
in § 98.234(b).
tkelley on DSK3SPTVN1PROD with RULES3
(1) If you elect to use Equation W–
10A of this section on gas wells, you
must use Calculation Method 1 as
specified in paragraph (g)(1)(i) of this
section, or Calculation Method 2 as
specified in paragraph (g)(1)(ii) of this
section, to determine the value of FRMs
and FRMi. If you elect to use Equation
W–10A of this section on oil wells, you
must use Calculation Method 1 as
specified in paragraph (g)(1)(i) to
determine the value of FRMs and FRMi.
These values must be based on the flow
rate for flowback gases, once sufficient
gas is present to enable separation. The
number of measurements or calculations
required to estimate FRMs and FRMi
must be determined individually for
completions and workovers per subbasin and well type combination as
follows: Complete measurements or
calculations for at least one completion
or workover for less than or equal to 25
completions or workovers for each well
type combination within a sub-basin;
complete measurements or calculations
for at least two completions or
workovers for 26 to 50 completions or
workovers for each sub-basin and well
type combination; complete
measurements or calculations for at
least three completions or workovers for
51 to 100 completions or workovers for
each sub-basin and well type
combination; complete measurements or
calculations for at least four
completions or workovers for 101 to 250
completions or workovers for each subbasin and well type combination; and
complete measurements or calculations
for at least five completions or
workovers for greater than 250
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completions or workovers for each subbasin and well type combination.
(i) Calculation Method 1. You must
use Equation W–12A of this section as
specified in paragraph (g)(1)(iii) of this
section to determine the value of FRMs.
You must use Equation W–12B of this
section as specified in paragraph
(g)(1)(iv) of this section to determine the
value of FRMi. The procedures specified
in paragraphs (g)(1)(v) and (vi) of this
section also apply. When making gas
flowback measurements for use in
Equations W–12A and W–12B of this
section, you must use a recording flow
meter (digital or analog) installed on the
vent line, downstream of a separator
and ahead of a flare or vent, to measure
the gas flowback rates in units of
standard cubic feet per hour according
to methods set forth in § 98.234(b).
(ii) Calculation Method 2 (for gas
wells). * * *
(iii) * * *
*
*
*
*
*
FRMs = Ratio of average gas flowback rate,
during the period of time when sufficient
quantities of gas are present to enable
separation, of well completions and
workovers from hydraulic fracturing to
30-day gas production rate for each subbasin and well type combination.
FRs,p = Measured average gas flowback rate
from Calculation Method 1 described in
paragraph (g)(1)(i) of this section or
calculated average flowback rate from
Calculation Method 2 described in
paragraph (g)(1)(ii) of this section, during
the separation period in standard cubic
feet per hour for well(s) p for each subbasin and well type combination.
Convert measured and calculated FRa
values from actual conditions upstream
of the restriction orifice (FRa) to standard
conditions (FRs,p) for each well p using
Equation W–33 in paragraph (t) of this
section. You may not use flow volume as
used in Equation W–10B of this section
converted to a flow rate for this
parameter.
PRs,p = Average gas production flow rate
during the first 30 days of production
after completions of newly drilled wells
or well workovers using hydraulic
fracturing, in standard cubic feet per
hour for each well, p, that was measured
in the sub-basin and well type
combination. For oil wells for which
production is not measured continuously
during the first 30 days of production,
the average flow rate may be based on
individual well production tests
conducted within the first 30 days of
production. Alternatively, if applicable,
PRs,p may be calculated for oil wells
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using procedures specified in paragraph
(g)(1)(vii) of this section.
*
*
*
(iv) * * *
*
*
*
*
*
*
*
FRMi = Ratio of initial gas flowback rate
during well completions and workovers
from hydraulic fracturing to 30-day gas
production rate for the sub-basin and
well type combination, for the period of
flow to open tanks/pits.
*
*
*
*
*
PRs,p = Average gas production flow rate
during the first 30-days of production
after completions of newly drilled wells
or well workovers using hydraulic
fracturing, in standard cubic feet per
hour of each well, p, that was measured
in the sub-basin and well type
combination. For oil wells for which
production is not measured continuously
during the first 30 days of production,
the average flow rate may be based on
individual well production tests
conducted within the first 30 days of
production. Alternatively, if applicable,
PRs,p may be calculated for oil wells
using procedures specified in paragraph
(g)(1)(vii) of this section.
*
*
*
*
*
(v) For Equation W–10A of this
section, the ratio of gas flowback rate
during well completions and workovers
from hydraulic fracturing to 30-day gas
production rate are applied to all well
completions and well workovers,
respectively, in the sub-basin and well
type combination for the total number of
hours of flowback and for the first 30
day average gas production rate for each
of these wells.
(vi) For Equations W–12A and W–12B
of this section, calculate new flowback
rates for well completions and well
workovers in each sub-basin and well
type combination once every two years
starting in the first calendar year of data
collection.
(vii) For oil wells where the gas
production rate is not metered and you
elect to use Equation W–10A of this
section, calculate the average gas
production rate (PRs,p) using Equation
W–12C of this section. If GOR cannot be
determined from your available data,
then you must use one of the procedures
specified in paragraph (g)(1)(vii)(A) or
(B) of this section to determine GOR. If
GOR from each well is not available, use
the GOR from a cluster of wells in the
same sub-basin category.
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Where:
PRs,p = Average gas production flow rate
during the first 30 days of production
after completions of newly drilled wells
or well workovers using hydraulic
fracturing in standard cubic feet per hour
of well p, in the sub-basin and well type
combination.
GORp = Average gas to oil ratio during the
first 30 days of production after
completions of newly drilled wells or
workovers using hydraulic fracturing in
standard cubic feet of gas per barrel of
oil for each well p, that was measured in
the sub-basin and well type combination;
oil here refers to hydrocarbon liquids
produced of all API gravities.
Vp = Volume of oil produced during the first
30 days of production after completions
of newly drilled wells or well workovers
using hydraulic fracturing in barrels of
each well p, that was measured in the
sub-basin and well type combination.
720 = Conversion from 30 days of production
to hourly production rate.
(A) You may use an appropriate
standard method published by a
consensus-based standards organization
if such a method exists.
(B) You may use an industry standard
practice as described in § 98.234(b).
(2) For paragraphs (g) introductory
text and (g)(1) of this section,
measurements and calculations are
completed separately for workovers and
completions per sub-basin and well type
combination. A well type combination
is a unique combination of the
parameters listed in paragraphs (g)(2)(i)
through (iv) of this section.
*
*
*
*
*
(iv) Oil well or gas well.
*
*
*
*
*
(4) Calculate annual emissions from
well venting during well completions
and workovers from hydraulic
fracturing where all or a portion of the
gas is flared as specified in paragraphs
(g)(4)(i) and (ii) of this section.
*
*
*
*
*
(i) * * *
(2) Method for determining emissions
from blowdown vent stacks according to
equipment or event type. If you elect to
determine emissions according to each
equipment or event type, using unique
physical volumes as calculated in
paragraph (i)(1) of this section, you must
calculate emissions as specified in
paragraph (i)(2)(i) of this section and
either paragraph (i)(2)(ii) or, if
applicable, paragraph (i)(2)(iii) of this
section for each equipment or event
type. For industry segments other than
onshore natural gas transmission
pipeline, equipment or event types must
be grouped into the following seven
categories: Facility piping (i.e., piping
within the facility boundary other than
physical volumes associated with
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distribution pipelines), pipeline venting
(i.e., physical volumes associated with
distribution pipelines vented within the
facility boundary), compressors,
scrubbers/strainers, pig launchers and
receivers, emergency shutdowns (this
category includes emergency shutdown
blowdown emissions regardless of
equipment type), and all other
equipment with a physical volume
greater than or equal to 50 cubic feet. If
a blowdown event resulted in emissions
from multiple equipment types and the
emissions cannot be apportioned to the
different equipment types, then
categorize the blowdown event as the
equipment type that represented the
largest portion of the emissions for the
blowdown event. For the onshore
natural gas transmission pipeline
segment, pipeline segments or event
types must be grouped into the
following eight categories: Pipeline
integrity work (e.g., the preparation
work of modifying facilities, ongoing
assessments, maintenance or
mitigation), traditional operations or
pipeline maintenance, equipment
replacement or repair (e.g., valves), pipe
abandonment, new construction or
modification of pipelines including
commissioning and change of service,
operational precaution during activities
(e.g. excavation near pipelines),
emergency shutdowns including
pipeline incidents as defined in 49 CFR
191.3, and all other pipeline segments
with a physical volume greater than or
equal to 50 cubic feet. If a blowdown
event resulted in emissions from
multiple categories and the emissions
cannot be apportioned to the different
categories, then categorize the
blowdown event in the category that
represented the largest portion of the
emissions for the blowdown event.
(i) * * *
*
*
*
*
*
Ta = Temperature at actual conditions in the
unique physical volume (°F). For
emergency blowdowns at onshore
petroleum and natural gas gathering and
boosting facilities, engineering estimates
based on best available information may
be used to determine the temperature.
*
*
*
*
*
Pa = Absolute pressure at actual conditions
in the unique physical volume (psia). For
emergency blowdowns at onshore
petroleum and natural gas gathering and
boosting facilities, engineering estimates
based on best available information may
be used to determine the pressure.
*
*
*
*
*
(j) Onshore production and onshore
petroleum and natural gas gathering
and boosting storage tanks. Calculate
CH4, CO2, and N2O (when flared)
emissions from atmospheric pressure
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64287
fixed roof storage tanks receiving
hydrocarbon produced liquids from
onshore petroleum and natural gas
production facilities and onshore
petroleum and natural gas gathering and
boosting facilities (including stationary
liquid storage not owned or operated by
the reporter), as specified in this
paragraph (j). For gas-liquid separators
or onshore petroleum and natural gas
gathering and boosting non-separator
equipment (e.g., stabilizers, slug
catchers) with annual average daily
throughput of oil greater than or equal
to 10 barrels per day, calculate annual
CH4 and CO2 using Calculation Method
1 or 2 as specified in paragraphs (j)(1)
and (2) of this section. For wells flowing
directly to atmospheric storage tanks
without passing through a separator
with throughput greater than or equal to
10 barrels per day, calculate annual CH4
and CO2 emissions using Calculation
Method 2 as specified in paragraph (j)(2)
of this section. For hydrocarbon liquids
flowing to gas-liquid separators or nonseparator equipment or directly to
atmospheric storage tanks with
throughput less than 10 barrels per day,
use Calculation Method 3 as specified in
paragraph (j)(3) of this section. If you
use Calculation Method 1 or Calculation
Method 2 for separators, you must also
calculate emissions that may have
occurred due to dump valves not
closing properly using the method
specified in paragraph (j)(6) of this
section. If emissions from atmospheric
pressure fixed roof storage tanks are
routed to a vapor recovery system, you
must adjust the emissions downward
according to paragraph (j)(4) of this
section. If emissions from atmospheric
pressure fixed roof storage tanks are
routed to a flare, you must calculate
CH4, CO2, and N2O annual emissions as
specified in paragraph (j)(5) of this
section.
(1) Calculation Method 1. Calculate
annual CH4 and CO2 emissions from
onshore production storage tanks and
onshore petroleum and natural gas
gathering and boosting storage tanks
using operating conditions in the last
gas-liquid separator or non-separator
equipment before liquid transfer to
storage tanks. Calculate flashing
emissions with a software program,
such as AspenTech HYSYS® or API
4697 E&P Tank, that uses the PengRobinson equation of state, models
flashing emissions, and speciates CH4
and CO2 emissions that will result when
the oil from the separator or nonseparator equipment enters an
atmospheric pressure storage tank. The
following parameters must be
determined for typical operating
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boosting for oil composition and Reid
vapor pressure using an appropriate
standard method published by a
consensus-based standards organization.
(2) Calculation Method 2. Calculate
annual CH4 and CO2 emissions using
the methods in paragraph (j)(2)(i) of this
section for gas-liquid separators with
annual average daily throughput of oil
greater than or equal to 10 barrels per
day. Calculate annual CH4 and CO2
emissions using the methods in
paragraph (j)(2)(ii) of this section for
wells with annual average daily oil
production greater than or equal to 10
barrels per day that flow directly to
atmospheric storage tanks in onshore
petroleum and natural gas production
and onshore petroleum and natural gas
gathering and boosting (if applicable).
Calculate annual CH4 and CO2
emissions using the methods in
paragraph (j)(2)(iii) of this section for
non-separator equipment with annual
average daily hydrocarbon liquids
throughput greater than or equal to 10
barrels per day that flow directly to
atmospheric storage tanks in onshore
petroleum and natural gas gathering and
boosting.
(i) Flow to storage tank after passing
through a separator. Assume that all of
the CH4 and 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
§ 98.234(b) to sample and analyze
separator oil composition at separator
pressure and temperature.
(ii) Flow to storage tank direct from
wells. Calculate CH4 and CO2 emissions
using either of the methods in paragraph
(j)(2)(ii)(A) or (B) of this section.
(A) If well production oil and gas
compositions are available through a
previous analysis, select the latest
available analysis that is representative
of produced oil and gas from the subbasin category and assume all of the CH4
and CO2 in both oil and gas are emitted
from the tank.
(B) 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 the
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.
(iii) Flow to storage tank direct from
non-separator equipment. Calculate CH4
and CO2 emissions using either of the
methods in paragraph (j)(2)(iii)(A) or (B)
of this section.
(A) If other non-separator equipment
liquid and gas compositions are
available through a previous analysis,
select the latest available analysis that is
representative of liquid and gas from
non-separator equipment in the same
county and assume all of the CH4 and
CO2 in both hydrocarbon liquids and
gas are emitted from the tank.
(B) If non-separator equipment liquid
and gas compositions are not available,
use default liquid and gas compositions
in software programs, such as API 4697
E&P Tank, that most closely match the
non-separator equipment gas/liquid
ratio and API gravity and assume all of
the CH4 and CO2 in both hydrocarbon
liquids and gas are emitted from the
tank.
(3) Calculation Method 3. Calculate
CH4 and CO2 emissions using Equation
W–15 of this section:
Where:
Es,i = Annual total volumetric GHG emissions
(either CO2 or CH4) at standard
conditions in cubic feet.
EFi = Population emission factor for
separators, wells, or non-separator
equipment in thousand standard cubic
feet per separator, well, or non-separator
equipment per year, for crude oil use 4.2
for CH4 and 2.8 for CO2 at 60 °F and 14.7
psia, and for gas condensate use 17.6 for
CH4 and 2.8 for CO2 at 60 °F and 14.7
psia.
Count = Total number of separators, wells, or
non-separator equipment with annual
average daily throughput less than 10
barrels per day. Count only separators,
wells, or non-separator equipment that
feed oil directly to the storage tank.
1,000 = Conversion from thousand standard
cubic feet to standard cubic feet.
(6) If you use Calculation Method 1 or
Calculation Method 2 in paragraph (j)(1)
or (2) of this section, calculate emissions
from occurrences of gas-liquid separator
liquid dump valves not closing during
the calendar year by using Equation W–
16 of this section.
*
*
*
*
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conditions over the year by engineering
estimate and process knowledge based
on best available data, and must be used
at a minimum to characterize emissions
from liquid transferred to tanks:
(i) Separator or non-separator
equipment temperature.
(ii) Separator or non-separator
equipment 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 or non-separator
equipment oil composition and Reid
vapor pressure. If this data is not
available, determine these parameters
by using one of the methods described
in paragraphs (j)(1)(vii)(A) through (C)
of this section.
(A) If separator or non-separator
equipment oil composition and Reid
vapor pressure default data are provided
with the software program, select the
default values that most closely match
your separator or non-separator
equipment pressure first, and API
gravity secondarily.
(B) If separator or non-separator
equipment oil composition and Reid
vapor pressure data are available
through your previous analysis, select
the latest available analysis that is
representative of produced crude oil or
condensate from the sub-basin category
for onshore petroleum and natural gas
production or from the county for
onshore petroleum and natural gas
gathering and boosting.
(C) Analyze a representative sample of
separator or non-separator equipment
oil in each sub-basin category for
onshore petroleum and natural gas
production or each county for onshore
petroleum and natural gas gathering and
Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations
Where:
Es,i,o = Annual volumetric GHG emissions at
standard conditions from each storage
tank in cubic feet that resulted from the
dump valve on the gas-liquid separator
not closing properly.
En = Storage tank emissions as determined in
paragraphs (j)(1), (j)(2) and, if applicable,
(j)(4) of this section in standard cubic
feet per year.
Tn = Total time a dump valve is not closing
properly in the calendar year in hours.
Estimate Tn based on maintenance,
operations, or routine separator
inspections that indicate the period of
time when the valve was malfunctioning
in open or partially open position.
CFn = Correction factor for tank emissions for
time period Tn is 2.87 for crude oil
production. Correction factor for tank
emissions for time period Tn is 4.37 for
gas condensate production.
8,760 = Conversion to hourly emissions.
64289
*
*
*
*
(p) Reciprocating compressor venting.
If you are required to report emissions
from reciprocating compressor venting
as specified in § 98.232(d)(1), (e)(1),
(f)(1), (g)(1), and (h)(1), you must
conduct volumetric emission
measurements specified in paragraph
(p)(1) of this section using methods
specified in paragraphs (p)(2) through
(5) of this section; perform calculations
specified in paragraphs (p)(6) through
(9) of this section; and calculate CH4
and CO2 mass emissions as specified in
paragraph (p)(11) of this section. If
emissions from a compressor source are
routed to a flare, paragraphs (p)(1)
through (11) do not apply and instead
you must calculate CH4, CO2, and N2O
emissions as specified in paragraph
(p)(12) of this section. If emissions from
a compressor source are captured for
fuel use or are routed to a thermal
oxidizer, paragraphs (p)(1) through (12)
do not apply and instead you must
calculate and report emissions as
specified in subpart C of this part. If
emissions from a compressor source are
routed to vapor recovery, paragraphs
(p)(1) through (12) do not apply. If you
are required to report emissions from
reciprocating compressor venting at an
onshore petroleum and natural gas
production facility as specified in
§ 98.232(c)(11) or an onshore petroleum
and natural gas gathering and boosting
facility as specified in § 98.232(j)(5), you
must calculate volumetric emissions as
specified in paragraph (p)(10); and
calculate CH4 and CO2 mass emissions
as specified in paragraph (p)(11).
*
*
*
*
*
(10) Method for calculating
volumetric GHG emissions from
reciprocating compressor venting at an
onshore petroleum and natural gas
production facility or an onshore
petroleum and natural gas gathering
and boosting facility. You must
calculate emissions from reciprocating
compressor venting at an onshore
petroleum and natural gas production
facility or an onshore petroleum and
natural gas gathering and boosting
facility using Equation W–29D of this
section.
Where:
Es,i = Annual volumetric GHGi (either CH4 or
CO2) emissions from reciprocating
compressors, at standard conditions, in
cubic feet.
Count = Total number of reciprocating
compressors.
EFi,s = Emission factor for GHGi. Use 9.48 ×
103 standard cubic feet per year per
compressor for CH4 and 5.27 × 102
standard cubic feet per year per
compressor for CO2 at 60 °F and 14.7
psia.
*
*
*
*
*
(n) * * *
(2) * * *
(i) For onshore natural gas production
and onshore petroleum and natural gas
gathering and boosting, determine the
Where:
Es,i = Annual volumetric GHGi (either CH4 or
CO2) emissions from centrifugal
compressor wet seals, at standard
conditions, in cubic feet.
Count = Total number of centrifugal
compressors that have wet seal oil
degassing vents.
EFi,s = Emission factor for GHGi. Use 1.2 ×
107 standard cubic feet per year per
compressor for CH4 and 5.30 × 105
standard cubic feet per year per
compressor for CO2 at 60 °F and 14.7
psia.
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*
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*
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*
22OCR3
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*
ER22OC15.012</GPH>
emissions from a compressor source are
routed to vapor recovery, paragraphs
(o)(1) through (12) do not apply. If you
are required to report emissions from
centrifugal compressor venting at an
onshore petroleum and natural gas
production facility as specified in
§ 98.232(c)(19) or an onshore petroleum
and natural gas gathering and boosting
facility as specified in § 98.232(j)(8), you
must calculate volumetric emissions as
specified in paragraph (o)(10); and
calculate CH4 and CO2 mass emissions
as specified in paragraph (o)(11).
*
*
*
*
*
(10) Method for calculating
volumetric GHG emissions from wet seal
oil degassing vents at an onshore
petroleum and natural gas production
facility or an onshore petroleum and
natural gas gathering and boosting
facility. You must calculate emissions
from centrifugal compressor wet seal oil
degassing vents at an onshore petroleum
and natural gas production facility or an
onshore petroleum and natural gas
gathering and boosting facility using
Equation W–25 of this section.
ER22OC15.011</GPH>
GHG mole fraction using paragraph
(u)(2)(i) of this section.
*
*
*
*
*
(o) Centrifugal compressor venting. If
you are required to report emissions
from centrifugal compressor venting as
specified in § 98.232(d)(2), (e)(2), (f)(2),
(g)(2), and (h)(2), you must conduct
volumetric emission measurements
specified in paragraph (o)(1) of this
section using methods specified in
paragraphs (o)(2) through (5) of this
section; perform calculations specified
in paragraphs (o)(6) through (9) of this
section; and calculate CH4 and CO2
mass emissions as specified in
paragraph (o)(11) of this section. If
emissions from a compressor source are
routed to a flare, paragraphs (o)(1)
through (11) do not apply and instead
you must calculate CH4, CO2, and N2O
emissions as specified in paragraph
(o)(12) of this section. If emissions from
a compressor source are captured for
fuel use or are routed to a thermal
oxidizer, paragraphs (o)(1) through (12)
do not apply and instead you must
calculate and report emissions as
specified in subpart C of this part. If
64290
Federal Register / Vol. 80, No. 204 / Thursday, October 22, 2015 / Rules and Regulations
CH4 plus CO2 by weight are exempt
from the requirements of this paragraph
(r) and do not need to be reported.
Tubing systems equal to or less than one
half inch diameter are exempt from the
requirements of paragraph (r) of this
section and do not need to be reported.
You must calculate emissions from all
emission sources listed in this
paragraph using Equation W–32A of this
section, except for natural gas
distribution facility emission sources
listed in § 98.232(i)(3). Natural gas
distribution facility emission sources
listed in § 98.232(i)(3) must calculate
emissions using Equation W–32B of this
section and according to paragraph
(r)(6)(ii) of this section.
Where:
Es,e,i = Annual volumetric emissions of GHGi
from the emission source type in
standard cubic feet. The emission source
type may be a component (e.g.
connector, open-ended line, etc.), below
grade metering-regulating station, below
grade transmission-distribution transfer
station, distribution main, distribution
service, or gathering pipeline.
Es,MR,i = Annual volumetric emissions of
GHGi from all meter/regulator runs at
above grade metering regulating stations
that are not above grade transmissiondistribution transfer stations or, when
used to calculate emissions according to
paragraph (q)(9) of this section, the
annual volumetric emissions of GHGi
from all meter/regulator runs at above
grade transmission-distribution transfer
stations, in standard cubic feet.
Counte = Total number of the emission
source type at the facility. For onshore
petroleum and natural gas production
facilities and onshore petroleum and
natural gas gathering and boosting
facilities, 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. Onshore petroleum
and natural gas gathering and boosting
facilities must also count the miles of
gathering pipelines by material type
(protected steel, unprotected steel,
plastic, or cast iron). Underground
natural gas storage facilities must count
each component listed in Table W–4 of
this subpart. LNG storage facilities must
count the number of vapor recovery
compressors. LNG import and export
facilities must count the number of vapor
recovery compressors. Natural gas
distribution facilities must count: (1) The
number of distribution services by
material type; (2) miles of distribution
mains by material type; and (3) number
of below grade metering-regulating
stations, by pressure type; as listed in
Table W–7 of this subpart.
CountMR = Total number of meter/regulator
runs at above grade metering-regulating
stations that are not above grade
transmission-distribution transfer
stations or, when used to calculate
emissions according to paragraph (q)(9)
of this section, the total number of
meter/regulator runs at above grade
transmission-distribution transfer
stations.
EFs,e = Population emission factor for the
specific emission source type, as listed
in Tables W–1A and W–4 through 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.
EFs,MR,i = Meter/regulator run population
emission factor for GHGi based on all
surveyed above grade transmissiondistribution transfer stations over ‘‘n’’
years, in standard cubic feet of GHGi per
operational hour of all meter/regulator
runs, as determined in Equation W–31 of
this section.
GHGi = For onshore petroleum and natural
gas production facilities and onshore
petroleum and natural gas gathering and
boosting facilities, concentration of
GHGi, CH4, or CO2, in produced natural
gas as defined in paragraph (u)(2) of this
section; for onshore natural gas
transmission compression and
underground natural gas storage, GHGi
equals 0.975 for CH4 and 1.1 × 10¥2 for
CO2; for LNG storage and LNG import
and export equipment, GHGi equals 1 for
CH4 and 0 for CO2; and for natural gas
distribution, GHGi equals 1 for CH4 and
1.1 × 10¥2 CO2.
Te = Average estimated time that each
emission source type associated with the
equipment leak emission was
operational in the calendar year, in
hours, using engineering estimate based
on best available data.
Tw,avg = Average estimated time that each
meter/regulator run was operational in
the calendar year, in hours per meter/
regulator run, using engineering estimate
based on best available data.
equipment and components associated
with gas wells and onshore petroleum
and natural gas gathering and boosting
systems are considered gas service
components in reference to Table W–1A
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 W–1A
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
calculation methods described in this
paragraph (r)(2), except for miles of
gathering pipelines by material type,
which must be determined using
Component Count Method 2 in
paragraph (r)(2)(ii) of this section. The
same calculation method must be used
for the entire calendar year.
(i) Component Count Method 1. For
all onshore petroleum and natural gas
production operations and onshore
petroleum and natural gas gathering and
boosting 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. For meters/piping, use one
meters/piping per well-pad for onshore
petroleum and natural gas production
operations and the number of meters in
the facility for onshore petroleum and
natural gas gathering and boosting
operations.
(B) Multiply major equipment counts
by the average component counts listed
in Table W–1B of this subpart for
onshore natural gas production and
onshore petroleum and natural gas
gathering and boosting; and Table W–1C
of this subpart for onshore oil
production. Use the appropriate factor
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*
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*
*
*
(2) Onshore petroleum and natural gas
production facilities and onshore
petroleum and natural gas gathering and
boosting facilities must use the
appropriate default whole gas
population emission factors listed in
Table W–1A of this subpart. Major
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(r) Equipment leaks by population
count. This paragraph (r) applies to
emissions sources listed in § 98.232
(c)(21), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3),
(i)(4), (i)(5), (i)(6), (j)(10), and (j)(11) on
streams with gas content greater than 10
percent CH4 plus CO2 by weight.
Emissions sources in streams with gas
content less than or equal to 10 percent
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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.
*
*
*
*
*
(u) * * *
(2) * * *
(i) GHG mole fraction in produced
natural gas for onshore petroleum and
natural gas production facilities and
onshore petroleum and natural gas
gathering and boosting facilities. If you
have a continuous gas composition
analyzer for produced natural gas, you
must use an annual average of these
values for determining the mole
fraction. If you do not have a continuous
gas composition analyzer, then you
must use an annual average gas
composition based on your most recent
available analysis of the sub-basin
category or facility, as applicable to the
emission source.
*
*
*
*
*
(iii) GHG mole fraction in
transmission pipeline natural gas that
passes through the facility for the
onshore natural gas transmission
compression industry segment and the
onshore natural gas transmission
pipeline industry segment. You may use
either a default 95 percent methane and
1 percent carbon dioxide fraction for
GHG mole fraction in natural gas or site
specific engineering estimates based on
best available data.
*
*
*
*
*
(z) Onshore petroleum and natural
gas production, onshore petroleum and
natural gas gathering and boosting, and
natural gas distribution combustion
emissions. Calculate CO2, CH4, and N2O
combustion-related emissions from
stationary or portable equipment, except
as specified in paragraphs (z)(3) and (4)
of this section, as follows:
(1) * * *
(ii) Emissions from fuel combusted in
stationary or portable equipment at
onshore petroleum and natural gas
production facilities, at onshore
petroleum and natural gas gathering and
boosting facilities, and at natural gas
distribution facilities will be reported
according to the requirements specified
in § 98.236(z) and not according to the
reporting requirements specified in
subpart C of this part.
*
*
*
*
*
■ 6. Section 98.234 is amended by
adding paragraph (g) to read as follows:
§ 98.234 Monitoring and QA/QC
requirements.
*
*
*
*
*
(g) Special reporting provisions for
best available monitoring methods in
reporting year 2016—(1) Best available
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monitoring methods. From January 1,
2016, to December 31, 2016, you must
use the calculation methodologies and
equations in § 98.233 but you may use
the best available monitoring method as
described in paragraph (g)(2) of this
section for any parameter specified in
paragraphs (g)(3) through (6) of this
section for which it is not reasonably
feasible to acquire, install, and operate
a required piece of monitoring
equipment by January 1, 2016. Starting
no later than January 1, 2017, you must
discontinue using best available
methods and begin following all
applicable monitoring and QA/QC
requirements of this part. For onshore
petroleum and natural gas production,
this paragraph (g)(1) only applies if
emissions from well completions and
workovers of oil wells with hydraulic
fracturing cause your facility to exceed
the reporting threshold in § 98.231(a)(1).
(2) Best available monitoring methods
means any of the following methods:
(i) Monitoring methods currently used
by the facility that do not meet the
specifications of this subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(3) Best available monitoring methods
for well-related measurement data for
oil wells with hydraulic fracturing. You
may use best available monitoring
methods for any well-related
measurement data that cannot
reasonably be measured according to the
monitoring and QA/QC requirements of
this subpart for venting during well
completions and workovers of oil wells
with hydraulic fracturing.
(4) Best available monitoring methods
for measurement data for onshore
petroleum and natural gas gathering
and boosting facilities. You may use
best available monitoring methods for
any leak detection and/or measurement
data that cannot reasonably be measured
according to the monitoring and QA/QC
requirements of this subpart for acid gas
removal vents as specified in
§ 98.233(d).
(5) Best available monitoring methods
for measurement data for natural gas
transmission pipelines. You may use
best available monitoring methods for
any measurement data for natural gas
transmission pipelines that cannot
reasonably be obtained according to the
monitoring and QA/QC requirements of
this subpart for blowdown vent stacks.
(6) Best available monitoring methods
for specified activity data. You may use
best available monitoring methods for
activity data as listed in paragraphs
(g)(6)(i) through (iii) of this section that
cannot reasonably be obtained
according to the monitoring and QA/QC
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requirements of this subpart for well
completions and workovers of oil wells
with hydraulic fracturing, onshore
petroleum and natural gas gathering and
boosting facilities, or natural gas
transmission pipelines.
(i) Cumulative hours of venting, days,
or times of operation in § 98.233(e), (g),
(o), (p), and (r).
(ii) Number of blowdowns,
completions, workovers, or other events
in § 98.233(g) and (i).
(iii) Cumulative volume produced,
volume input or output, or volume of
fuel used in paragraphs § 98.233(d), (e),
(j), (n), and (z).
*
*
*
*
*
■ 7. Section 98.236 is amended by:
■ a. Revising paragraph (a) introductory
text;
■ b. Adding paragraphs (a)(9) and (10);
■ c. Revising paragraphs (d)(1)(i) and
(vi);
■ d. Revising paragraphs (e)(1)(i) and
(xviii);
■ e. Revising paragraphs (f)(1)(ii),
(f)(1)(xi)(A), (f)(1)(xii)(A), and (f)(2)(i);
■ f. Revising paragraphs (g) introductory
text, (g)(1), (g)(2), (g)(5), and (g)(6);
■ g. Revising paragraphs (h)(1)(i) and
(iv), (h)(2)(i) and (iv), (h)(3)(i), and
(h)(4)(i);
■ h. Revising paragraphs (i)
introductory text and (i)(1) introductory
text;
■ i. Adding paragraph (i)(3);
■ j. Revising paragraphs (j) introductory
text and (j)(1) introductory text;
■ k. Revising paragraphs (j)(1)(i), (iii),
(iv) (v), (vii), and (viii);
■ l. Revising paragraphs (j)(2)(i)
introductory text, (j)(2)(i)(A) through
(C), (j)(2)(ii), (j)(2)(iii) introductory text,
(j)(2)(iii)(A) and (B), and (j)(3)
introductory text;
■ m. Revising paragraph (l)(1)
introductory text;
■ n. Redesignating paragraphs (l)(1)(ii)
through (vi) as paragraphs (l)(1)(iii)
through (vii), respectively;
■ o. Adding paragraph (l)(1)(ii);
■ p. Revising newly designated
paragraph (l)(1)(v);
■ q. Revising paragraph (l)(2)
introductory text;
■ r. Redesignating paragraphs (l)(2)(ii)
through (vii) as paragraphs (l)(2)(iii)
through (viii), respectively;
■ s. Adding paragraph (l)(2)(ii);
■ t. Revising newly designated
paragraph (l)(2)(v);
■ u. Revising paragraph (l)(3)
introductory text;
■ v. Redesignating paragraphs (l)(3)(ii)
through (v) as paragraphs (l)(3)(iii)
through (vi), respectively;
■ w. Adding paragraph (l)(3)(ii);
■ x. Revising newly designated
paragraph (l)(3)(iv);
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y. Revising paragraph (l)(4)
introductory text;
■ a. Redesignating paragraphs (l)(4)(ii)
through (vi) as paragraphs (l)(4)(iii)
through (vii), respectively;
■ aa. Adding paragraph (l)(4)(ii);
■ bb. Revising newly designated
paragraph (l)(4)(iv);
■ cc. Revising paragraphs (m)(1), (m)(5),
(m)(6), (m)(7)(i), (m)(8)(i);
■ dd. Revising paragraph (n)(1);
■ ee. Revising paragraphs (o)
introductory text and (o)(5) introductory
text;
■ ff. Revising paragraphs (p)
introductory text and (p)(5) introductory
text;
■ gg. Revising paragraphs (r)(1)
introductory text, (r)(1)(i), (r)(3)
introductory text, and (r)(3)(ii)
introductory text;
■ hh. Revising paragraph (z)
introductory text;
■ ii. Revising paragraphs (aa)
introductory text and (aa)(1)(ii)(D)
through (H);
■ jj. Adding paragraphs (aa)(10) and
(11); and
■ kk. Revising paragraph (cc).
The revisions and additions read as
follows:
■
§ 98.236
Data reporting requirements.
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(a) The annual report must include
the information specified in paragraphs
(a)(1) through (10) of this section for
each applicable industry segment. The
annual report must also include annual
emissions totals, in metric tons of each
GHG, for each applicable industry
segment listed in paragraphs (a)(1)
through (10), and each applicable
emission source listed in paragraphs (b)
through (z) of this section.
*
*
*
*
*
(9) Onshore petroleum and natural
gas gathering and boosting. For the
equipment/activities specified in
paragraphs (a)(9)(i) through (xi) of this
section, report the information specified
in the applicable paragraphs of this
section.
(i) Natural gas pneumatic devices.
Report the information specified in
paragraph (b) of this section.
(ii) Natural gas driven pneumatic
pumps. Report the information specified
in paragraph (c) of this section.
(iii) Acid gas removal units. Report
the information specified in paragraph
(d) of this section.
(iv) Dehydrators. Report the
information specified in paragraph (e) of
this section.
(v) Blowdown vent stacks. Report the
information specified in paragraph (i) of
this section.
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(vi) Storage tanks. Report the
information specified in paragraph (j) of
this section.
(vii) Flare stacks. Report the
information specified in paragraph (n)
of this section.
(viii) Centrifugal compressors. Report
the information specified in paragraph
(o) of this section.
(ix) Reciprocating compressors.
Report the information specified in
paragraph (p) of this section.
(x) Equipment leaks by population
count. Report the information specified
in paragraph (r) of this section.
(xi) Combustion equipment. Report
the information specified in paragraph
(z) of this section.
(10) Onshore natural gas transmission
pipeline. For blowdown vent stacks,
report the information specified in
paragraph (i) of this section.
*
*
*
*
*
(d) * * *
(1) * * *
(i) A unique name or ID number for
the acid gas removal unit. For the
onshore petroleum and natural gas
production and the onshore petroleum
and natural gas gathering and boosting
industry segments, a different name or
ID may be used for a single acid gas
removal unit for each location it
operates at in a given year.
*
*
*
*
*
(vi) Sub-basin ID that best represents
the wells supplying gas to the unit (for
the onshore petroleum and natural gas
production industry segment only) or
name of the county that best represents
the equipment supplying gas to the unit
(for the onshore petroleum and natural
gas gathering and boosting industry
segment only).
*
*
*
*
*
(e) * * *
(1) * * *
(i) A unique name or ID number for
the dehydrator. For the onshore
petroleum and natural gas production
and the onshore petroleum and natural
gas gathering and boosting industry
segments, a different name or ID may be
used for a single dehydrator for each
location it operates at in a given year.
*
*
*
*
*
(xviii) Sub-basin ID that best
represents the wells supplying gas to the
dehydrator (for the onshore petroleum
and natural gas production industry
segment only) or name of the county
that best represents the equipment
supplying gas to the dehydrator (for the
onshore petroleum and natural gas
gathering and boosting industry segment
only).
*
*
*
*
*
(f) * * *
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(1) * * *
(ii) Well tubing diameter and pressure
group ID and a list of the well ID
numbers associated with each sub-basin
and well tubing diameter and pressure
group ID.
*
*
*
*
*
(xi) * * *
(A) Well ID number of tested well.
*
*
*
*
*
(xii) * * *
(A) Well ID number.
*
*
*
*
*
(2) * * *
(i) Sub-basin ID and a list of the well
ID numbers associated with each subbasin.
*
*
*
*
*
(g) Completions and workovers with
hydraulic fracturing. You must indicate
whether your facility had any well
completions or workovers with
hydraulic fracturing during the calendar
year. If your facility had well
completions or workovers with
hydraulic fracturing during the calendar
year, then you must report information
specified in paragraphs (g)(1) through
(10) of this section, for each sub-basin
and well type combination. Report
information separately for completions
and workovers.
(1) Sub-basin ID and a list of the well
ID numbers associated with each subbasin that had completions or
workovers with hydraulic fracturing
during the calendar year.
(2) Well type combination (horizontal
or vertical, gas well or oil well).
*
*
*
*
*
(5) If you used Equation W–10A of
§ 98.233 to calculate annual volumetric
total gas emissions, then you must
report the information specified in
paragraphs (g)(5)(i) through (iii) of this
section.
(i) Cumulative gas flowback time, in
hours, from when gas is first detected
until sufficient quantities are present to
enable separation, and the cumulative
flowback time, in hours, after sufficient
quantities of gas are present to enable
separation (sum of ‘‘Tp,i’’ and sum of
‘‘Tp,s’’ values used in Equation W–10A
of § 98.233). You may delay the
reporting of this data element if you
indicate in the annual report that
wildcat wells and/or delineation wells
are the only wells included in this
number. If you elect to delay reporting
of this data element, you must report by
the date specified in § 98.236(cc) the
total number of hours of flowback from
all wells during completions or
workovers and the well ID number(s) for
the well(s) included in the number.
(ii) For the measured well(s), the
flowback rate, in standard cubic feet per
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hour (average of ‘‘FRs,p’’ values used in
Equation W–12A of § 98.233), and the
well ID numbers of the wells for which
it is measured. You may delay the
reporting of this data element if you
indicate in the annual report that
wildcat wells and/or delineation wells
are the only wells that can be used for
the measurement. If you elect to delay
reporting of this data element, you must
report by the date specified in
§ 98.236(cc) the measured flowback rate
during well completion or workover and
the well ID number(s) for the well(s)
included in the measurement.
(iii) If you used Equation W–12C of
§ 98.233 to calculate the average gas
production rate for an oil well, then you
must report the information specified in
paragraphs (g)(5)(iii)(A) and (B) of this
section.
(A) Gas to oil ratio for the well in
standard cubic feet of gas per barrel of
oil (‘‘GORp’’ in Equation W–12C of
§ 98.233). You may delay the reporting
of this data element if you indicate in
the annual report that wildcat wells
and/or delineation wells are the only
wells that can be used for the
measurement. If you elect to delay
reporting of this data element, you must
report by the date specified in
§ 98.236(cc) the gas to oil ratio for the
well and the well ID number for the
well.
(B) Volume of oil produced during the
first 30 days of production after
completions of each newly drilled well
or well workover using hydraulic
fracturing, in barrels (‘‘Vp’’ in Equation
W–12C of § 98.233). You may delay the
reporting of this data element if you
indicate in the annual report that
wildcat wells and/or delineation wells
are the only wells that can be used for
the measurement. If you elect to delay
reporting of this data element, you must
report by the date specified in
§ 98.236(cc) the volume of oil produced
during the first 30 days of production
after well completion or workover and
the well ID number for the well.
(6) If you used Equation W–10B of
§ 98.233 to calculate annual volumetric
total gas emissions, then you must
report the information specified in
paragraphs (g)(6)(i) through (iii) of this
section.
(i) Vented natural gas volume, in
standard cubic feet, for each well in the
sub-basin (‘‘FVs,p’’ in Equation W–10B
of § 98.233).
(ii) Flow rate at the beginning of the
period of time when sufficient
quantities of gas are present to enable
separation, in standard cubic feet per
hour, for each well in the sub-basin
(‘‘FRp,i’’ in Equation W–10B of § 98.233).
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(iii) The well ID number for which
vented natural gas volume was
measured.
*
*
*
*
*
(h) * * *
(1) * * *
(i) Sub-basin ID and a list of the well
ID numbers associated with each subbasin for gas well completions without
hydraulic fracturing and without flaring.
*
*
*
*
*
(iv) Average daily gas production rate
for all completions without hydraulic
fracturing in the sub-basin without
flaring, in standard cubic feet per hour
(average of all ‘‘Vp’’ used in Equation
W–13B of § 98.233). You may delay
reporting of this data element if you
indicate in the annual report that
wildcat wells and/or delineation wells
are the only wells that can be used for
the measurement. If you elect to delay
reporting of this data element, you must
report by the date specified in
§ 98.236(cc) the measured average daily
gas production rate for all wells during
completions and the well ID number(s)
for the well(s) included in the
measurement.
*
*
*
*
*
(2) * * *
(i) Sub-basin ID and a list of the well
ID numbers associated with each subbasin for gas well completions without
hydraulic fracturing and with flaring.
*
*
*
*
*
(iv) Average daily gas production rate
for all completions without hydraulic
fracturing in the sub-basin with flaring,
in standard cubic feet per hour (the
average of all ‘‘Vp’’ from Equation W–
13B of § 98.233). You may delay
reporting of this data element if you
indicate in the annual report that
wildcat wells and/or delineation wells
are the only wells that can be used for
the measurement. If you elect to delay
reporting of this data element, you must
report by the date specified in
§ 98.236(cc) the measured average daily
gas production rate for all wells during
completions and the well ID number(s)
for the well(s) included in the
measurement.
*
*
*
*
*
(3) * * *
(i) Sub-basin ID and a list of the well
ID numbers associated with each subbasin for gas well workovers without
hydraulic fracturing and without flaring.
*
*
*
*
*
(4) * * *
(i) Sub-basin ID and a list of well ID
numbers associated with each sub-basin
for gas well workovers without
hydraulic fracturing and with flaring.
*
*
*
*
*
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(i) Blowdown vent stacks. You must
indicate whether your facility has
blowdown vent stacks. If your facility
has blowdown vent stacks, then you
must report whether emissions were
calculated by equipment or event type
or by using flow meters or a
combination of both. If you calculated
emissions by equipment or event type
for any blowdown vent stacks, then you
must report the information specified in
paragraph (i)(1) of this section
considering, in aggregate, all blowdown
vent stacks for which emissions were
calculated by equipment or event type.
If you calculated emissions using flow
meters for any blowdown vent stacks,
then you must report the information
specified in paragraph (i)(2) of this
section considering, in aggregate, all
blowdown vent stacks for which
emissions were calculated using flow
meters. For the onshore natural gas
transmission pipeline segment, you
must also report the information in
paragraph (i)(3) of this section.
(1) Report by equipment or event type.
If you calculated emissions from
blowdown vent stacks by the seven
categories listed in § 98.233(i)(2) for
industry segments other than the
onshore natural gas transmission
pipeline segment, then you must report
the equipment or event types and the
information specified in paragraphs
(i)(1)(i) through (iii) of this section for
each equipment or event type. If a
blowdown event resulted in emissions
from multiple equipment types, and the
emissions cannot be apportioned to the
different equipment types, then you
may report the information in
paragraphs (i)(1)(i) through (iii) of this
section for the equipment type that
represented the largest portion of the
emissions for the blowdown event. If
you calculated emissions from
blowdown vent stacks by the eight
categories listed in § 98.233(i)(2) for the
onshore natural gas transmission
pipeline segment, then you must report
the pipeline segments or event types
and the information specified in
paragraphs (i)(1)(i) through (iii) of this
section for each ‘‘equipment or event
type’’ (i.e., category). If a blowdown
event resulted in emissions from
multiple categories, and the emissions
cannot be apportioned to the different
categories, then you may report the
information in paragraphs (i)(1)(i)
through (iii) of this section for the
‘‘equipment or event type’’ (i.e.,
category) that represented the largest
portion of the emissions for the
blowdown event.
*
*
*
*
*
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(3) Onshore natural gas transmission
pipeline segment. Report the
information in paragraphs (i)(3)(i)
through (iii) of this section for each
state.
(i) Annual CO2 emissions in metric
tons CO2.
(ii) Annual CH4 emissions in metric
tons CH4.
(iii) Annual number of blowdown
events.
(j) Onshore production and onshore
petroleum and natural gas gathering
and boosting storage tanks. You must
indicate whether your facility sends
produced oil to atmospheric tanks. If
your facility sends produced oil to
atmospheric tanks, then you must
indicate which Calculation Method(s)
you used to calculate GHG emissions,
and you must report the information
specified in paragraphs (j)(1) and (2) of
this section as applicable. If you used
Calculation Method 1 or Calculation
Method 2 of § 98.233(j), and any
atmospheric tanks were observed to
have malfunctioning dump valves
during the calendar year, then you must
indicate that dump valves were
malfunctioning and you must report the
information specified in paragraph (j)(3)
of this section.
(1) If you used Calculation Method 1
or Calculation Method 2 of § 98.233(j) to
calculate GHG emissions, then you must
report the information specified in
paragraphs (j)(1)(i) through (xvi) of this
section for each sub-basin (for onshore
production) or county (for onshore
petroleum and natural gas gathering and
boosting) and by calculation method.
Onshore petroleum and natural gas
gathering and boosting facilities do not
report the information specified in
paragraphs (j)(1)(ix) and (xi) of this
section.
(i) Sub-basin ID (for onshore
production) or county name (for
onshore petroleum and natural gas
gathering and boosting).
*
*
*
*
*
(iii) The total annual oil volume from
gas-liquid separators and direct from
wells or non-separator equipment that is
sent to applicable onshore production
and onshore petroleum and natural gas
gathering and boosting storage tanks, in
barrels. You may delay reporting of this
data element for onshore production if
you indicate in the annual report that
wildcat wells and delineation wells are
the only wells in the sub-basin with oil
production greater than or equal to 10
barrels per day and flowing to gas-liquid
separators or direct to storage tanks. If
you elect to delay reporting of this data
element, you must report by the date
specified in § 98.236(cc) the total
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volume of oil from all wells and the
well ID number(s) for the well(s)
included in this volume.
(iv) The average gas-liquid separator
or non-separator equipment
temperature, in degrees Fahrenheit.
(v) The average gas-liquid separator or
non-separator equipment pressure, in
pounds per square inch gauge.
*
*
*
*
*
(vii) The minimum and maximum
concentration (mole fraction) of CO2 in
flash gas from onshore production and
onshore natural gas gathering and
boosting storage tanks.
(viii) The minimum and maximum
concentration (mole fraction) of CH4 in
flash gas from onshore production and
onshore natural gas gathering and
boosting storage tanks.
*
*
*
*
*
(2) * * *
(i) Report the information specified in
paragraphs (j)(2)(i)(A) through (F) of this
section, at the basin level, for
atmospheric tanks where emissions
were calculated using Calculation
Method 3 of § 98.233(j). Onshore
gathering and boosting facilities do not
report the information specified in
paragraphs (j)(2)(i)(E) and (F) of this
section.
(A) The total annual oil/condensate
throughput that is sent to all
atmospheric tanks in the basin, in
barrels. You may delay reporting of this
data element for onshore production if
you indicate in the annual report that
wildcat wells and delineation wells are
the only wells in the sub-basin with oil/
condensate production less than 10
barrels per day and that send oil/
condensate to atmospheric tanks. If you
elect to delay reporting of this data
element, you must report by the date
specified in § 98.236(cc) the total annual
oil/condensate throughput from all
wells and the well ID number(s) for the
well(s) included in this volume.
(B) An estimate of the fraction of oil/
condensate throughput reported in
paragraph (j)(2)(i)(A) of this section sent
to atmospheric tanks in the basin that
controlled emissions with flares.
(C) An estimate of the fraction of oil/
condensate throughput reported in
paragraph (j)(2)(i)(A) of this section sent
to atmospheric tanks in the basin that
controlled emissions with vapor
recovery systems.
*
*
*
*
*
(ii) Report the information specified
in paragraphs (j)(2)(ii)(A) through (D) of
this section for each sub-basin (for
onshore production) or county (for
onshore petroleum and natural gas
gathering and boosting) with
atmospheric tanks whose emissions
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Sfmt 4700
were calculated using Calculation
Method 3 of § 98.233(j) and that did not
control emissions with flares.
(A) Sub-basin ID (for onshore
production) or county name (for
onshore petroleum and natural gas
gathering and boosting).
(B) The number of atmospheric tanks
in the sub-basin (for onshore
production) or county (for onshore
petroleum and natural gas gathering and
boosting) that did not control emissions
with flares.
(C) Annual CO2 emissions, in metric
tons CO2, from atmospheric tanks in the
sub-basin (for onshore production) or
county (for onshore petroleum and
natural gas gathering and boosting) that
did not control emissions with flares,
calculated using Equation W–15 of
§ 98.233(j) and adjusted for vapor
recovery, if applicable.
(D) Annual CH4 emissions, in metric
tons CH4, from atmospheric tanks in the
sub-basin (for onshore production) or
county (for onshore petroleum and
natural gas gathering and boosting) that
did not control emissions with flares,
calculated using Equation W–15 of
§ 98.233(j) and adjusted for vapor
recovery, if applicable.
(iii) Report the information specified
in paragraphs (j)(2)(iii)(A) through (E) of
this section for each sub-basin (for
onshore production) or county (for
onshore petroleum and natural gas
gathering and boosting) with
atmospheric tanks whose emissions
were calculated using Calculation
Method 3 of § 98.233(j) and that
controlled emissions with flares.
(A) Sub-basin ID (for onshore
production) or county name (for
onshore petroleum and natural gas
gathering and boosting).
(B) The number of atmospheric tanks
in the sub-basin (for onshore
production) or county (for onshore
petroleum and natural gas gathering and
boosting) that controlled emissions with
flares.
*
*
*
*
*
(3) If you used Calculation Method 1
or Calculation Method 2 of § 98.233(j),
and any gas-liquid separator liquid
dump values did not close properly
during the calendar year, then you must
report the information specified in
paragraphs (j)(3)(i) through (iv) of this
section for each sub-basin (for onshore
production) or county (for onshore
petroleum and natural gas gathering and
boosting).
*
*
*
*
*
(l) * * *
(1) If you used Equation W–17A of
§ 98.233 to calculate annual volumetric
natural gas emissions at actual
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conditions from oil wells and the
emissions are not vented to a flare, then
you must report the information
specified in paragraphs (l)(1)(i) through
(vii) of this section.
*
*
*
*
*
(ii) Well ID numbers for the wells
tested in the calendar year.
*
*
*
*
*
(v) Average flow rate for well(s)
tested, in barrels of oil per day. You may
delay reporting of this data element if
you indicate in the annual report that
wildcat wells and/or delineation wells
are the only wells that are tested. If you
elect to delay reporting of this data
element, you must report by the date
specified in § 98.236(cc) the measured
average flow rate for well(s) tested and
the well ID number(s) for the well(s)
included in the measurement.
*
*
*
*
*
(2) If you used Equation W–17A of
§ 98.233 to calculate annual volumetric
natural gas emissions at actual
conditions from oil wells and the
emissions are vented to a flare, then you
must report the information specified in
paragraphs (l)(2)(i) through (viii) of this
section.
*
*
*
*
*
(ii) Well ID numbers for the wells
tested in the calendar year.
*
*
*
*
*
(v) Average flow rate for well(s)
tested, in barrels of oil per day. You may
delay reporting of this data element if
you indicate in the annual report that
wildcat wells and/or delineation wells
are the only wells that are tested. If you
elect to delay reporting of this data
element, you must report by the date
specified in § 98.236(cc) the measured
average flow rate for well(s) tested and
the well ID number(s) for the well(s)
included in the measurement.
*
*
*
*
*
(3) If you used Equation W–17B of
§ 98.233 to calculate annual volumetric
natural gas emissions at actual
conditions from gas wells and the
emissions were not vented to a flare,
then you must report the information
specified in paragraphs (l)(3)(i) through
(vi) of this section.
*
*
*
*
*
(ii) Well ID numbers for the wells
tested in the calendar year.
*
*
*
*
*
(iv) Average annual production rate
for well(s) tested, in actual cubic feet
per day. You may delay reporting of this
data element if you indicate in the
annual report that wildcat wells and/or
delineation wells are the only wells that
are tested. If you elect to delay reporting
of this data element, you must report by
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the date specified in § 98.236(cc) the
measured average annual production
rate for well(s) tested and the well ID
number(s) for the well(s) included in the
measurement.
*
*
*
*
*
(4) If you used Equation W–17B of
§ 98.233 to calculate annual volumetric
natural gas emissions at actual
conditions from gas wells and the
emissions were vented to a flare, then
you must report the information
specified in paragraphs (l)(4)(i) through
(vii) of this section.
*
*
*
*
*
(ii) Well ID numbers for the wells
tested in the calendar year.
*
*
*
*
*
(iv) Average annual production rate
for well(s) tested, in actual cubic feet
per day. You may delay reporting of this
data element if you indicate in the
annual report that wildcat wells and/or
delineation wells are the only wells that
are tested. If you elect to delay reporting
of this data element, you must report by
the date specified in § 98.236(cc) the
measured average annual production
rate for well(s) tested and the well ID
number(s) for the well(s) included in the
measurement.
*
*
*
*
*
(m) * * *
(1) Sub-basin ID and a list of well ID
numbers for wells for which associated
gas was vented or flared.
*
*
*
*
*
(5) Volume of oil produced, in barrels,
in the calendar year during the time
periods in which associated gas was
vented or flared (the sum of ‘‘Vp,q’’ used
in Equation W–18 of § 98.233). You may
delay reporting of this data element if
you indicate in the annual report that
wildcat wells and/or delineation wells
are the only wells from which
associated gas was vented or flared. If
you elect to delay reporting of this data
element, you must report by the date
specified in § 98.236(cc) the volume of
oil produced for well(s) with associated
gas venting and flaring and the well ID
number(s) for the well(s) included in the
measurement.
(6) Total volume of associated gas sent
to sales, in standard cubic feet, in the
calendar year during time periods in
which associated gas was vented or
flared (the sum of ‘‘SG’’ values used in
Equation W–18 of § 98.233(m)). You
may delay reporting of this data element
if you indicate in the annual report that
wildcat wells and/or delineation wells
from which associated gas was vented
or flared. If you elect to delay reporting
of this data element, you must report by
the date specified in § 98.236(cc) the
measured total volume of associated gas
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64295
sent to sales for well(s) with associated
gas venting and flaring and the well ID
number(s) for the well(s) included in the
measurement.
(7) * * *
(i) Total number of wells for which
associated gas was vented directly to the
atmosphere without flaring and a list of
their well ID numbers.
*
*
*
*
*
(8) * * *
(i) Total number of wells for which
associated gas was flared and a list of
their well ID numbers.
*
*
*
*
*
(n) * * *
(1) Unique name or ID for the flare
stack. For the onshore petroleum and
natural gas production and onshore
petroleum and natural gas gathering and
boosting industry segments, a different
name or ID may be used for a single
flare stack for each location where it
operates at in a given calendar year.
*
*
*
*
*
(o) Centrifugal compressors. You must
indicate whether your facility has
centrifugal compressors. You must
report the information specified in
paragraphs (o)(1) and (2) of this section
for all centrifugal compressors at your
facility. For each compressor source or
manifolded group of compressor sources
that you conduct as found leak
measurements as specified in
§ 98.233(o)(2) or (4), you must report the
information specified in paragraph
(o)(3) of this section. For each
compressor source or manifolded group
of compressor sources that you conduct
continuous monitoring as specified in
§ 98.233(o)(3) or (5), you must report the
information specified in paragraph
(o)(4) of this section. Centrifugal
compressors in onshore petroleum and
natural gas production and onshore
petroleum and natural gas gathering and
boosting are not required to report
information in paragraphs (o)(1) through
(4) of this section and instead must
report the information specified in
paragraph (o)(5) of this section.
*
*
*
*
*
(5) Onshore petroleum and natural
gas production and onshore petroleum
and natural gas gathering and boosting.
Centrifugal compressors with wet seal
degassing vents in onshore petroleum
and natural gas production and onshore
petroleum and natural gas gathering and
boosting must report the information
specified in paragraphs (o)(5)(i) through
(iii) of this section.
*
*
*
*
*
(p) Reciprocating compressors. You
must indicate whether your facility has
reciprocating compressors. You must
report the information specified in
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paragraphs (p)(1) and (2) of this section
for all reciprocating compressors at your
facility. For each compressor source or
manifolded group of compressor sources
that you conduct as found leak
measurements as specified in
§ 98.233(p)(2) or (4), you must report the
information specified in paragraph
(p)(3) of this section. For each
compressor source or manifolded group
of compressor sources that you conduct
continuous monitoring as specified in
§ 98.233(p)(3) or (5), you must report the
information specified in paragraph
(p)(4) of this section. Reciprocating
compressors in onshore petroleum and
natural gas production and onshore
petroleum and natural gas gathering and
boosting are not required to report
information in paragraphs (p)(1) through
(4) of this section and instead must
report the information specified in
paragraph (p)(5) of this section.
*
*
*
*
*
(5) Onshore petroleum and natural
gas production and onshore petroleum
and natural gas gathering and boosting.
Reciprocating compressors in onshore
petroleum and natural gas production
and onshore petroleum and natural gas
gathering and boosting must report the
information specified in paragraphs
(p)(5)(i) through (iii) of this section.
*
*
*
*
*
(r) * * *
(1) You must indicate whether your
facility contains any of the emission
source types required to use Equation
W–32A of § 98.233. You must report the
information specified in paragraphs
(r)(1)(i) through (v) of this section
separately for each emission source type
required to use Equation W–32A that is
located at your facility. Onshore
petroleum and natural gas production
facilities and onshore petroleum and
natural gas gathering and boosting
facilities must report the information
specified in paragraphs (r)(1)(i) through
(v) separately by component type,
service type, and geographic location
(i.e., Eastern U.S. or Western U.S.).
(i) Emission source type. Onshore
petroleum and natural gas production
facilities and onshore petroleum and
natural gas gathering and boosting
facilities must report the component
type, service type and geographic
location.
*
*
*
*
*
(3) Onshore petroleum and natural gas
production facilities and onshore
petroleum and natural gas gathering and
boosting facilities must also report the
information specified in paragraphs
(r)(3)(i) and (ii) of this section.
*
*
*
*
*
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(ii) Onshore petroleum and natural
gas production facilities and onshore
petroleum and natural gas gathering and
boosting facilities must report the
information specified in paragraphs
(r)(3)(ii)(A) and (B) of this section, for
each major equipment type, production
type (i.e., natural gas or crude oil), and
geographic location combination in
Tables W–1B and W–1C of this subpart.
*
*
*
*
*
(z) Combustion equipment at onshore
petroleum and natural gas production
facilities, onshore petroleum and
natural gas gathering and boosting
facilities, and natural gas distribution
facilities. If your facility is required by
§ 98.232(c)(22), (i)(7), or (j)(12) to report
emissions from combustion equipment,
then you must indicate whether your
facility has any combustion units
subject to reporting according to
paragraph (a)(1)(xvii), (a)(8)(i), or
(a)(9)(xi) of this section. If your facility
contains any combustion units subject
to reporting according to paragraph
(a)(1)(xvii), (a)(8)(i), or (a)(9)(xi) of this
section, then you must report the
information specified in paragraphs
(z)(1) and (2) of this section, as
applicable.
*
*
*
*
*
(aa) Each facility must report the
information specified in paragraphs
(aa)(1) through (11) of this section, for
each applicable industry segment, by
using best available data. If a quantity
required to be reported is zero, you must
report zero as the value.
(1) * * *
(ii) * * *
(D) The number of producing wells at
the end of the calendar year and a list
of the well ID numbers (exclude only
those wells permanently taken out of
production, i.e., plugged and
abandoned).
(E) The number of producing wells
acquired during the calendar year and a
list of the well ID numbers.
(F) The number of producing wells
divested during the calendar year and a
list of the well ID numbers.
(G) The number of wells completed
during the calendar year and a list of the
well ID numbers.
(H) The number of wells permanently
taken out of production (i.e., plugged
and abandoned) during the calendar
year and a list of the well ID numbers.
*
*
*
*
*
(10) For onshore petroleum and
natural gas gathering and boosting
facilities, report the quantities specified
in paragraphs (aa)(10)(i) through (iv) of
this section.
(i) The quantity of gas received by the
gathering and boosting facility in the
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calendar year, in thousand standard
cubic feet.
(ii) The quantity of gas transported to
a natural gas processing facility, a
natural gas transmission pipeline, a
natural gas distribution pipeline, or
another gathering and boosting facility
in the calendar year, in thousand
standard cubic feet.
(iii) The quantity of all hydrocarbon
liquids received by the gathering and
boosting facility in the calendar year, in
barrels.
(iv) The quantity of all hydrocarbon
liquids transported to a natural gas
processing facility, a natural gas
transmission pipeline, a natural gas
distribution pipeline, or another
gathering and boosting facility in the
calendar year, in barrels.
(11) For onshore natural gas
transmission pipeline facilities, report
the quantities specified in paragraphs
(aa)(11)(i) through (vi) of this section.
(i) The quantity of natural gas
received at all custody transfer stations
in the calendar year, in thousand
standard cubic feet. This value may
include meter corrections, but only for
the calendar year covered by the annual
report.
(ii) The quantity of natural gas
withdrawn from in-system storage in the
calendar year, in thousand standard
cubic feet.
(iii) The quantity of natural gas added
to in-system storage in the calendar
year, in thousand standard cubic feet.
(iv) The quantity of natural gas
transferred to third parties such as LDCs
or other transmission pipelines, in
thousand standard cubic feet.
(v) The quantity of natural gas
consumed by the transmission pipeline
facility for operational purposes, in
thousand standard cubic feet.
(vi) The miles of transmission
pipeline for each state in the facility.
*
*
*
*
*
(cc) If you elect to delay reporting the
information in paragraph (g)(5)(i),
(g)(5)(ii), (g)(5)(iii)(A), (g)(5)(iii)(B),
(h)(1)(iv), (h)(2)(iv), (j)(1)(iii), (j)(2)(i)(A),
(l)(1)(iv), (l)(2)(iv), (l)(3)(iii), (l)(4)(iii),
(m)(5), or (m)(6) of this section, you
must report the information required in
that paragraph no later than the date 2
years following the date specified in
§ 98.3(b) introductory text.
■ 8. Section 98.238 is amended by
adding definitions for ‘‘Facility with
respect to onshore petroleum and
natural gas gathering and boosting for
purposes of reporting under this subpart
and for the corresponding subpart A
requirements,’’ ‘‘Facility with respect to
the onshore natural gas transmission
pipeline segment,’’ ‘‘Gathering and
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boosting system,’’ ‘‘Gathering and
boosting system owner or operator,’’
‘‘Onshore natural gas transmission
pipeline owner or operator,’’ and ‘‘Well
identification (ID) number’’ in
alphabetical order to read as follows:
§ 98.238
Definitions.
*
*
*
*
*
Facility with respect to onshore
petroleum and natural gas gathering
and boosting for purposes of reporting
under this subpart and for the
corresponding subpart A requirements
means all gathering pipelines and other
equipment located along those pipelines
that are under common ownership or
common control by a gathering and
boosting system owner or operator and
that are located in a single hydrocarbon
basin as defined in this section. Where
a person owns or operates more than
one gathering and boosting system in a
basin (for example, separate gathering
lines that are not connected), then all
gathering and boosting equipment that
the person owns or operates in the basin
would be considered one facility. Any
gathering and boosting equipment that
is associated with a single gathering and
boosting system, including leased,
rented, or contracted activities, is
considered to be under common control
of the owner or operator of the gathering
and boosting system that contains the
pipeline. The facility does not include
equipment and pipelines that are part of
any other industry segment defined in
this subpart.
*
*
*
*
*
Facility with respect to the onshore
natural gas transmission pipeline
segment means the total U.S. mileage of
natural gas transmission pipelines, as
defined in this section, owned and
operated by an onshore natural gas
transmission pipeline owner or operator
as defined in this section. The facility
does not include pipelines that are part
of any other industry segment defined
in this subpart.
*
*
*
*
*
Gathering and boosting system means
a single network of pipelines,
compressors and process equipment,
including equipment to perform natural
gas compression, dehydration, and acid
gas removal, that has one or more
connection points to gas and oil
production and a downstream endpoint,
typically a gas processing plant,
transmission pipeline, LDC pipeline, or
other gathering and boosting system.
Gathering and boosting system owner
or operator means any person that holds
a contract in which they agree to
transport petroleum or natural gas from
one or more onshore petroleum and
natural gas production wells to a natural
gas processing facility, another
gathering and boosting system, a natural
gas transmission pipeline, or a
distribution pipeline, or any person
responsible for custody of the petroleum
or natural gas transported.
*
*
*
*
*
Onshore natural gas transmission
pipeline owner or operator means, for
interstate pipelines, the person
64297
identified as the transmission pipeline
owner or operator on the Certificate of
Public Convenience and Necessity
issued under 15 U.S.C. 717f, or, for
intrastate pipelines, the person
identified as the owner or operator on
the transmission pipeline’s Statement of
Operating Conditions under section 311
of the Natural Gas Policy Act, or for
pipelines that fall under the ‘‘Hinshaw
Exemption’’ as referenced in section 1(c)
of the Natural Gas Act, 15 U.S.C. 717–
717 (w)(1994), the person identified as
the owner or operator on blanket
certificates issued under 18 CFR
284.224. If an intrastate pipeline is not
subject to section 311 of the Natural Gas
Policy Act (NGPA), the onshore natural
gas transmission pipeline owner or
operator is the person identified as the
owner or operator on reports to the state
regulatory body regulating rates and
charges for the sale of natural gas to
consumers.
*
*
*
*
*
Well identification (ID) number means
the unique and permanent identification
number assigned to a petroleum or
natural gas well. If the well has been
assigned a US Well Number, the well ID
number required in this subpart is the
US Well Number. If a US Well Number
has not been assigned to the well, the
well ID number is the identifier
established by the well’s permitting
authority.
*
*
*
*
*
■ 9. Revise Table W–1A of subpart W of
part 98 to read as follows:
TABLE W–1A TO SUBPART W OF PART 98—DEFAULT WHOLE GAS EMISSION FACTORS FOR ONSHORE PETROLEUM AND
NATURAL GAS PRODUCTION FACILITIES AND ONSHORE PETROLEUM AND NATURAL GAS GATHERING AND BOOSTING
FACILITIES
Onshore petroleum and natural gas production and Onshore petroleum and natural gas gathering and boosting
Emission factor
(scf/hour/component)
Eastern U.S.
Population Emission Factors—All Components, Gas Service 1
Valve ....................................................................................................................................................................................
Connector ............................................................................................................................................................................
Open-ended Line .................................................................................................................................................................
Pressure Relief Valve ..........................................................................................................................................................
Low Continuous Bleed Pneumatic Device Vents 2 ..............................................................................................................
High Continuous Bleed Pneumatic Device Vents 2 .............................................................................................................
Intermittent Bleed Pneumatic Device Vents 2 ......................................................................................................................
Pneumatic Pumps 3 .............................................................................................................................................................
0.027
0.003
0.061
0.040
1.39
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Population Emission Factors—All Components, Light Crude Service 4
Valve ....................................................................................................................................................................................
Flange ..................................................................................................................................................................................
Connector ............................................................................................................................................................................
Open-ended Line .................................................................................................................................................................
Pump ....................................................................................................................................................................................
Other 5 ..................................................................................................................................................................................
0.05
0.003
0.007
0.05
0.01
0.30
Population Emission Factors—All Components, Heavy Crude Service 6
Valve ....................................................................................................................................................................................
Flange ..................................................................................................................................................................................
Connector (other) .................................................................................................................................................................
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0.0009
0.0003
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TABLE W–1A TO SUBPART W OF PART 98—DEFAULT WHOLE GAS EMISSION FACTORS FOR ONSHORE PETROLEUM AND
NATURAL GAS PRODUCTION FACILITIES AND ONSHORE PETROLEUM AND NATURAL GAS GATHERING AND BOOSTING
FACILITIES—Continued
Onshore petroleum and natural gas production and Onshore petroleum and natural gas gathering and boosting
Open-ended Line .................................................................................................................................................................
Other 5 ..................................................................................................................................................................................
Emission factor
(scf/hour/component)
0.006
0.003
Population Emission Factors—Gathering Pipelines, by Material Type 7
Protected Steel ....................................................................................................................................................................
Unprotected Steel ................................................................................................................................................................
Plastic/Composite ................................................................................................................................................................
Cast Iron ..............................................................................................................................................................................
0.47
16.59
2.50
27.60
Western U.S.
Population Emission Factors—All Components, Gas Service 1
Valve ....................................................................................................................................................................................
Connector ............................................................................................................................................................................
Open-ended Line .................................................................................................................................................................
Pressure Relief Valve ..........................................................................................................................................................
Low Continuous Bleed Pneumatic Device Vents 2 ..............................................................................................................
High Continuous Bleed Pneumatic Device Vents 2 .............................................................................................................
Intermittent Bleed Pneumatic Device Vents 2 ......................................................................................................................
Pneumatic Pumps 3 .............................................................................................................................................................
0.121
0.017
0.031
0.193
1.39
37.3
13.5
13.3
Population Emission Factors—All Components, Light Crude Service 4
Valve ....................................................................................................................................................................................
Flange ..................................................................................................................................................................................
Connector (other) .................................................................................................................................................................
Open-ended Line .................................................................................................................................................................
Pump ....................................................................................................................................................................................
Other 5 ..................................................................................................................................................................................
0.05
0.003
0.007
0.05
0.01
0.30
Population Emission Factors—All Components, Heavy Crude Service 6
Valve ....................................................................................................................................................................................
Flange ..................................................................................................................................................................................
Connector (other) .................................................................................................................................................................
Open-ended Line .................................................................................................................................................................
Other 5 ..................................................................................................................................................................................
0.0005
0.0009
0.0003
0.006
0.003
Population Emission Factors—Gathering Pipelines by Material Type 7
Protected Steel ....................................................................................................................................................................
Unprotected Steel ................................................................................................................................................................
Plastic/Composite ................................................................................................................................................................
Cast Iron ..............................................................................................................................................................................
0.47
16.59
2.50
27.60
1 For
multi-phase flow that includes gas, use the gas service emissions factors.
Factor is in units of ‘‘scf/hour/device.’’
Factor is in units of ‘‘scf/hour/pump.’’
4 Hydrocarbon liquids greater than or equal to 20°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°API are considered ‘‘heavy crude.’’
7 Emission factors are in units of ‘‘scf/hour/mile of pipeline.’’
2 Emission
3 Emission
10. Amend Table W–1B of subpart W
of part 98 by revising the table heading
to read as follows:
tkelley on DSK3SPTVN1PROD with RULES3
■
VerDate Sep<11>2014
20:55 Oct 21, 2015
Jkt 238001
*
*
*
*
TABLE W–1B TO SUBPART W OF PART *
98—DEFAULT AVERAGE COMPO- [FR Doc. 2015–25840 Filed 10–21–15; 08:45 am]
NENT COUNTS FOR MAJOR ON- BILLING CODE 6560–50–P
SHORE NATURAL GAS PRODUCTION
EQUIPMENT AND ONSHORE PETROLEUM AND NATURAL GAS GATHERING AND BOOSTING EQUIPMENT
PO 00000
Frm 00038
Fmt 4701
Sfmt 9990
E:\FR\FM\22OCR3.SGM
22OCR3
]]>Agencies
[Federal Register Volume 80, Number 204 (Thursday, October 22, 2015)]
[Rules and Regulations]
[Pages 64261-64298]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-25840]
[[Page 64261]]
Vol. 80
Thursday,
No. 204
October 22, 2015
Part V
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Part 98
Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems; Final Rule
Federal Register / Vol. 80 , No. 204 / Thursday, October 22, 2015 /
Rules and Regulations
[[Page 64262]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 98
[EPA-HQ-OAR-2014-0831; FRL-9935-50-OAR]
RIN 2060-AS37
Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: The Environmental Protection Agency (EPA) is finalizing
revisions and confidentiality determinations for the petroleum and
natural gas systems source category of the Greenhouse Gas Reporting
Rule. These revisions include the addition of calculation methods and
reporting requirements for greenhouse gas (GHG) emissions from
gathering and boosting facilities, completions and workovers of oil
wells with hydraulic fracturing, and blowdowns of natural gas
transmission pipelines between compressor stations. The revisions also
include the addition of well identification reporting requirements to
improve the EPA's ability to verify reported data and enhance
transparency. This action also finalizes confidentiality determinations
for new data elements contained in these amendments.
DATES: This final rule is effective on January 1, 2016.
ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2014-0831. All documents in the docket are
listed on the https://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 electronically through https://www.regulations.gov.
FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division,
Office of Atmospheric Programs (MC-6207A), Environmental Protection
Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone
number: (202) 343-9263; fax number: (202) 343-2342; email address:
GHGReportingRule@epa.gov. For technical information, please go to the
Greenhouse Gas Reporting Rule Web site, https://www.epa.gov/ghgreporting/. To submit a question, select Help Center, followed by
``Contact Us.''
Worldwide Web (WWW). In addition to being available in the docket,
an electronic copy of this final rule will also be available through
the WWW. Following the Administrator's signature, a copy of this action
will be posted on the EPA's Greenhouse Gas Reporting Rule Web site at
https://www.epa.gov/ghgreporting/.
SUPPLEMENTARY INFORMATION:
Regulated Entities. This final rule adds calculation methods,
monitoring, and data reporting requirements and finalizes
confidentiality determinations for the petroleum and natural gas
systems source category of the Greenhouse Gas Reporting Rule (40 CFR
part 98). The Administrator determined that 40 CFR part 98 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''). Entities affected
by this final rule are owners and operators of petroleum and natural
gas systems that directly emit GHGs, which include those listed in
Table 1 of this preamble:
Table 1--Examples of Affected Entities by Category
------------------------------------------------------------------------
Examples of affected
Category NAICS \a\ facilities
------------------------------------------------------------------------
Petroleum and Natural Gas Systems. 211111 Crude petroleum and
natural gas
extraction.
211112 Natural gas liquid
extraction.
221210 Natural gas
distribution.
486210 Pipeline
transportation of
natural gas.
------------------------------------------------------------------------
\a\ North American Industry Classification System.
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. Types of facilities other than those 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 and 40
CFR part 98, subpart W. If you have questions regarding the
applicability of this action to a particular facility, consult the
person listed in the preceding FOR FURTHER INFORMATION CONTACT section.
What is the effective date? The final rule is effective on January
1, 2016.
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 (the
Court) by December 21, 2015. 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. Section 307(d)(7)(B) of the CAA also provides a
mechanism for the EPA to convene a proceeding for reconsideration,
``[i]f the person raising an objection can demonstrate to the 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
the 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, William
Jefferson Clinton Building, 1200 Pennsylvania Ave. NW., Washington, DC
20460, 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 that 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 the EPA to
enforce these requirements.
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
AGR acid gas removal
[[Page 64263]]
API American Petroleum Institute
BAMM best available monitoring methods
CAA Clean Air Act
CBI confidential business information
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e carbon dioxide equivalent
e-GGRT Electronic Greenhouse Gas Reporting Tool
EPA U.S. Environmental Protection Agency
FERC Federal Energy Regulatory Commission
FR Federal Register
ft\3\ cubic feet
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GOR gas to oil ratio
GRI Gas Research Institute
ICR information collection request
ID identification
LDC local distribution company
N2O nitrous oxide
NAICS North American Industry Classification System
NGO non-government organization
NGPA Natural Gas Policy Act
NTTAA National Technology Transfer and Advancement Act
O&M operation and maintenance
OMB Office of Management and Budget
PHMSA Pipeline and Hazardous Materials Safety Administration
psi/ft pounds per square inch per foot
REC reduced emissions completion
RFA Regulatory Flexibility Act
scf standard cubic feet
scf/STB standard cubic feet per stock tank barrel
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
WWW worldwide web
Organization of This Document. The following outline is provided to
aid in locating information in this preamble.
I. Background
A. Organization of This Preamble
B. Background on This Action
C. Legal Authority
D. How do these amendments apply to 2015 and 2016 reports?
II. Summary of Final Revisions and Other Amendments to Subpart W and
Responses to Public Comment
A. Summary of Final Amendments for Oil Wells With Hydraulic
Fracturing
B. Summary of Final Amendments for the Onshore Petroleum and
Natural Gas Gathering and Boosting Segment
C. Summary of Final Amendments for the Onshore Natural Gas
Transmission Pipeline Segment
D. Summary of Final Amendments for Well Identification Numbers
E. Summary of Final Amendments to Best Available Monitoring
Methods
III. Final Confidentiality Determinations
A. Summary of Final Confidentiality Determinations for New
Subpart W Data Elements
B. Summary of Public Comments and Responses on the Proposed
Confidentiality Determinations
IV. Impacts of the Final Amendments to Subpart W
A. Impacts of the Final Amendments
B. Summary of Comments and Responses on the Impacts of the
Proposed Rule
V. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations 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
Section I of this preamble provides background information
regarding the origin of the final amendments. This section also
discusses the EPA's legal authority under the CAA to promulgate and
amend 40 CFR part 98 of the Greenhouse Gas Reporting Rule (hereafter
referred to as ``part 98'') as well as the legal authority for making
confidentiality determinations for the data to be reported. Section II
of this preamble contains information on the final amendments to part
98, subpart W (Petroleum and Natural Gas Systems) (hereafter referred
to as ``subpart W''), including a summary of the major comments that
the EPA considered in the development of this final rule. Section III
of this preamble discusses the final confidentiality determinations for
new data reporting elements. Section IV of this preamble discusses the
impacts of the final amendments to subpart W. Finally, Section V of
this preamble describes the statutory and executive order requirements
applicable to this action.
B. Background on This Action
The EPA's Greenhouse Gas Reporting Program (GHGRP) requires annual
reporting of GHG data and other relevant information from large sources
and suppliers in the United States. On October 30, 2009, the EPA
published part 98 for collecting information regarding GHG emissions
from a broad range of industry sectors (74 FR 56260). Although
reporting requirements for petroleum and natural gas systems were
originally proposed to be part of part 98 (75 FR 16448; April 10,
2009), the final October 2009 rule did not include the petroleum and
natural gas systems source category as one of the 29 source categories
for which reporting requirements were finalized. The EPA re-proposed
subpart W in 2010 (79 FR 18608; April 12, 2010), and a subsequent final
rule was published on November 30, 2010, with the requirements for the
petroleum and natural gas systems source category at 40 CFR part 98,
subpart W (75 FR 74458) (hereafter referred to as ``the final subpart W
rule''). Following promulgation, the EPA finalized actions revising
subpart W (76 FR 22825, April 25, 2011; 76 FR 59533, September 27,
2011; 76 FR 80554, December 23, 2011; 77 FR 51477, August 24, 2012; 78
FR 25392, May 1, 2013; 78 FR 71904, November 29, 2013; 79 FR 63750,
October 24, 2014; 79 FR 70352, November 25, 2014).
On December 9, 2014, the EPA proposed ``2015 Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems''
(79 FR 76267) to require the reporting of GHG emissions from several
sources that had not previously been included in subpart W. These
sources include completions and workovers of oil wells with hydraulic
fracturing, petroleum and natural gas gathering and boosting systems,
and transmission pipeline blowdowns between compressor stations. The
reporting requirements for completions and workovers of oil wells with
hydraulic fracturing were proposed to be included as part of the
existing Onshore Petroleum and Natural Gas Production industry segment.
For the other sources, the EPA proposed two new industry segments: The
Onshore Petroleum and Natural Gas Gathering and Boosting segment for
petroleum and natural gas gathering and boosting facilities, and the
Onshore Natural Gas Transmission Pipeline segment for transmission
pipeline blowdowns between compressor stations. The EPA also proposed
to require the reporting of a well identification number for oil and
gas wells covered in the Onshore Petroleum and Natural Gas Production
segment. In addition, the EPA proposed confidentiality determinations
for new data elements contained in the proposed amendments. The public
comment period for these proposed rule amendments ended on February 24,
2015, following a 2-week extension of the original comment period end
date (80 FR 6495; February 5, 2015).
[[Page 64264]]
In this action, the EPA is finalizing additions and revisions to
the subpart W calculation, monitoring, and reporting requirements for
new sources, with some changes made in response to public comments.
Responses to comments submitted on the proposed amendments can be found
in sections II, III, and IV of this preamble as well as in ``Response
to Public Comments on Greenhouse Gas Reporting Rule: 2015 Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems''
in Docket ID No. EPA-HQ-OAR-2014-0831. As noted in the preamble to the
proposed amendments (79 FR 73148; December 9, 2014), these additions
and revisions further the EPA's goals of improving the completeness,
quality, accuracy, and transparency of data from this sector, and
improving the ability of agencies and the public to use these GHG data
to analyze emissions and understand emission trends.
The Strategy to Reduce Methane Emissions in the President's Climate
Action Plan summarizes the sources of methane (CH4)
emissions, commits to new steps to cut emissions of this potent GHG,
and outlines the Administration's efforts to improve the measurement of
these emissions. The strategy builds on progress to date and takes
steps to further cut CH4 emissions from several sectors,
including the oil and natural gas sector. In the strategy, the EPA was
tasked to review regulatory requirements to address potential gaps in
coverage, improve methods, and help ensure high quality data
reporting.\1\ The final revisions to subpart W covered in this action
are responsive to this task by addressing data gaps in subpart W,
specifying methods for measuring CH4 emissions, and
providing data that can be used to further analyze CH4
emissions in this industry.
---------------------------------------------------------------------------
\1\ Climate Action Plan--Strategy to Reduce Methane Emissions.
The White House, Washington, DC, March 2014. Available at https://www.whitehouse.gov/sites/default/files/strategy_to_reduce_methane_emissions_2014-03-28_final.pdf.
---------------------------------------------------------------------------
This action also addresses a petition the EPA received from a group
of non-government organizations (NGOs) requesting that the EPA collect
data from emissions sources not currently included in subpart W,
including well completion emissions from oil wells that co-produce
natural gas, facilities and pipelines in the gathering and boosting
segment, and transmission pipeline blowdown events (``Petition for
Rulemaking'').\2\ Table 2 of this preamble summarizes how the EPA has
responded to the Petition for Rulemaking. These revisions, and
previously finalized revisions where noted in Table 2, reflect the
EPA's complete response to the Petition for Rulemaking. It is our
position that we have fully responded to the NGO petition, however, any
requests included in the petition that have not been responded to in
Table 2 are considered denied.
---------------------------------------------------------------------------
\2\ Petition for Rulemaking and Interpretive Guidance Ensuring
Comprehensive Coverage of Methane Sources Under Subpart W of the
Greenhouse Gas Reporting Rule--Petroleum And Natural Gas Systems;
Submitted by Clean Air Task Force, Environmental Defense Fund,
Natural Resources Defense Council, and Sierra Club; March 19, 2013.
Docket Item No. EPA-HQ-OAR-2014-0831-0005.
Table 2--EPA Response to Petition for Rulemaking
------------------------------------------------------------------------
Final rule
Request in petition EPA's response citations (40
CFR)
------------------------------------------------------------------------
Clarify that oil wells that co- The EPA is not 98.232(c)(6)
produce natural gas (``co- changing the 98.232(c)(8)
producing wells''), definition of ``gas 98.236(g)
specifically wells in tight- well'' or ``oil
oil formations like the well.'' Instead, the
Bakken and Eagle Ford, are EPA is amending
subject to the completion subpart W to require
reporting requirements as the reporting of GHG
currently written. Expand the emissions from
well completion reporting completions and
requirements to all wells, workovers with
ensuring co-producing wells hydraulic fracturing
in any formation type are for wells in the
required to report completion Onshore Petroleum
emissions. and Natural Gas
Production segment,
regardless of
whether their
primary product is
oil or natural gas.
Require reporting from The EPA is finalizing 98.230(a)(9)
facilities and pipelines in the proposal to 98.232(j)
the gathering and boosting amend subpart W to 98.233 (various)
segment of the natural gas add a new industry 98.236(a)(9)
industry. segment, Onshore
Petroleum and
Natural Gas
Gathering and
Boosting, which
covers emissions
from equipment used
by gathering
pipeline systems
that move petroleum
and natural gas from
the well to either
larger gathering
pipeline systems,
natural gas
processing plants,
natural gas
transmission
pipelines, or
natural gas
distribution
pipelines.
Require reporting from The EPA is finalizing 98.230(a)(10)
transmission pipeline the proposal to add 98.232(m)
blowdown events. reporting 98.236(aa)(11)
requirements for
emissions from
natural gas
transmission
pipeline blowdowns
between compressor
stations in a new
Onshore Natural Gas
Transmission
Pipeline segment.
Require reporters to include The EPA is requiring 98.236(f), (g),
API well identification the reporting of (h), (l), and
numbers along with their well identification (m)
submissions to help the numbers for the 98.238
public and policymakers Onshore Petroleum
understand which sources are and Natural Gas
reporting and how the Production segment
threshold may be adjusted to for information
most effectively provide related specifically
emissions information. to wells.
Phase out the use of best Prior to these 98.234(f) and (g)
available monitoring methods amendments, BAMM was
(BAMM), which will further discontinued for all
help to ensure Subpart W data sources except
are rigorous, and specific sources
comprehensive. that were affected
by the amendments
finalized on
November 25, 2014
(79 FR 70352); those
BAMM provisions will
be unavailable after
December 31, 2015.
Reporters will be
allowed to use BAMM
for the 2016
reporting year for
only the new
industry segments
and emission sources
included in this
action. The EPA is
not allowing the use
of BAMM beyond 2016.
[[Page 64265]]
Consider including advanced The agency is .................
innovative monitoring methods assessing the
as a way to accelerate potential
development and deployment of opportunities for
real-time continuous CH4 application of
emission monitoring in the remote sensing
oil and natural gas sector. technologies and
other innovations in
measurement or
monitoring
technology to
identifying and
calculating
emissions from
affected sources
under subpart W and
requested comment in
the proposal. The
EPA received
multiple comments in
response to the
request for comments
on the feasibility,
possible regulatory
approaches, and
provisions necessary
to incorporate or
allow the use of
advanced measurement
or monitoring
methods in subpart
W. All of the
comments received
are included in
``Response to Public
Comments on
Greenhouse Gas
Reporting Rule: 2015
Revisions and
Confidentiality
Determinations for
Petroleum and
Natural Gas
Systems'' in Docket
ID No. EPA-HQ-OAR-
2014-0831. The EPA
is not including
provisions related
to advanced
measurement or
monitoring methods
in this rule and is
not responding to
these comments in
this rulemaking.
Instead, following
review of the data
and information
received in
comments, the EPA
may propose
amendments related
to the use of
innovative
technologies in
reporting to the
GHGRP in a future
rulemaking.
------------------------------------------------------------------------
Legal Authority
The EPA is finalizing these rule amendments under its existing CAA
authority provided in CAA section 114. As stated in the preamble to the
2009 final GHG reporting rule (74 FR 56260; October 30, 2009), CAA
section 114(a)(1) provides the EPA broad authority to require the
information to be gathered by this rule because such data would inform
and are relevant to the EPA's carrying out a wide variety of CAA
provisions. See the preambles to the proposed (74 FR 16448; April 10,
2009) and final GHG reporting rule (74 FR 56260; October 30, 2009) for
further information.
In addition, pursuant to sections 114, 301, and 307 of the CAA, the
EPA is publishing final confidentiality determinations for the new data
elements required by these amendments. Section 114(c) requires that the
EPA make information obtained under section 114 available to the
public, except for information that qualifies for confidential
treatment. The Administrator has determined that this action is subject
to the provisions of section 307(d) of the CAA.
D. How do these amendments apply to 2015 and 2016 reports?
These amendments are effective on January 1, 2016. Thus, beginning
on January 1, 2016, facilities must follow the revised methods in
subpart W, as amended, to calculate emissions occurring during the 2016
calendar year (i.e., reporting year 2016). The first annual reports of
emissions calculated using the amended requirements will be those
submitted by March 31, 2017, covering reporting year 2016. For
reporting year 2015, reporters will continue to calculate emissions and
other relevant data for the reports that are submitted according to the
requirements in part 98 that are applicable to reporting year 2015
(i.e., the requirements in place until the effective date of this final
rule).
For reporting year 2016 only, we are allowing the use of best
available monitoring methods (BAMM) on a short-term transitional basis
for facilities new to reporting under subpart W as well as reporters of
facilities subject to new monitoring requirements associated with these
revisions. Reporters have the option of using BAMM for only the new
industry segments and emission sources included in this action from
January 1, 2016, to December 31, 2016, without seeking prior EPA
approval. The EPA will not accept requests for an extension for the use
of BAMM beyond the time periods listed above. The EPA is not allowing
the use of BAMM for the new well identification number provisions in
the Onshore Petroleum and Natural Gas Production segment because the
well identification number is not a parameter that requires monitoring
equipment to be measured and, therefore, does not meet the requirements
for BAMM. In addition, reporters should already have well
identification numbers readily available for all wells and associated
equipment to which this reporting requirement applies. See section II.E
of this preamble for more information.
II. Summary of Final Revisions and Other Amendments to Subpart W and
Responses to Public Comment
In this action, the EPA is amending subpart W to require the
reporting of GHG emissions from completions and workovers of oil wells
with hydraulic fracturing as part of the existing Onshore Petroleum and
Natural Gas Production industry segment. The EPA is also adding
requirements for two new industry segments: the Onshore Petroleum and
Natural Gas Gathering and Boosting segment for petroleum and natural
gas gathering and boosting systems, and the Onshore Natural Gas
Transmission Pipeline segment for transmission pipeline blowdowns
between compressor stations. Finally, the EPA is requiring the
reporting of well identification numbers for oil and gas well-specific
information (e.g., completions and workovers, associated gas venting
and flaring) reported in the Onshore Petroleum and Natural Gas
Production segment. The comments received on this rule generally did
not dispute the merit of adding these new segments and sources to
subpart W, but they did provide a number of suggestions regarding the
technical details of monitoring, reporting, and applicability.
Sections II.A through II.E of this preamble describe the
requirements and other amendments that we are finalizing in this
rulemaking. Section II.A describes the final amendments for the
[[Page 64266]]
reporting of GHG emissions from completions and workovers of oil wells
with hydraulic fracturing. Section II.B describes the final amendments
for the reporting of GHG emissions from sources in the new Onshore
Petroleum and Natural Gas Gathering and Boosting segment. Section II.C
describes the final amendments for the reporting of GHG emissions from
sources in the new Onshore Natural Gas Transmission Pipeline segment.
Section II.D describes the requirements for reporting well
identification numbers for the Onshore Petroleum and Natural Gas
Production segment. Finally, section II.E provides a summary of the
final amendments to the best available monitoring method requirements.
The amendments described in each section are followed by a summary of
the major comments on those amendments and the EPA's responses. See
``Response to Public Comments on Greenhouse Gas Reporting Rule: 2015
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems'' in Docket ID No. EPA-HQ-OAR-2014-0831 for a complete
listing of all comments and the EPA's responses.
Finally, in the preamble to the proposed rule, the EPA stated that
the agency is ``assessing the potential opportunities for applying
remote sensing technologies and other innovations in measurement or
monitoring technology to identifying and calculating emissions from
affected sources under subpart W'' (79 FR 73148; December 9, 2014). The
EPA did not propose, and therefore is not finalizing, any amendments to
subpart W to this effect, but the EPA did request comment on the
feasibility, possible regulatory approaches, provisions necessary to
incorporate or allow the use of advanced measurement or monitoring
methods in subpart W, and methods to ensure compliance with those
provisions in an efficient manner. The EPA also requested comment on
the memorandum ``Discussion Paper on Potential Implementation of
Alternative Monitoring under the GHGRP'' in Docket ID No. EPA-HQ-OAR-
2014-0831. All of the comments received are included in ``Response to
Public Comments on Greenhouse Gas Reporting Rule: 2015 Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems''
in Docket ID No. EPA-HQ-OAR-2014-0831. The EPA will consider these
comments in the context of any future action related to alternative
monitoring.
The amendments in this action will advance EPA's goal of maximizing
rule effectiveness. For example, these amendments provide clear
monitoring, calculation and reporting requirements for new segments and
sources in subpart W, thus enabling government, regulated entities, and
the public to easily identify and understand rule requirements. In
addition, specific changes such as increasing the flexibility and time
period for transitional BAMM will make compliance easier than non-
compliance.
These amendments will also improve the EPA's ability to assess
compliance by adding reporting elements that allow the EPA to more
thoroughly verify greenhouse gas data and understand trends in
emissions. For example, the requirement for the Onshore Petroleum and
Natural Gas Production segment to report well identification numbers
will allow the EPA to link GHGRP data with other data sources and
assess the completeness and representativeness of the data collected
relative to all activity in the U.S. oil and gas production sector.
Lastly, these amendments further advance the ability of the GHGRP to
provide access to quality data on greenhouse gas emissions by adding
key petroleum and natural gas emission sources to this program. One
example is the addition of the Onshore Petroleum and Natural Gas
Gathering and Boosting segment, a significant greenhouse gas emissions
segment that had not been previously covered under the GHGRP.
A. Summary of Final Amendments for Oil Wells With Hydraulic Fracturing
1. Summary of Final Amendments
The EPA is amending subpart W to require the reporting of GHG
emissions from completions and workovers with hydraulic fracturing for
wells in the Onshore Petroleum and Natural Gas Production segment,
regardless of whether their primary product is oil or natural gas. In
general, commenters supported inclusion of emissions from completions
and workovers of oil wells with hydraulic fracturing in subpart W, and
a few commenters provided targeted technical edits and suggestions for
this source. Consistent with the requirements for completions and
workovers of gas wells with hydraulic fracturing, and consistent with
the proposed requirements, the new provisions include the reporting of
activity data on the number of completions and workovers of oil wells
with hydraulic fracturing and on the use of flaring and reduced
emission completions (RECs). In response to public comments, the final
monitoring and reporting amendments do not apply to completions and
workovers of oil wells with hydraulic fracturing that have a gas to oil
ratio (GOR) of less than 300 standard cubic feet per stock tank barrel
(scf/STB).
The EPA is also amending the equations and definitions in 40 CFR
98.233(g) to reflect applicability to completions and workovers of all
gas and oil wells with hydraulic fracturing. As in the proposal, the
final amendments require the use of either Equation W-10A or W-10B for
calculating GHG emissions from completions and workovers of oil wells
with hydraulic fracturing. Equation W-10A is used to calculate
emissions from wells using inputs obtained from a representative sample
of wells within a sub-basin and the ratio of the gas flowback rate to
the production flow rate, and Equation W-10B is used to calculate
emissions using inputs obtained from all wells within a sub-basin and
the flow rate and flow volume of the gas vented or flared. As proposed,
the EPA is finalizing that emissions be calculated and reported
separately for gas wells and oil wells by sub-basin and well type
combination.\3\ Furthermore, as proposed, the final amendments require
the use of Calculation Method 1 for calculating inputs to Equations W-
12A and W-12B for oil wells. Calculation Method 1 relies on direct
measurement of gas flow rate during flowback to develop calculation
inputs; the requirements for the location of the flow meter used to
measure the gas flow rate for oil wells are the same as the location
requirements for gas wells. Other provisions that apply to completions
and workovers of gas wells with hydraulic fracturing also apply to
completions and workovers of oil wells with hydraulic fracturing,
including the determination of wells that constitute a representative
sample for use in Equation W-10A.
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\3\ Within subpart W, an individual well is labeled an ``oil
well'' or ``gas well'' depending on the formation type reported for
that well. If wells produce from more than one formation type, then
the well is classified into only one type based on the formation
type with the most contribution to production as determined by the
reporter's engineering knowledge. See the definition of ``Sub-basin
category, for onshore natural gas production'' in 40 CFR 98.238.
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For oil wells that do not meter gas production, such as some wells
with a relatively low GOR, the EPA is adding a new Equation W-12C as
proposed to calculate, rather than measure, the value of
PRs,p (the average gas production flow rate during the first
30 days of production after the completion or workover), which is used
as an input to Equation W-10A. In this Equation W-12C, the value of
PRs,p is calculated by multiplying the GOR of the well by
the measured oil production rate over the
[[Page 64267]]
first 30 days of production after the completion or workover.
2. Summary of Comments and Responses
Comment: Several commenters responded to the EPA's request for
comment on whether to establish a minimum GOR threshold such that oil
wells with a very low GOR would not be subject to the monitoring and
reporting requirements for GHG emissions from completions and workovers
with hydraulic fracturing. Most of these commenters supported
establishment of a cutoff for wells with very low emissions. One
commenter urged the EPA to require monitoring and reporting for all
completions and workovers with hydraulic fracturing but stated that if
a threshold is set, it should be set at a level that ensures that all
significant emissions sources are included and that sources are able to
clearly determine whether they are required to report. Three commenters
supported setting a minimum GOR threshold. One commenter suggested a
minimum GOR threshold of 300 and stated that, based on industry
experience, oil wells with GOR values less than 300 do not have
sufficient gas to operate a separator. The second commenter agreed that
operators should only have to monitor and report emissions if the GOR
is great enough to operate a separator and direct measurement is
possible. The third commenter supporting a minimum GOR threshold did
not provide a suggestion for a specific numeric threshold but stated
that the emissions from wells with a low GOR are insignificant, and the
time and resources involved in measuring the flowback and reporting
emissions for wells expected to have minimal emissions would outweigh
any contribution of these emissions to the overall source category
totals. This commenter supported the inclusion of a threshold so that
only significant sources of emissions would be included.
Response: The EPA agrees that including a minimum GOR threshold
will help minimize reporting burden while still capturing most of the
emissions from this source. Energy Information Administration data show
that the number of ``oil only'' wells drilled from 2007-2012 was less
than 20 percent of all new wells.\4\ These wells would have a GOR
approaching zero and, therefore, would be expected to have low
emissions. We believe that having no threshold may create an
unnecessary burden for operators to report emissions for these wells
with just a trace of gas. Given that the EPA is finalizing the proposed
requirement that the oil well flow meter be located downstream of the
separator, the separator must be operating for the owner or operator to
be able to measure the flow rate and estimate emissions from
completions and workovers of oil wells with hydraulic fracturing. One
commenter, an industry trade association, suggested a threshold of 300
scf/STB based on the industry trade association's experience that
separators typically do not operate at a GOR less than 300 scf/STB.
---------------------------------------------------------------------------
\4\ In this analysis, all hydrocarbon production in the liquid
state at the wellhead was considered oil. J. Lieskovsky and S.
Gorgen. ``Drilling often results in both oil and natural gas
production.'' Today in Energy, U.S. Energy Information
Administration, October 29, 2013. https://www.eia.gov/todayinenergy/detail.cfm?id=13571. Accessed June 9, 2015.
---------------------------------------------------------------------------
The primary concern when determining the level for a threshold is
volatility; the threshold must be low enough that the oil produced is
considered non-volatile. Non-volatile ``black oils'' (i.e., oil likely
to not have gases or light hydrocarbons associated with it) are
generally defined as having GOR values in the range of 200 to 900 scf/
STB.\5\ Oil wells with a GOR less than the 300 scf/STB suggested by the
commenter are at the lower end of this range, and completions and
workovers with hydraulic fracturing of these wells will not likely have
enough gas associated that can be separated. Therefore, the final
monitoring and reporting requirements do not apply to completions and
workovers of oil wells with hydraulic fracturing that have a GOR of
less than 300 scf/STB.
---------------------------------------------------------------------------
\5\ M.P. Walsh. ``Oil Reservoir Primary Drive Mechanisms.'' In
Petroleum Engineering Handbook, Volume V: Reservoir Engineering and
Petrophysics, E.D. Holstein (Ed.), L.W. Lake (Ed. in Chief), pp. V-
895-980. Society of Petroleum Engineers, 2007.
---------------------------------------------------------------------------
Comment: Several commenters responded to the EPA's request for
comment on whether to establish a minimum well pressure threshold such
that oil wells with a very low well pressure would not be subject to
the monitoring and reporting requirements for GHG emissions from
completions and workovers with hydraulic fracturing. Most of these
commenters supported establishment of a cutoff for wells with very low
well pressure. One commenter urged the EPA to require monitoring and
reporting for all completions and workovers with hydraulic fracturing
but stated that if a threshold is set, it should be set at a level that
ensures that all significant emissions sources are included and that
sources are able to clearly determine whether they are required to
report. Three commenters supported setting a minimum well pressure
threshold. One commenter suggested a minimum well pressure threshold of
0.4645 pounds per square inch per foot (psi/ft) because this is the
vertical pressure gradient needed for a well to flow back, based on
experience with the Natural Gas STAR program. The second commenter
suggested that operators should only have to monitor and report
emissions if the pressure of the reservoir during oil well completions
and workovers is greater than the pressure gradient of 0.433 psi/ft and
noted that the pressure needed varies based on the density of the
materials in the column and the depth of the well. The third commenter
supporting a minimum well pressure threshold did not provide a
suggestion for a threshold but supported the inclusion of a threshold
so that only significant sources of emissions would be included.
Response: The EPA evaluated the commenters' suggestions and has
decided not to include a minimum well pressure threshold. Both
commenters who suggested a specific value noted in their comments that
these pressure gradients are the minimum needed for the well to
produce. In other words, according to the commenters' rationale, wells
with pressures below the suggested pressure thresholds would not have
any production, regardless of whether a threshold is included in the
final rule. As a result, specifying that reporting of emissions from
completions and workovers of oil wells with hydraulic fracturing is not
required below those pressures is redundant. Therefore, the final rule
does not include a minimum well or reservoir pressure threshold for
completions and workovers of oil wells with hydraulic fracturing.
B. Summary of Final Amendments for the Onshore Petroleum and Natural
Gas Gathering and Boosting Segment
The EPA is amending subpart W to add a new industry segment,
Onshore Petroleum and Natural Gas Gathering and Boosting, that covers
emissions from equipment used by gathering pipeline systems that move
petroleum and natural gas from the well to either larger gathering
pipeline systems, natural gas processing plants, natural gas
transmission pipelines, or natural gas distribution pipelines. A
gathering and boosting system is a single network of pipelines,
compressors and process equipment, including equipment to perform
natural gas compression, dehydration, and acid gas removal, that has
one or more well-defined connection points to gas and oil production
and a well-defined downstream endpoint, typically a gas
[[Page 64268]]
processing plant or transmission pipeline. Gathering pipelines are
pipelines used to transport gas from the furthermost downstream point
in an onshore production facility to certain endpoints, generally
either a gas processing facility or point of connection to a
transmission pipeline. Compressors located along the gathering and
boosting system are used to control or ``boost'' the pressure of the
gas in the pipeline and keep the gas moving downstream. Commenters
generally supported inclusion of gathering and boosting system
emissions in subpart W, and many commenters suggested targeted
revisions concerning definitions, what emission sources should be
included in the segment and methods for individual emission sources.
The remainder of this section describes the final reporting
requirements for this new industry segment, including the segment
description, definitions, calculation methods, and information to be
reported. The amendments described in each section are followed by a
summary of the major comments, if any, on those amendments and the
EPA's responses. See ``Response to Public Comments on Greenhouse Gas
Reporting Rule: 2015 Revisions and Confidentiality Determinations for
Petroleum and Natural Gas Systems'' in Docket ID No. EPA-HQ-OAR-2014-
0831 for a complete listing of all comments and the EPA's responses.
1. Segment Description for the Onshore Petroleum and Natural Gas
Gathering and Boosting Segment
a. Summary of Final Amendments
The EPA is finalizing the definition of the Onshore Petroleum and
Natural Gas Gathering and Boosting segment in 40 CFR 98.230 as
gathering pipelines and other equipment used to collect petroleum and/
or natural gas from onshore production gas or oil wells and used to
compress, dehydrate, sweeten, or transport the petroleum and/or natural
gas to a natural gas processing facility, a natural gas transmission
pipeline, or a natural gas distribution pipeline. Gathering and
boosting equipment includes, but is not limited to, gathering
pipelines, separators, compressors, acid gas removal (AGR) units,
dehydrators, pneumatic devices/pumps, storage vessels, engines,
boilers, heaters, and flares. The Onshore Petroleum and Natural Gas
Gathering and Boosting segment does not include equipment and pipelines
that are reported under any other industry segment defined in subpart
W. The segment definition is being finalized as proposed, except that
the final amendments provide two clarifications regarding gathering
pipelines. First, gathering pipelines operating on a vacuum are not
included because they would not be expected to have emissions. Second,
to address comments regarding the inclusion of liquid and multiphase
streams in the segment, the definition clarifies that gathering
pipelines with a GOR less than 300 scf/STB are not a part of the
segment.
b. Summary of Comments and Responses
Comment: Commenters requested that the EPA remove ``Petroleum and''
from the proposed segment name, ``Onshore Petroleum and Natural Gas
Gathering and Boosting.'' The commenters asserted that the removal
would provide a clear demarcation between onshore petroleum and natural
gas production and onshore natural gas gathering and boosting. They
also stated that such a change would be more consistent with the
segment definition, which includes pipelines and equipment ``used to
compress, dehydrate, sweeten, or transport the gas to a natural gas
processing facility, a natural gas transmission pipeline or to a
natural gas distribution pipeline.'' The commenter stated that the type
of equipment included in the gathering and boosting segment is
``synonymous'' with gas gathering and boosting systems, not liquid or
petroleum, and they noted that the emission factor for equipment leaks
from gathering pipelines is not applicable to gathering pipelines that
carry mostly liquid.
Commenters also specifically requested that the EPA exclude
petroleum gathering pipelines from the gathering and boosting segment
because the fugitive gas emissions from these gathering pipelines would
be negligible. Both commenters stated that the proposed emission factor
for gathering pipeline leaks is only applicable to gas gathering
pipelines. Two commenters also requested that multi-phase flow lines
from wells to a centralized production facility where initial
separation occurs be retained in the Onshore Petroleum and Natural Gas
Production segment rather than included in the new gathering and
boosting segment.
Response: The EPA is finalizing the segment name as proposed and
not removing ``Petroleum and'' from the segment name or moving
multiphase gathering pipelines to the Onshore Petroleum and Natural Gas
Production segment. We proposed including ``Petroleum and'' in the
segment name to reflect the complex nature of upstream operations where
wells can produce oil, natural gas, or a mixture of both and to signify
the inclusion of GHG emissions from gathering and boosting systems
moving high volatility liquids in this new segment. Even in wells that
produce primarily liquids at surface temperature and pressure
conditions, there is often a volatile gaseous component. This
associated gas is usually considered wet due to the high content of
natural gas liquids (volatile components) to go along with gaseous
CH4. Similarly, the inclusion of all petroleum gathering
pipelines in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment, including multiphase pipelines, is appropriate,
because gathering lines are a key component to gathering and boosting
systems. Therefore, all gathering pipelines that collect petroleum and/
or natural gas from onshore production gas or oil wells and transport
the petroleum and/or natural gas to a natural gas processing facility,
a natural gas transmission pipeline or to a natural gas distribution
pipeline are considered part of the final Onshore Petroleum and Natural
Gas Gathering and Boosting segment.
However, the EPA does agree that gathering pipelines carrying
mostly oil have a low potential for GHG emissions. We note that the
ratio of CH4 to volatile components increases as the GOR
increases. Therefore, to clarify our intent to exclude gathering
pipelines containing oil, the final rule clarifies that the Onshore
Petroleum and Natural Gas Gathering and Boosting segment does not
include gathering pipelines with a GOR of less than 300 scf/STB.
Operators of gathering pipelines below that threshold are not required
to include those pipelines in their gathering and boosting facility.
See section II.B.5 of this preamble for additional discussion.
Finally, as part of evaluating this comment, the EPA reviewed the
proposed definitions related to the Onshore Petroleum and Natural Gas
Gathering and Boosting segment and recognizes that two of them referred
to ``the gas'' rather than ``the petroleum and/or natural gas.'' One
was the proposed description of the Onshore Petroleum and Natural Gas
Gathering and Boosting segment in 40 CFR 98.230, as identified by the
commenters, and the other was the definition of ``gathering and
boosting system owner or operator'' in 40 CFR 98.238. For consistency
throughout the final rule with the intent stated in this response, the
final description of the Onshore
[[Page 64269]]
Petroleum and Natural Gas Gathering and Boosting segment in 40 CFR
98.230 refers to ``petroleum and/or natural gas'' and the final
definition of ``gathering and boosting system owner or operator'' in 40
CFR 98.238 refers to ``the petroleum or natural gas transported.''
Comment: One commenter stated that there may be confusion regarding
which equipment should be reported in the different industry segments,
which could lead to emissions being mistakenly excluded or double-
counted. For example, gathering and boosting equipment located on a
single well pad or associated with a single well pad could be double-
counted, especially if it is operated by one entity but owned by
another. The commenter also noted that confusion over the proper
segment for this type of equipment could make the difference between
reporting emissions or not reporting emissions if a facility is close
to the reporting threshold of 25,000 metric tons carbon dioxide
equivalent (CO2e). Therefore, the commenter requested that
the EPA incorporate by reference the U.S. Department of
Transportation's Pipeline and Hazardous Materials Safety Administration
(PHMSA) federally defined boundaries of production, gathering and
boosting, and transmission segments to ensure state/federal
transparency and consistency.
Response: The EPA is not changing the segment description for the
Onshore Petroleum and Natural Gas Production segment in 40 CFR
98.230(a)(2) or the Onshore Natural Gas Processing segment in 40 CFR
98.230(a)(3). As stated at proposal, the EPA decided not to make any
changes to the existing segment descriptions to provide consistency for
reporters in that segment. This decision allows the EPA to ensure that
the data gap in subpart W related to gathering and boosting systems is
addressed while minimizing confusion over changes to other segments.
Instead, the EPA is reiterating the intention for the Onshore Petroleum
and Natural Gas Gathering and Boosting segment to cover equipment and
emission sources not included in reporting for the existing Onshore
Petroleum and Natural Gas Production or Onshore Natural Gas Processing
segments.
The EPA does not agree that emissions from the same equipment will
be reported under more than one industry segment in a given reporting
year; however, we acknowledge that similar equipment may exist in
adjacent industry segments as defined in subpart W. The owner or
operator of the equipment in question should first determine if that
equipment is subject to reporting in another segment of subpart W, such
as the Onshore Petroleum and Natural Gas Production or Onshore Natural
Gas Processing segments. If the equipment is not subject to reporting
in another segment of subpart W, then the owner or operator should
evaluate whether or not the equipment is included in the Onshore
Petroleum and Natural Gas Gathering and Boosting source category. For
example, if a gathering and boosting owner or operator also owns or
operates equipment on or associated with a single well pad (40 CFR
98.230(a)(2)), that equipment is part of the Onshore Petroleum and
Natural Gas Production segment, not the Onshore Petroleum and Natural
Gas Gathering and Boosting segment. Therefore, emissions from that
equipment should not be included when determining if the gathering and
boosting facility exceeds the reporting threshold.
Comment: One commenter requested that the EPA clarify the proper
segment for AGR units and revise the rule accordingly. The commenter
suggested that the Natural Gas Processing segment should explicitly
exclude sulfur dioxide and carbon dioxide (CO2) removal
units, so that it is clear that those units do not report under both
the Natural Gas Processing segment and the Onshore Petroleum and
Natural Gas Gathering and Boosting segment. The commenter stated that
this revision would be more consistent with the definition of gas
processing plant in other EPA rules. If the EPA does not make this
change, the commenter stated that AGR units should not be included in
the Onshore Petroleum and Natural Gas Gathering and Boosting segment
because they are already included in the Natural Gas Processing
segment. The commenter noted that AGR units are specifically defined in
40 CFR 98.238 as a process unit that separates hydrogen sulfide and/or
CO2 from sour natural gas using liquid or solid absorbents
or membrane separators.
Response: The EPA agrees that emissions from a particular acid gas
removal unit should not be reported under both the Natural Gas
Processing segment and the Onshore Petroleum and Natural Gas Gathering
and Boosting segment. However, as noted previously in this preamble,
the EPA is not changing the segment description for the Onshore
Petroleum and Natural Gas Production segment in 40 CFR 98.230(a)(2) or
the Onshore Natural Gas Processing segment in 40 CFR 98.230(a)(3).
Instead, the EPA is reiterating the intention for the Onshore Petroleum
and Natural Gas Gathering and Boosting segment to cover equipment and
emission sources not included in reporting for the Onshore Petroleum
and Natural Gas Production or Onshore Natural Gas Processing segments.
The final segment description for the Onshore Petroleum and Natural Gas
Gathering and Boosting segment in 40 CFR 98.230(a)(10) specifies that
gathering and boosting equipment does not include equipment reported
under any other industry segment defined in 40 CFR 98.230(a), which
should address the commenter's concern about reporting under multiple
segments.
Regarding the commenter's suggestion to exclude AGR units from the
Onshore Petroleum and Natural Gas Gathering and Boosting segment, the
EPA believes AGR units should be reported under subpart W and that the
current requirements, coupled with the revisions in this rulemaking,
allow for a clear demarcation of where they should be included and
reported. While most AGR units will be included in the Onshore Natural
Gas Processing segment, the EPA does not agree that the Onshore Natural
Gas Processing segment includes all AGR vents, particularly those in
processes that do not fractionate gas liquids with an annual average
throughput of less than 25 million scf per day. Therefore, the final
Onshore Petroleum and Natural Gas Gathering and Boosting segment
includes AGR vents that do not meet the segment descriptions for the
Onshore Petroleum and Natural Gas Production segment in 40 CFR
98.230(a)(2) or the Onshore Natural Gas Processing segment in 40 CFR
98.230(a)(3) but do meet the Onshore Petroleum and Natural Gas
Gathering and Boosting segment description in 40 CFR 98.230(a)(10).
2. Definitions
a. Summary of Final Amendments
The EPA is finalizing the definition of ``gathering and boosting
system'' as proposed and is finalizing the definition of ``gathering
and boosting system owner or operator'' as proposed with a
clarification that the fluid being transported may be petroleum or
natural gas. Specifically, a gathering and boosting system is a single
network of pipelines, compressors and process equipment, including
equipment to perform natural gas compression, dehydration, and acid gas
removal, that has one or more connection points to gas and oil
production and a downstream endpoint, typically a gas processing plant,
transmission pipeline, local distribution company (LDC) pipeline, or
other gathering and boosting system. A gathering and
[[Page 64270]]
boosting system owner or operator is any person that: (1) Holds a
contract in which they agree to transport petroleum or natural gas from
one or more onshore petroleum and natural gas production wells to a
natural gas processing facility, another gathering and boosting system,
a natural gas transmission pipeline, or a distribution pipeline; or (2)
is responsible for custody of the petroleum or natural gas transported.
In complex ownership scenarios, the owner/operator assigns a designated
representative responsible for reporting consistent with 40 CFR 98.4.
The EPA is also finalizing the definition of ``facility with
respect to onshore petroleum and natural gas gathering and boosting''
in 40 CFR 98.238 as proposed. A facility with respect to onshore
petroleum and natural gas gathering and boosting is all gathering
pipelines and other equipment located along those pipelines that are
under common ownership or common control by a gathering and boosting
system owner or operator and that are located in a single hydrocarbon
basin as defined in 40 CFR 98.238. Where a person owns or operates more
than one gathering and boosting system in a basin (for example,
separate gathering lines that are not connected), then all gathering
and boosting systems and equipment that the person owns or operates in
the basin are considered one facility. Any gathering and boosting
equipment that is associated with a single gathering and boosting
system, including leased, rented, or contracted activities, is
considered to be under common control of the owner or operator of the
gathering and boosting system. Emissions from an onshore petroleum and
natural gas gathering and boosting facility only need to be reported if
the collection of emission sources emits 25,000 metric tons
CO2e or more per year.
b. Summary of Comments and Responses
Comment: Multiple commenters provided comments on the definition of
``facility with respect to onshore petroleum and natural gas gathering
and boosting.'' Some commenters supported the basin-level approach that
the EPA proposed, although a few asked the EPA to clarify how to report
their emissions if their gathering and boosting system is in more than
one basin. Other commenters disagreed with the basin-level approach and
suggested that the EPA should use the definition of facility in 40 CFR
98.6. These commenters asserted that the basin-level approach would
result in an expansive definition of facility that includes huge
numbers of emissions sources and that this approach is not consistent
with how a facility is defined elsewhere in the GHGRP or with
traditional notions of aggregation under the CAA. One commenter
asserted that defining a facility in a way that is not consistent with
other CAA programs will make it difficult for the EPA to use the GHGRP
data to inform future policy decisions. The commenter also stated that
the EPA has not provided any explanation of why basin-wide aggregation
is a reasonable data request under section 114 of the CAA.
Commenters opposing the basin-level facility definition noted that
the Onshore Petroleum and Natural Gas Gathering and Boosting segment
has very different characteristics from the Onshore Petroleum and
Natural Gas Production segment, which also uses the basin-level
approach to defining a facility. One commenter specifically noted that
production sources are located at well-defined, discrete locations,
owners and operators of production sites know where the wells are
physically located and how many operate in a single production basin.
In contrast, the commenter stated, the gathering and boosting
operations of one owner or operator in a single hydrocarbon basin may
include hundreds or thousands of miles of pipelines with multiple
sites, including interconnects, meter stations, scrubber stations,
pigging stations, compressor stations, and gas treating plants. Another
commenter stated that gathering and boosting sites have the ability to
boost and move gas from multiple basins within the same site, whereas
production typically maintains operations and moves gas within one
basin.
Another commenter also disagreed with the basin-level approach,
noting that the term ``basin'' is not common terminology that is used
in the gathering and boosting industry segment. The commenter suggested
that the EPA use a county- or parish-level approach with an equipment
threshold (to determine which equipment should be counted when
determining if the 25,000 metric tons CO2e reporting
threshold has been exceeded).
Response: The EPA is finalizing the definition of ``facility with
respect to onshore petroleum and natural gas gathering and boosting''
as proposed. As noted in the preamble to the proposed amendments, the
basin-level approach to defining a facility for the Onshore Petroleum
and Natural Gas Gathering and Boosting segment is expected to achieve a
balance of providing geographically specific information while also
reducing burden on reporters. This approach also recognizes the fact
that gathering and boosting facilities are more dispersed than
processing facilities and are geographically similar to the Onshore
Petroleum and Natural Gas Production segment in size and number of
sources because, by their nature, they are needed to process and
transport the petroleum and natural gas produced in a given basin.
While some gathering and boosting operations may span multiple basins
or may only be present in a portion of a basin, as will some onshore
production operations, the EPA has concluded that a basin-level
facility definition is the best reflection of how this industry is
organized operationally.
In ``Greenhouse Gas Reporting Rule: Technical Support for 2015
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems; Proposed Rule'' (Docket Item No. EPA-HQ-OAR-2014-0831-
0018), we evaluated the option of using the definition of ``facility''
found in 40 CFR 98.6 for gathering and boosting facilities, and we
found that this definition would provide limited data on the proposed
Onshore Petroleum and Natural Gas Gathering and Boosting segment
compared to the basin-level approach, due to the fact that fewer
facilities would exceed the 25,000 metric tons CO2e
reporting threshold. It would also likely be more burdensome overall to
reporters, because a larger number of facilities would have to be
evaluated to determine whether they exceed the 25,000 metric tons
CO2e reporting threshold, and a larger number of
``facility'' reports would be required for each owner or operator. The
commenters did not provide any new information that would enable us to
re-evaluate this conclusion. A county- or parish-level approach would
similarly result in a larger number of smaller facilities to be
evaluated to determine whether they exceed the reporting threshold than
the basin-level approach. This approach would result in fewer
facilities reporting than a basin-level definition, especially if an
equipment threshold were defined as requested by the commenter, as well
as a higher burden for owners or operators with multiple facilities in
a basin that exceed the 25,000 metric tons CO2e reporting
threshold. Therefore, the EPA concluded that these options would not
achieve the goals that were articulated in the preamble to the proposed
rule of ``having a thorough data set and transparent, complete
information for this sector while minimizing burden to reporters'' (79
FR 73156; December 9,
[[Page 64271]]
2014). For more detail on this analysis, see ``Greenhouse Gas Reporting
Rule: Technical Support for Final 2015 Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems'' in Docket ID No.
EPA-HQ-OAR-2014-0831. We disagree with the comment that aggregation of
data would not provide a data set that the EPA can use to inform future
policy decisions. The purpose of this rule is to collect emissions and
activity data for this industry and understand the relative emission
sources, which we anticipate the aggregated data will help to promote.
Therefore, the aggregated data can still inform future GHG policy. As
we have pointed out previously, the EPA's definition of ``facility''
for purposes of part 98 in no way impacts the ``facility'' definition
for similar sources under existing CAA programs.\6\ Information
collected under part 98 can inform a number of different CAA programs
and the Agency's authority under CAA section 114 as the basis for part
98 is independent from the EPA's authority for other CAA programs.
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\6\ Mandatory Greenhouse Gas Reporting Rule: EPA's Response to
Public Comments, Subpart W: Petroleum and Natural Gas Systems,
Docket Id. No. EPA-HQ-OAR-2009-0923.
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To address the commenters' question about reporting a system in two
basins, we are confirming in this response that reporters should submit
one report per basin (i.e., per facility as it is defined in subpart W)
and that the 25,000 metric tons CO2e per year reporting
threshold applies to each basin/facility separately. In other words,
the reporter should determine the emissions from the portion of
gathering and boosting system associated with each basin. If the total
emissions in each basin exceed the 25,000 metric tons CO2e
per year reporting threshold, then the reporter submits two reports. If
the total emissions in one basin exceed the 25,000 metric tons
CO2e threshold, but the emissions in the other basin are
below the threshold, then the reporter submits one report (for the
facility that exceeds the threshold).
Regarding the commenter's question regarding the reasonableness of
collecting data at the basin-level under the CAA, the EPA established
its basis for collecting basin-level data in the final subpart W rule,
when the EPA finalized the requirements for the Onshore Petroleum and
Natural Gas Production segment. Additionally, as noted earlier in this
section, more granular collection of data for this segment would result
in higher burden for owners or operators with multiple operations in a
basin that exceed the 25,000 metric tons CO2e reporting
threshold. See also, ``Greenhouse Gas Emissions Reporting from the
Petroleum and Natural Gas Industry, Background Technical Support
Document (Docket Item No. EPA-HQ-OAR-2009-0923-3610) and ``Mandatory
Greenhouse Gas Reporting Rule Subpart W--Petroleum and Natural Gas:
EPA's Response to Public Comments'' (Docket Item No. EPA-HQ-OAR-2009-
0923-3608).
3. Blowdown Vent Stacks
a. Summary of Final Amendments
The EPA is finalizing the requirements for blowdowns of equipment
in the Onshore Petroleum and Natural Gas Gathering and Boosting segment
with some clarifications from proposal. Emissions should be calculated
using the same methods that are used for the Onshore Natural Gas
Processing segment. The same exemptions, including those for volumes
less than 50 cubic feet (ft\3\) and for desiccant dehydrator reloading,
apply to the Onshore Petroleum and Natural Gas Gathering and Boosting
segment. In response to comments that the segment is geographically
dispersed and blowdowns may occur without personnel on-site or nearby,
making it difficult to determine emissions from a blowdown event, the
final amendments specify that for emergency blowdowns, reporters may
use engineering estimates based on best available information to
determine the temperature and pressure used in Equation W-14A.
b. Summary of Comments and Responses
Comment: Commenters stated that the EPA should not include
reporting of blowdown vent stack emissions due to the large burden on
the reporter. Instead, the commenters stated, blowdowns in the Onshore
Petroleum and Natural Gas Gathering and Boosting segment should be
treated similarly to blowdowns in the Onshore Petroleum and Natural Gas
Production segment, where they are excluded because they are not
located at consolidated facility sites and are not manned. Commenters
also stated that blowdowns from gathering and boosting systems
contribute minimally to overall GHG emissions. One commenter noted that
while there is an exemption for any blowdown of a volume less than 50
ft\3\, there is also a burden to determine if the physical volume meets
this reporting threshold. To reduce the burden, some commenters
suggested only including emissions from blowdown vent stacks located at
a facility site (e.g., compressor station, central tank battery). Other
commenters stated if blowdowns remain in the segment, the EPA should
allow reporters to use an emission factor approach to calculate
emissions. Another commenter stated that the EPA's supporting
documentation focuses on gathering pipeline blowdowns, but the
regulatory text appears to include all the blowdowns occurring within a
basin, including individual equipment blowdowns. The commenter
requested that the EPA clarify its intent if blowdowns remain in the
segment.
Response: The EPA has evaluated these comments and has decided to
finalize the reporting requirements for blowdowns in the Onshore
Petroleum and Natural Gas Gathering and Boosting segment with some
revisions to address the commenters' concerns. While the EPA does
recognize that many gathering and boosting systems are geographically
dispersed, as noted by the commenters, the nature of the Onshore
Petroleum and Natural Gas Gathering and Boosting segment is such that
the amount of fluid passing through a gathering and boosting system
will be much greater than the amount of fluid at individual well pads.
Therefore, the EPA has determined that the potential for emissions from
blowdowns in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment is higher than blowdowns in the Onshore Petroleum and
Natural Gas Production segment, and they should not be excluded.
However, the EPA acknowledges that the geographic dispersion of the
segment, and the fact that some blowdowns occur without facility
personnel on site, may make it difficult to measure emissions from
blowdowns, particularly emergency blowdowns. Therefore, the final
amendments include a provision specifying that for emergency blowdowns,
reporters may use engineering estimates based on best available
information to determine the temperature at actual conditions in the
unique physical volume and absolute pressure at actual conditions in
the unique physical volume for use in Equation W-14A.
To respond to the commenter's request regarding whether only
gathering pipeline blowdowns or all equipment blowdowns should be
included, the EPA is clarifying that the intent is to include emissions
from the ``blowdown vent stacks'' source type as defined in subpart A
of part 98. The focus on blowdown vent stacks located on gathering
pipelines in the supporting documentation was not intended to imply
that only gathering pipeline blowdowns should be reported. On the
[[Page 64272]]
contrary, the proposal supporting documentation reflects the fact that
the EPA expected that blowdown vent stacks located at boosting stations
would be similar to blowdown vent stacks in other industry segments and
conducted a separate evaluation to determine whether the same
calculation methods would be appropriate for gathering pipeline
blowdown vent stacks. The final rule supporting documentation more
clearly reflects this intent. The EPA also notes that while measuring
equipment to determine whether it exceeds the 50 ft\3\ physical volume
threshold for reporting may create an initial burden on reporters, the
threshold will lead to a burden reduction as reporters become familiar
with the identification process.
4. Storage Tank Vented Emissions
a. Summary of Final Amendments
The EPA is finalizing the same methods for calculating emissions
for atmospheric storage tanks located in the Onshore Petroleum and
Natural Gas Gathering and Boosting segment as in the Onshore Petroleum
and Natural Gas Production segment, as proposed but with a few
clarifications. Specifically, the EPA is clarifying some of the
language within 40 CFR 98.233(j) and 40 CFR 98.236(j) that was
originally written to apply to Onshore Petroleum and Natural Gas
Production facilities and not proposed to be amended to also apply to
storage tanks in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment. In particular, references to a ``wellhead separator''
have been clarified to refer simply to a ``separator,'' which is a
defined term in 40 CFR 98.238. To accommodate Onshore Petroleum and
Natural Gas Gathering and Boosting storage tanks that do not receive
hydrocarbon liquids from a separator or well, Calculation Methods 1 and
2 have been amended to specify how to estimate emissions if liquids are
received from non-separator equipment. In addition, certain instances
of ``sub-basin'' have been amended to refer to ``county'' to clarify
the requirements for Onshore Petroleum and Natural Gas Gathering and
Boosting reporters. All other provisions in 40 CFR 98.233(j) apply to
the Onshore Petroleum and Natural Gas Gathering and Boosting segment,
including the 10 barrels per day threshold for determining which
calculation method may be used for estimating emissions.
b. Summary of Comments and Responses
Comment: One commenter stated that combining the requirements for
storage tanks in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment and the Onshore Petroleum and Natural Gas Production
segment results in confusing terminology and unclear requirements. In
particular, the commenter noted that the terms ``separator(s),'' ``gas-
liquid separator(s),'' ``wellhead separator(s),'' and ``wellhead gas-
liquid separator(s),'' appear throughout the storage tank requirements.
The commenter asked whether the EPA intended all of these terms to
refer to the same equipment. The commenter also noted that not all
gathering and boosting system storage tanks receive liquids directly
from separators, and no gathering and boosting storage tanks receive
liquids directly from wellhead separators. Therefore, the commenter
stated, the requirements for storage tanks in the Onshore Petroleum and
Natural Gas Gathering and Boosting segment are unclear.
The commenter also noted inconsistency between use of the terms
``oil,'' ``sales oil,'' and ``stabilized oil'' in 40 CFR 98.233(j) and
40 CFR 98.236(j). The commenter stated that Onshore Petroleum and
Natural Gas Gathering and Boosting facilities may process condensate
but not oil, and the commenter asked the EPA to clarify how those terms
should be applied to the Onshore Petroleum and Natural Gas Gathering
and Boosting segment.
Finally, the commenter noted that Calculation Method 1 for storage
tanks requires use of the latest available analysis that is
representative of produced crude oil or condensate from the sub-basin
category. The commenter stated that the term ``sub-basin'' has no
relevance to the Onshore Petroleum and Natural Gas Gathering and
Boosting segment because the composition of condensate processed at a
compressor station may have little relationship to the oil or gas
formation below the compressor station.
Response: The EPA agrees that the language in 40 CFR 98.233(j) and
40 CFR 98.236(j) should be clear for all Onshore Petroleum and Natural
Gas Production facilities and all Onshore Petroleum and Natural Gas
Gathering and Boosting facilities to which it applies. The existing
definition of ``separator'' in 40 CFR 98.238 is a vessel in which
streams of multiple phases are gravity separated into individual
streams of single phase. This general definition and the general term
``gas-liquid separator'' apply to both Onshore Petroleum and Natural
Gas Production facilities and all Onshore Petroleum and Natural Gas
Gathering and Boosting facilities. Therefore, the EPA has reviewed the
language and is amending references to a ``well,'' ``well pad,'' or
``wellhead,'' which are terms that are not expected to apply to most
Onshore Petroleum and Natural Gas Gathering and Boosting facilities.
The final provisions in 40 CFR 98.233(j) and 40 CFR 98.236(j) refer
more generally to separators or gas-liquid separators. To address the
comment that not all gathering and boosting system storage tanks
receive liquids directly from separators, the EPA has amended 40 CFR
98.233(j)(1) and (2) to specify how those calculation methodologies may
be used for Onshore Petroleum and Natural Gas Gathering and Boosting
storage tanks receiving hydrocarbon liquids from non-separator
equipment (i.e., without a well or separator directly upstream of the
storage tank).
Regarding the particular material being stored in storage tanks,
the EPA agrees that there is inconsistency in some of the terms that
could cause some confusion. The EPA is clarifying in this response that
for the Onshore Petroleum and Natural Gas Gathering and Boosting
segment, the intent is for ``oil'' to refer more generally to
hydrocarbon liquids, which is consistent with the statement in 40 CFR
98.233(j) that reporters are required to calculate emissions ``from
atmospheric pressure fixed roof storage tanks receiving hydrocarbon
produced liquids.'' The proposed separate reporting requirements for
quantity of produced oil throughput and produced condensate throughput
in 40 CFR 98.236(aa)(10) have been revised, and the final rule requires
reporting of the hydrocarbon liquids received by the facility and the
hydrocarbon liquids leaving the facility. Finally, the EPA notes that
the term ``sales oil'' is already defined in Subpart A to include
``produced crude oil or condensate,'' so there is no further
clarification needed.
Regarding the term ``sub-basin,'' the EPA agrees with the commenter
that the definition of ``sub-basin category, for onshore natural gas
production'' in 40 CFR 98.238 is not relevant for Onshore Petroleum and
Natural Gas Gathering and Boosting facilities. The EPA also agrees that
the operations within a section of a gathering and boosting system may
not be related to the formation type below the surface of the ground at
that location, especially as the material travels further from the
wells supplying gas and hydrocarbon liquids to the system. As a result
of this comment, the EPA reviewed the use of the term ``sub-basin'' as
it was proposed to apply to Onshore Petroleum and Natural Gas Gathering
and Boosting facilities. In 40 CFR 98.233(j), the calculation methods
provide options to
[[Page 64273]]
estimate unknown parameters using information from a previous analysis
of the composition in the sub-basin category. In these cases, the
intent is to estimate unknown parameters from a representative unit
(e.g., well, separator). To reflect a similar intent for Onshore
Petroleum and Natural Gas Gathering and Boosting facilities, 40 CFR
98.233(j)(1)(vii)(B) and 40 CFR 98.233(j)(1)(vii)(C) in Calculation
Method 1 clarify that representative separators or non-separator
equipment are located within the same county for Onshore Petroleum and
Natural Gas Gathering and Boosting reporters. For Calculation Method 2,
the term ``sub-basin category'' is used to describe calculation of
emissions for flow to storage tanks directly from wells. The final rule
includes a new paragraph 40 CFR 98.233(j)(2)(iii) to address
calculation of emissions from flow to a tank from equipment other than
a well or separator (such as a stabilizer or slug catcher), and this
paragraph also clarifies that representative analyses should come from
other non-separator equipment located within the same county. Finally,
there are reporting requirements for a ``sub-basin ID'' in 40 CFR
98.236. The final rule specifies that for Onshore Petroleum and Natural
Gas Gathering and Boosting, the information to be reported is the
county in which the equipment is located.
5. Gathering Pipelines
a. Summary of Final Amendments
The EPA is finalizing the requirements for calculating emissions
from gathering pipelines defined to be included in the Onshore
Petroleum and Natural Gas Gathering and Boosting segment as proposed.
The methodology is similar to the approach used for equipment leaks in
the Onshore Petroleum and Natural Gas Production segment. For gathering
lines, reporters use the population count and emission factor approach
in 40 CFR 98.233(r). The emission factors in Table W-1A for gathering
pipelines are whole gas emission factors based on the U.S. GHG
Inventory. The population count is the miles of gathering pipeline,
similar to the approach used for calculating emissions from natural gas
distribution pipelines in the Natural Gas Distribution segment. As
noted in section II.B.1.a of this preamble, gathering pipelines with a
GOR less than 300 scf/STB are not included in this segment.
b. Summary of Comments and Responses
Comment: One commenter asserted that the EPA should revise the
proposed emission factor of 2.81 standard cubic feet (scf)/hour/mile
for leaks from gathering pipelines to be based on characteristics of
currently operating gathering pipelines rather than distribution
pipelines or older data on gathering pipelines. The commenter also
noted that this emission factor is not applicable to gathering
pipelines that carry primarily liquids, as there is no gas stream until
after separation. The commenter identified gathering pipeline-specific
data from PHMSA and used the data to calculate a suggested emission
factor of 2.23 scf/hour/mile.
Response: We reviewed the underlying data used to develop the
proposed emission factor, and we agree with the commenter that the
proposed emission factor could better account for differences between
pipeline types and for currently operating gathering pipelines. In the
1996 Gas Research Institute (GRI)/EPA report that is the basis of the
emission factor, material-specific emissions factors for gathering
lines were developed using data from direct measurement of distribution
pipelines conducted in the 1990s, not gathering pipelines. These
material-specific emission factors are the same emission factors used
by the commenter as the starting point for their revised emission
factor.
We agree with the commenter that the emission factors should better
represent currently operating gathering pipelines; however, there is
significant variability in gathering pipelines and gathering system
configurations. Owners and operators currently report the mileage of
pipeline by gathering pipeline type to PHMSA.\7\ Therefore, rather than
calculate a single emission factor for gathering pipelines based on a
distribution of gathering pipeline materials, as was done at proposal,
the EPA determined that the most appropriate approach is to develop
gathering pipeline emission factors for four pipeline material types:
Protected steel, unprotected steel, plastic, and cast iron. (For more
information about the development of these emission factors, see
``Greenhouse Gas Reporting Rule: Technical Support for Final 2015
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems'' in Docket ID No. EPA-HQ-OAR-2014-0831.) The final
amendments require reporters to estimate emissions using material-
specific emission factors provided in the rule and to report gathering
pipeline mileage by material type.
---------------------------------------------------------------------------
\7\ U.S. Department of Transportation Pipeline and Hazardous
Materials Safety Administration. Natural and Other Gas Transmission
and Gathering Pipeline Systems: Annual Report for Calendar Year.
Form PHMSA F 7100.2-1 (rev 10-2014). OMB No. 2137-0522, Expires: 10/
31/2016.
---------------------------------------------------------------------------
The EPA also notes that reporters will not need to calculate
emissions from gathering pipelines that carry hydrocarbon liquids if
they are below the minimum GOR threshold for the Onshore Petroleum and
Natural Gas Gathering and Boosting segment.
6. Other Emission Sources
a. Summary of Final Amendments
The EPA is finalizing the requirements for natural gas pneumatic
devices and pneumatic pumps located in the Onshore Petroleum and
Natural Gas Gathering and Boosting segment as proposed. Gathering and
boosting reporters will use the same methods for calculating emissions
as in the Onshore Petroleum and Natural Gas Production segment. The EPA
is also finalizing the requirements for acid gas removal units,
dehydrators, and flare stacks as proposed. The methods are the same as
the methods for these sources in both the Onshore Petroleum and Natural
Gas Production segment and the Onshore Natural Gas Processing segment.
The EPA is also finalizing the requirements for compressors and
equipment leaks as proposed, with one clarification regarding how to
count ``meters/piping'' for equipment leaks. Gathering and boosting
reporters use the same method as in the Onshore Petroleum and Natural
Gas Production segment. Specifically, a reporter will need to establish
an inventory of the components or equipment subject to the population
counts, apply the emission factors, and then update the inventory each
year to account for new or retired components or equipment.
b. Summary of Comments and Responses
Comment: Two commenters stated that the major equipment categories
for calculating equipment leaks by population count are not clear for
the Onshore Petroleum and Natural Gas Gathering and Boosting segment.
Both commenters requested that the EPA clarify how to count ``meters/
piping'' for the Onshore Petroleum and Natural Gas Gathering and
Boosting segment. One commenter also requested clarification regarding
separators, compressors, and in-line heaters (specifically, whether
small heating systems used to ensure a temperate environment for a
meter are considered in-line heaters). The
[[Page 64274]]
commenter also noted that there was limited time to evaluate the
appropriateness of the emission factors in Table W-1A and the component
counts in Table W-1B for gathering and boosting systems.
Response: The categories in Table W-1B represent the types of
equipment that are generally expected to be found in the field for
Onshore Petroleum and Natural Gas Production and Onshore Petroleum and
Natural Gas Gathering and Boosting facilities.\8\ For the Onshore
Petroleum and Natural Gas Gathering and Boosting segment, the EPA
realizes that reporters will only use those categories that apply
(e.g., reporters will not include wellheads, as that equipment type is
specific to Onshore Petroleum and Natural Gas Production facilities).
---------------------------------------------------------------------------
\8\ See the memorandum ``Equipment-Level Population Emission
Factors for Onshore Production,'' Docket Item No. EPA-HQ-OAR-2009-
0923-3582, for more information regarding the derivation of this
table.
---------------------------------------------------------------------------
Most of the major equipment categories are described by function in
the rule. For the example of a separator, 40 CFR 98.238 defines a
separator as ``a vessel in which streams of multiple phases are gravity
separated into individual streams of single phase.'' Any device meeting
this functional definition will fall into this major equipment
category. Other major categories are described in the rule by their
functional role, including dehydrators and compressors. For the in-line
heater example for which the commenter requested clarification, the
equipment described is not located in line with the fluid flow and
therefore would not be considered in this equipment category.
The EPA agrees with both commenters that the measurement of meters/
piping in the Onshore Petroleum and Natural Gas Gathering and Boosting
segment was not clear as proposed. The final rule specifies that
reporters in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment should count the number of meters in the facility and
use that as the count for ``meters/piping.''
Comment: Two commenters supported the use of calculation methods
that include emission factors for the Onshore Petroleum and Natural Gas
Gathering and Boosting segment because they are less burdensome to the
industry. However, the commenters also requested that the EPA allow
reporters the option to use any available data/information that
provides the best representation of emissions from their specific
sources, including manufacturer data, test data, measurement and/or
monitoring data. The commenters compared this option to the approach in
state-level emissions inventories that require an emissions reporting
hierarchy. The commenters noted that this approach will provide the EPA
with more accurate emissions data that could be used to update the
emission factors for the Onshore Petroleum and Natural Gas Gathering
and Boosting segment.
Response: The calculation methods provided in subpart W were
selected to minimize burden on industry while maintaining the necessary
quality and consistency of data to inform policy. Therefore, outside of
the BAMM provisions being finalized in this rulemaking, the EPA does
not agree to allow reporters to use customized, individual information
for their emission sources at this time. The EPA is currently
investigating additional calculation methods for subpart W sources and
may propose additional calculation methods in the future.
C. Summary of Final Amendments for the Onshore Natural Gas Transmission
Pipeline Segment
1. Summary of Final Amendments
The EPA is finalizing the proposal to add reporting requirements
for emissions from natural gas transmission pipeline blowdowns between
compressor stations in a new Onshore Natural Gas Transmission Pipeline
segment. Commenters generally had no objections to the merit of
including this segment in subpart W but did suggest technical edits and
clarifications for targeted provisions. As noted in the preamble to the
proposed amendments, a blowdown is the release of gas from transmission
pipelines that causes a reduction in system pressure or a complete
depressurization. The EPA is clarifying that for the purposes of the
Onshore Natural Gas Transmission Pipeline segment, the blowdowns that
must be reported are blowdowns of a pipeline or section of pipeline.
The EPA is finalizing clarifications to the proposed definition of
onshore natural gas transmission pipeline owner or operator. For
interstate pipelines, the onshore natural gas transmission pipeline
owner or operator is the person identified as the transmission pipeline
owner or operator on the Certificate of Public Convenience and
Necessity issued under 15 U.S.C. 717f, as proposed. For intrastate
pipelines, the onshore natural gas transmission pipeline owner or
operator is the person identified as the owner or operator on the
transmission pipeline's Statement of Operating Conditions under section
311 of the Natural Gas Policy Act (NGPA). If the intrastate pipeline is
not subject to section 311 of the NGPA, the onshore natural gas
transmission pipeline owner or operator is the person identified as the
owner or operator on reports to the state regulatory body regulating
rates and charges for the sale of natural gas to consumers. Finally,
the owner or operator of a pipeline that falls under the ``Hinshaw
Exemption'' is the person identified as the owner or operator on
blanket certificates issued under 18 CFR 284.224.
The EPA is finalizing the definition of facility for the new
Onshore Natural Gas Transmission Pipeline segment as proposed; the
facility is the total U.S. mileage of natural gas transmission
pipelines owned or operated by an onshore natural gas transmission
pipeline owner or operator. If an owner or operator has multiple
pipelines in the United States, the facility is considered the
aggregate of those pipelines, even if they are not interconnected.
The EPA is finalizing the requirement that reporters use the
methods in 40 CFR 98.233(i) to calculate or measure emissions from
pipeline blowdown events as proposed. One method allows a reporter to
calculate emissions based on the volume of the pipeline segment between
isolation valves that is blown down and the pressure and temperature of
the gas within the pipeline. The second method allows the reporter to
measure the emissions from the blowdown using a flow meter on the
blowdown vent stack. In both methods, the reporter calculates both
CH4 and CO2 emissions from the volume of natural
gas vented using either default gas composition or engineering
estimates of composition as specified in 40 CFR 98.233(u)(2)(iii).
The EPA is not finalizing the proposed requirement to report the
emissions and location (latitude and longitude) of each blowdown event.
Instead, the EPA is requiring that Onshore Natural Gas Transmission
Pipeline reporters report the total CH4 and CO2
emissions in each state, the number of blowdowns in each state, and the
miles of pipeline in each state. In addition, instead of requiring
Onshore Natural Gas Transmission Pipeline reporters to use the same
equipment and event type categories as other industry segments
reporting blowdown emissions, the EPA is including reporting categories
specific to the Onshore Natural Gas Transmission Pipeline segment.
[[Page 64275]]
2. Summary of Comments and Responses
Comment: Several commenters noted that not all intrastate pipelines
are subject to section 311 of the NGPA and asked the EPA to clarify
which intrastate pipelines are subject to reporting. One commenter
requested that the EPA clarify that intrastate pipelines not subject to
the NGPA are not required to report under subpart W. Another commenter
suggested revising the definition of owner or operator to state that if
section 311 of the NGPA does not apply, the intrastate transmission
pipeline owner or operator is the owner or operator identified on
required reports with the appropriate state agency.
Response: It was our intent to include transmission pipelines
(including intrastate pipelines) that meet the already existing subpart
W definition of ``transmission pipeline'' in the Onshore Natural Gas
Transmission Pipeline segment. A transmission pipeline in subpart W is
defined in 40 CFR 98.238 as a Federal Energy Regulatory Commission
(FERC) rate-regulated Interstate pipeline, a state rate-regulated
Intrastate pipeline, or a pipeline that falls under the ``Hinshaw
Exemption'' as referenced in section 1(c) of the Natural Gas Act, 15
U.S.C. 717-717 (w)(1994). After reviewing the comments on the proposed
rule, we re-reviewed section 311 of the NGPA and found that only
operators of some intrastate pipelines, including those that transport
natural gas on behalf of an interstate pipeline or sell natural gas to
an interstate pipeline, are required to prepare a Statement of
Operating Conditions for compliance under section 311 of the NGPA.
Therefore, to clarify how to determine the owner and operator of
intrastate transmission pipelines, the finalized definition of
``onshore natural gas transmission pipeline owner or operator''
specifies that for intrastate transmission pipelines not subject to
section 311 of the NGPA, the owner or operator is the person identified
as the owner or operator on reports to the state regulatory body
regulating rates and charges for the sale of natural gas to consumers.
The EPA also found that the proposed definition of ``onshore natural
gas transmission pipeline owner or operator'' did not specify how to
determine the owner or operator of pipelines that fall under the
``Hinshaw Exemption.'' The EPA notes that similar to intrastate
pipelines, pipelines that fall under the ``Hinshaw Exemption'' must
apply for a ``blanket certificate'' under 18 CFR 284.224 in order to
transport petroleum or natural gas on behalf of interstate pipelines.
Therefore, the finalized definition of ``onshore natural gas
transmission pipeline owner or operator'' also specifies that for a
pipeline that falls under the ``Hinshaw Exemption,'' the owner or
operator is the person identified as the owner or operator on blanket
certificates issued under 18 CFR 284.224.
Comment: Commenters appreciated that the EPA provided a threshold
of 50 ft\3\ of physical volume for blowdown emissions reporting but
requested several changes. Commenters requested that the EPA include a
list of ancillary equipment, such as metering and/or regulating
stations, pipeline interconnects, and pig launchers and receivers, that
would be excluded from reporting of blowdown emissions. One commenter
suggested that, alternatively, the physical volume threshold could be
increased to 3,000 thousand cubic feet to clearly exclude blowdowns of
ancillary facilities along the pipeline. Another commenter stated that
it is not feasible to establish a specific de minimis volume threshold
to exclude all ancillary equipment.
Response: The EPA is finalizing the reporting threshold of 50 ft\3\
of physical volume for blowdowns in the Onshore Natural Gas
Transmission Pipeline segment as proposed. This threshold excludes
smaller blowdown sources that have little contribution to emissions,
consistent with other industry segments within subpart W that must
report blowdown stack vent emissions. The EPA is not increasing the
physical volume reporting threshold to account for blowdowns from
ancillary equipment, as this would be inconsistent with the EPA's
previous analysis in ``Equipment Threshold for Blowdowns'' (see Docket
Item No. EPA-HQ-OAR-2009-0923-3581), and commenters were divided on
whether increasing the threshold would even address their primary
concern.
The EPA agrees that the emphasis for the Onshore Natural Gas
Transmission Pipeline segment is on calculating and reporting blowdown
emissions from pipeline segments, not ancillary equipment. However, any
list of ancillary equipment that would be excluded from blowdown
reporting could be incomplete, resulting in reporting of emissions from
other equipment that is ancillary but not on the list in the rule. In
addition, some of the equipment identified as ``ancillary'' in this
segment is not considered ancillary in other industry segments, which
could lead to confusion among reporters. Instead, the final rule
clarifies that facilities in the Onshore Natural Gas Transmission
Pipeline segment report pipeline blowdown emissions from blowdown vent
stacks. If the blowdown does not include a pipeline segment or has a
physical volume of less than 50 ft\3\, then that blowdown is not
required to be reported.
Comment: Several commenters stated that the blowdown equipment and
event type categories in 40 CFR 98.233(i)(2) were developed for
compressor station blowdowns and would not provide meaningful
information regarding pipeline blowdowns in the Onshore Natural Gas
Transmission Pipeline segment. The commenters provided suggestions for
categories that would be more applicable to Onshore Natural Gas
Transmission Pipeline blowdowns and would provide more valuable
information than relying on the categories in the existing rule.
Response: The EPA agrees with the commenters that the rule should
include blowdown categories specific to blowdowns in the Onshore
Natural Gas Transmission Pipeline segment. The final rule specifies
that blowdowns must be grouped into one of the following categories:
Pipeline integrity work (e.g., the preparation work of modifying
facilities, ongoing assessments, maintenance or mitigation),
traditional operations or pipeline maintenance, equipment replacement
or repair (e.g., valves), pipe abandonment, new construction or
modification of pipelines including commissioning and change of
service, operational precaution during activities (e.g. excavation near
pipelines), emergency shutdowns including pipeline incidents as defined
by PHMSA, and all other pipeline segments with a physical volume
greater than or equal to 50 ft\3\.
Comment: Commenters requested that the EPA not finalize the
requirement to report latitude and longitude for each blowdown event.
The commenters indicated this requirement would be burdensome, such
data are not currently collected, the requirement is inconsistent with
the Paperwork Reduction Act, and the data would not be useful in
determining the inventory. Some commenters also suggested aggregating
emissions at the state level or only at the national/facility level.
Response: The requirement to report latitude and longitude of each
blowdown was included in the proposed rule to help characterize the
emissions from the new Onshore Natural Gas Transmission Pipeline
segment on a more granular level than the nationwide facility. The EPA
evaluated this comment and has noted the commenters' assertion that the
latitude and longitude of each
[[Page 64276]]
blowdown is not information currently reported elsewhere and may result
in additional burden. Therefore, the EPA is not finalizing the
requirement to report the emissions or latitude and longitude for each
individual blowdown. Instead, the EPA is finalizing requirements for
reporters to aggregate blowdown emissions by state and report the
number of blowdowns and mileage of pipeline per state.
Comment: Two commenters questioned the requirement to report the
data elements in proposed 40 CFR 98.236(aa)(11). Two commenters noted
that the quantities of natural gas in this section are duplicative of
information reported to FERC annually in FERC Form 2, although the
units of measure are dekatherms rather than thousand standard cubic
feet. One commenter noted that for the GHGRP reporting, they would
assume 1 dekatherm is equivalent to 1,000 scf of natural gas, based on
the approximate heat value of natural gas. The other commenter opposed
these reporting requirements because they are duplicative and
inconsistent with the requirements of the PRA, which is intended to
reduce the information burden imposed by the federal government by
requiring that agencies ensure that reported information is not
duplicative of other available data and has a practical utility. This
commenter stated that the EPA has not followed the PRA. The commenter
also stated that the requested information is irrelevant to assisting
EPA in verifying pipeline blowdown emissions; in particular, the
information cannot be used to calculate pipeline blowdown volumes.
Response: As the EPA has noted elsewhere, the data collected in the
GHGRP will be used to inform future policy decisions. As such,
information regarding emissions and the inputs needed to verify those
emissions is only part of the information that is needed. It is
important to understand that, to inform future policy, activity data is
often as useful as emissions estimates. The EPA has determined that
data elements in 40 CFR 98.236(aa)(11) are activity data that will be
used to determine how to use the emissions data to inform future policy
decisions. It is essential that reporters provide and certify the data
they gather under this rule so that EPA has a complete inventory from
all sources under this rule and can directly relate the activity data
to the emissions data reported, which will provide for appropriate
verification of the emissions data reported.
The EPA agrees with the first commenter that for purposes of
reporting the data elements in 40 CFR 98.236(aa)(11), reporters may
consider 1 dekatherm equal to 1,000 scf.
Comment: Several commenters asserted that the EPA has not been
consistent in its decisions on whether to include pipeline leaks across
the subpart W industry segments. Some commenters supported the EPA's
proposal not to include leaks from transmission pipelines and noted the
decision was consistent with the Onshore Petroleum and Natural Gas
Production segment. Conversely, one commenter stated that transmission
pipeline leaks should be reported, consistent with the new Onshore
Petroleum and Natural Gas Gathering and Boosting segment. This
commenter noted that accidental leaks at these facilities can be a
significant source of CH4 emissions, as evidenced by the
magnitude of emissions from pipeline incidents reported to PHMSA, and
leaks at remote locations may not be noticed or repaired immediately.
Response: The EPA previously considered fugitive emissions that
result from leaks in transmission pipelines in the re-proposal of
subpart W in April 2010 (75 FR 18616; April 12, 2010) but did not
include provisions for these emissions in either the proposed or final
rules. The April 2010 preamble explained that the EPA did not propose
reporting requirements for fugitive emissions from leaks in natural gas
pipeline segments between compressor stations due to the dispersed
nature of the fugitive emissions and the fact that, once fugitives are
found, the leaks causing the emissions are usually addressed quickly
for safety reasons (75 FR 18616; April 12, 2010). The EPA also noted in
the proposal preamble for these amendments (79 FR 76267; December 9,
2014) that larger fugitive leaks are currently reported to PHMSA as
part of 49 CFR 191.3. Under this provision, any pipeline incident that
results in unintentional gas loss of 3 million ft\3\ or more must be
reported. The commenter that noted that emissions can be significant
cited the emissions reported to PHMSA under this provision, and the EPA
does not find it necessary to require owners and operators to report
this same information under the GHGRP. The focus of the PHMSA reporting
requirements is to identify major safety-related incidents that are not
a part of typical operations. Therefore, the EPA is not finalizing a
requirement to report fugitive emissions from transmission pipeline
leaks but will continue to review this source as part of the EPA's
ongoing effort to ensure comprehensive, high quality data in subpart W.
D. Summary of Final Amendments for Well Identification Numbers
1. Summary of Final Amendments
The EPA is finalizing some of the proposed amendments to 40 CFR
98.236 to add reporting requirements for well identification numbers to
improve data quality by enabling identification of wells. These well
identification numbers will be reported for the first time in the
report covering 2016 emissions; reporters will not be required to
report well identification numbers for previous years. For the majority
of wells, the well identification number reported will be the US Well
Number (formerly referred to as the API Well Number, or API Number).\9\
For any well that does not already have a US Well Number, the reporter
will be required to provide the unique well number assigned by the
permitting authority for drilling of oil and gas wells. Commenters
varied in their level of support for the proposed provisions regarding
well identification numbers. The EPA is adjusting the final provisions
in response to concerns about these reporting provisions raised in
comments.
---------------------------------------------------------------------------
\9\ The Professional Petroleum Data Management Association. The
US Well Number Standard: An Identifier for Petroleum Industry Wells
in the USA. Version 2013 rev 1, published June 19, 2014. Available
at https://dl.ppdm.org/dl/1147.
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The EPA is requiring the reporting of well identification numbers
for the Onshore Petroleum and Natural Gas Production segment only for
information related specifically to wells. For reporters in the Onshore
Petroleum and Natural Gas Production segment that report emissions
using input data that are calculated from measurements at individual
wells or equipment associated with individual wells (e.g., if Equation
W-10A was used to calculate emissions from oil well completions and
workovers with hydraulic fracturing, well testing emissions), the
report must include the well identification number for which those
measurements were made and the well identification number(s) of other
wells to which the measurements will be applied. This includes a list
of the well identification numbers by sub-basin for the producing wells
at the end of the calendar year as well as lists of the well
identification numbers for the wells acquired, divested, completed, and
permanently taken out of production during the calendar year. The EPA
is not finalizing the proposed requirement that reporters in the
Onshore Petroleum and Natural Gas Production segment report a list of
well identification numbers associated with different emission
[[Page 64277]]
sources for all wells in a sub-basin included in the reported emissions
data.
The EPA is finalizing the proposed change to update references to
the ``API well number'' in subpart W to ``well identification number.''
The EPA is not otherwise changing the well identification reporting
requirements finalized in 2014 (79 FR 70352; November 25, 2014).
Reporters will still need to report well identification numbers for
liquids unloading and for any exploratory wells for which reporting has
been delayed for 2 years.
2. Summary of Comments and Responses
Comment: While one commenter supported the addition of well
identification number reporting, most commenters opposed the proposal
to require reporting of well identification numbers. These commenters
asserted that requiring reporting of well identification numbers is an
overreach of the EPA's authority for the reporting program under CAA
section 114 and that the EPA has not provided a reasoned basis for the
departure from the previous EPA approach that well-specific data was
not necessary under Subpart W. Commenters also noted that well
identification numbers are not needed to validate reported emissions.
One commenter noted that the EPA has not questioned the data collected
from wells thus far; nor has the EPA stated that the data already
collected are insufficient to inform policy without addition of well
identification numbers, so with this proposal, the EPA is no longer
balancing data collection with reporting burdens. Commenters stated
that mapping and maintaining a database of well identification numbers
is more burdensome than the EPA estimated, and one commenter stated
that it would be arbitrary and capricious to require companies to
expend the resources necessary to report these data. Commenters also
noted that it is not clear how to interpret the term ``associated
with'' in all cases. One commenter stated that matching specific wells
with emissions in the GHGRP could cause security concerns.
Response: The EPA disagrees that requiring reporting of well
identification numbers is an overreach of our authority. The EPA has
determined that these data elements are useful and necessary for the
verification of existing data and for characterizing the emissions from
the industry segment. This final revision will allow the EPA to link
the GHGRP data to other databases (i.e. state permitting databases) to
more easily match the data reported under the GHGRP with other data
sources and will improve the accuracy and transparency of subpart W.
Additionally, being able to match the GHGRP data to other data sources
will provide the EPA with more options for analysis of the GHGRP data
to better inform future policy decisions related to GHG emissions from
the oil and natural gas production sector. The reporting of the well
identification numbers will also allow the EPA to assess the
completeness and representativeness of the data collected under the
GHGRP as a portion of all activity in the oil and natural gas
production sector. The EPA reiterates that CAA section 114 provides the
EPA with the authority to collect emissions data, which includes
information about the location of the source of emissions. Section 114
generally authorizes the EPA to gather information from any person who
owns or operates an emissions source, who is subject to a requirement
of the CAA, who manufactures control or process equipment, or who the
Administrator believes has information necessary for the purposes of
section 114(a). The EPA may gather information for purposes of
establishing implementation plans or emissions standards, determining
compliance, or ``carrying out any provision'' of the CAA. For these
reasons, the Administrator may request that a person, on a one-time,
periodic or continuous basis, establish and maintain records, make
reports, install and operate monitoring equipment and, among other
things, provide such information the Administrator may reasonably
require. This language has been interpreted to grant the EPA broad
authority. See, e.g., Dow Chemical Co. v. U.S., 467 U.S. 227, 233
(1986) (``Regulatory and enforcement authority generally carries with
it all modes of inquiring and investigation traditionally employed or
useful to execute the authority granted.''). See, generally Mandatory
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments,
Volume No.: 9, Legal Issues (Docket Item No. EPA-HQ-OAR-2008-0508-
2264). The requirement to report well identification numbers for well-
specific data clearly fits within EPA's statutory authority. We also
believe, for the reasons stated above, that we are exercising this
authority reasonably in furtherance of the purposes of the Clean Air
Act. Further, the EPA disagrees that this is a deviation from our
previous approach to collecting data. As discussed in section II.B of
this preamble, the EPA is finalizing the requirement to report Onshore
Petroleum and Natural Gas Gathering and Boosting facilities at the
basin-level, which is consistent with our previous approach to the
Onshore Petroleum and Natural Gas Production segment.
Therefore, the EPA is finalizing the requirements to report the
well identification number for well-specific data as proposed.
Specifically, for reporters in the Onshore Petroleum and Natural Gas
Production segment that report emissions using input data that are
calculated from measurements at individual wells or equipment or
operations associated with individual wells (e.g., if Equation W-10A is
used to calculate emissions from oil well completions and workovers
with hydraulic fracturing, well testing emissions, liquids unloading),
the report must include the well identification number for which those
measurements were made, or for which the equipment or operations are
associated. In addition, the EPA is finalizing the requirements in 40
CFR 98.236(aa)(1)(ii)(D) through (H) to include a list of the well
identification numbers by sub-basin for the producing wells at the end
of the calendar year and lists of the well identification numbers for
the wells acquired, divested, completed, and permanently taken out of
production during the calendar year. The EPA continues to expect that
this is a low burden to reporters because reporters already track and
maintain well identification numbers associated with measurements used
for the GHGRP input data.
To respond to the comment that well identification numbers may not
be available for or assigned to equipment other than wells, the EPA
reviewed the permits and requirements in seven different states.
Although most of the states assign unique identifiers to each emission
source, the EPA found that only two of the seven states have a tracking
system that links individual emission sources to specific wells and
well identification numbers, and these two states are not consistent in
their approach. (See ``Greenhouse Gas Reporting Rule: Technical Support
for 2015 Revisions and Confidentiality Determinations for Petroleum and
Natural Gas Systems; Final Rule'' in Docket ID No. EPA-HQ-OAR-2014-0831
for more information on this analysis.) While it may be straightforward
to assign some emission sources directly to one well, particularly if
there is only one well on the single well pad and the reporter does not
operate any other wells nearby, the EPA's review of state requirements
shows that there may be multiple scenarios in which a reporter does not
know which well or wells are associated with a particular emission
source. For
[[Page 64278]]
example, there may be multiple wells on a single well pad and multiple
storage tanks associated with that well pad, and the tanks may have the
ability to receive hydrocarbon liquids from several of those wells.
Therefore, in light of the potential burden of requiring facilities to
develop new tracking systems that would assign and track emissions to
well identification numbers for the purposes of part 98, the EPA is not
requiring facilities in this rulemaking to report well identification
numbers for every emission source in a facility in the Onshore
Petroleum and Natural Gas Production segment.
E. Summary of Final Amendments to Best Available Monitoring Methods
1. Summary of Final Amendments
As proposed, reporters will be allowed to use BAMM for the 2016
reporting year for the new industry segments and emission sources
included in this action. These include calculating and reporting
emissions from oil well completions and workovers with hydraulic
fracturing, from onshore petroleum and natural gas gathering and
boosting systems, and for transmission pipeline blowdown emissions.
Reporters are allowed to use BAMM to estimate inputs to emission
equations for the newly finalized emission sources for cases where the
monitoring of these inputs would not be possible beginning on January
1, 2016. The use of BAMM is not allowed for the reporting of well
identification numbers because reporters should already have well
identification numbers readily available for all wells and associated
equipment to which this reporting requirement applies and because the
well identification number is not a parameter that requires monitoring
equipment to be measured and, therefore, does not meet the requirements
for BAMM.
For these sources, the EPA is finalizing a longer timeline for BAMM
than was proposed. Reporters have the option of using BAMM for the new
industry segments and emission sources included in this action from
January 1, 2016, to December 31, 2016, without seeking prior EPA
approval. The provision providing a set amount of automatic
transitional BAMM will allow reporters to prepare for data collection
while automatically being able to use BAMM, which is consistent with
the approach of prior part 98 rulemakings. This additional time for
reporters to comply with the revised monitoring methods in subpart W
will allow facilities to install the necessary monitoring equipment
during other planned (or unplanned) process unit downtime, thus
avoiding process interruptions, and is responsive to comments received
on the proposed rule provisions.
The EPA is not finalizing the proposed provision to allow reporters
the opportunity to request an extension for the use of BAMM. The EPA
will not accept requests for an extension for the use of BAMM beyond
the time periods listed above. As proposed, the EPA also is not
providing transitional BAMM for these new requirements beyond December
31, 2016.
The EPA is not allowing the use of BAMM beyond 2016 and does not
anticipate that BAMM will be needed beyond 2016 for the new segments
and emissions sources being finalized in this rule.
2. Summary of Comments and Responses
Comment: Several commenters stated that only 3 months of automatic
BAMM and 1 year of transitional BAMM is not enough time to implement
the monitoring and measurement requirements for facilities newly
subject to subpart W and newly added emission sources. The commenter
stated that adding a new segment is a significant amendment and the EPA
has set the precedent of providing at least 1 year of automatic BAMM
when adding a new segment to subpart W. The commenters noted that not
all gathering and boosting reporters are already reporting as Onshore
Petroleum and Natural Gas Production facilities, so they will not
necessarily all be familiar with the monitoring and calculation
methodologies. The commenters also noted that nearly all reporters will
be spending the first month working on BAMM requests for the rest of
2016.
The commenters had a variety of suggestions for how long the EPA
should provide BAMM for these new emission sources. Several commenters
suggested 1 year (through the end of 2016) for automatic BAMM. Another
commenter suggested March 31, 2017 (i.e., 1 year in addition to the
EPA's proposed 3 months), and another stated that 3 years would be
consistent with the length of time provided when the Onshore Petroleum
and Natural Gas Production segment was added to subpart W. Some
commenters addressed the length of transitional BAMM with the EPA's
approval. One commenter noted that a new reporter/facility could become
subject to one of the new segments beyond the end of 2016, so there
should be no deadline for submitting a request for BAMM to the EPA.
Another requested transitional BAMM through the end of 2018.
Response: The EPA recognizes that most of the amendments being
finalized in this rulemaking are new requirements rather than
clarifications of existing reporting requirements for facilities
already subject to subpart W and may require the development and
implementation of new systems of data collection and monitoring.
Therefore, the EPA is finalizing 1 year of automatic transitional BAMM
in place of the proposed 3 months of automatic transitional BAMM. This
additional time for reporters to comply with the revised monitoring
methods in subpart W will allow facilities to install the necessary
monitoring equipment and implement any new systems of data collection
that may be required. Because the amount of time for which automatic
BAMM is available should be sufficient time to comply with the
requirements of subpart W for the new segments and emission sources,
the EPA will not provide additional BAMM beyond the automatic BAMM
provisions in 40 CFR 98.234(g).
We note that 40 CFR 98.235(e) and(f) provides 6 months of reporting
flexibility for facilities that become subject to subpart W or acquire
new sources after reporting year 2016. Reporters may also refer to the
provisions of 40 CFR 98.235 after reporting year 2016 for guidance on
reporting emissions if certain required data are not collected.
III. Confidentiality Determinations
A. Summary of Final Confidentiality Determinations for New Subpart W
Data Elements
In the proposed rule, we assigned new data elements to the
appropriate direct emitter data categories created in the 2011 Final
CBI Rule based on the type and characteristics of each data
element.\10\ For data elements the EPA assigned to a direct emitter
category with a categorical determination, the EPA proposed that the
categorical determination for the category be applied to the proposed
new data element. For data elements assigned to the ``Unit/Process
`Static' Characteristics that Are Not Inputs to Emission Equations''
and ``Unit/Process Operating Characteristics that Are Not Inputs to
Emission Equations,'' we proposed confidentiality determinations on a
case-by-case basis taking into
[[Page 64279]]
consideration the criteria in 40 CFR 2.208, consistent with the
approach used for data elements previously assigned to these two data
categories. We also proposed individual confidentiality determinations
for six new data elements without making a data category assignment.
Refer to the preamble to the proposed rule (79 FR 76267; December 9,
2014) for additional information regarding the proposed confidentiality
determinations.
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\10\ ``Confidentiality Determinations for Data Required Under
the Mandatory Greenhouse Gas Reporting Rule and Amendments to
Special Rules Governing Certain Information Obtained Under the Clean
Air Act'' (76 FR 30782, May 26, 2011).
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With consideration of the data provided by commenters, the EPA is
finalizing the confidentiality determinations as proposed.
Specifically, the EPA is finalizing the proposed decision to require
each of the new data elements to be designated as ``not CBI.''
The EPA proposed to provide reporters with the option to delay
reporting of five data elements for 2 reporting years in situations
where exploratory wells are the only wells in a sub-basin. We received
comment requesting that the EPA provide the same 2-year delay for
additional data elements associated with exploratory wells. The comment
and the EPA's response are included in section III.B of this preamble.
Based on consideration of the comment and consistent with the EPA's
previous decisions related to exploratory wells under part 98 (79 FR
63750, October 24, 2014; 79 FR 70352, November 25, 2014), the EPA is
finalizing provisions to provide reporters with the option to delay
reporting of five data elements as proposed and, based on comments
received, an additional two data elements for 2 reporting years in
situations where exploratory wells are the only wells in a sub-basin.
For a given sub-basin, in situations where wildcat wells and/or
delineation wells are the only wells in a sub-basin that can be used
for the required measurement, the following seven data elements
associated with the delineation or wildcat well may be delayed for 2
reporting years: (1) The cumulative gas flowback time, in hours, for
each sub-basin, from when gas is first detected until sufficient
quantities are present to enable separation (40 CFR 98.236(g)(5)(i));
(2) the cumulative flowback time, in hours, for each sub-basin, after
sufficient quantities of gas are present to enable separation (40 CFR
98.236(g)(5)(i)); (3) the measured flowback rate, in standard cubic
feet per hour, for each sub-basin (40 CFR 98.236(g)(5)(ii)); (4) the
gas to oil ratio for the well (40 CFR 98.236(g)(5)(iii)(A)); (5) the
volume of oil produced during the first 30 days of production after
completions of each newly drilled well or well workover using hydraulic
fracturing (40 CFR 98.236(g)(5)(iii)(B)); (6) the total annual gas-
liquid separator oil volume that is sent to applicable onshore storage
tanks, in barrels (40 CFR 98.236(j)(1)(iii)); and (7) the total annual
oil throughput that is sent to all atmospheric tanks, in barrels (40
CFR 98.236(j)(2)(i)(A).
Four of the seven data elements for which reporting may be delayed
by 2 years are inputs to emission equations and the EPA provided the
same option in the EPA's previous decisions related to exploratory
wells under part 98 (79 FR 63750, October 24, 2014). Two of the seven
data elements are inputs only when the applicable data are related to a
single well (the two data elements in 40 CFR 98.236(g)(5)(i)), and one
data element is never an input (40 CFR 98.236(j)(2)(i)(A)). Where the
EPA agrees that there are early disclosure concerns related to
exploratory wells, the EPA decided to treat those early disclosure
concerns consistently throughout subpart W by providing the option to
delay reporting by 2 years to all seven data elements listed above.
At proposal, in cases where the two data elements in 40 CFR
98.236(g)(5)(i)) are not inputs to equations, they were assigned to the
``Unit/Process Operating Characteristics that are Not Inputs to
Emission Equations'' category and were proposed to be ``not CBI.'' The
EPA is finalizing this determination as proposed. Specifically, the
``not CBI'' determination applies to all situations except for when the
data elements are inputs to equations.
For the situations when the data elements are used as inputs to
equations, the EPA is assigning them to the ``Inputs to Emission
Equations'' data category and is not making confidentiality
determinations for these data. The EPA evaluated and summarized any
potential disclosure concerns with the reporting of the data elements
assigned to the ``Inputs to Emission Equations'' data category in the
memo titled ``Review for Potential Disclosure Concerns for Inputs to
Emission Equations Affected by the 2015 Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems'' available in
Docket ID No. EPA-HQ-OAR-2014-0831. Other than the exception of the
early disclosure concerns for certain data elements related to
exploratory wells discussed earlier in this section, the EPA has
concluded that there are no disclosure concerns with the reporting of
these data elements.
The data element collected under 40 CFR 98.236(j)(2)(i)(A) was
proposed as ``not CBI'' and was not assigned to a data category. The
EPA is finalizing this determination as proposed as well. For the data
elements reported under 40 CFR 98.236(g)(5)(i)) (in cases where they
are not inputs to equations) and 40 CFR 98.236(j)(2)(i)(A), the ``not
CBI'' determinations will apply once the data are reported to the EPA
following the 2-year delay.
B. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed categorical assignments and confidentiality
determinations. See ``Response to Public Comments on Greenhouse Gas
Reporting Rule: 2015 Revisions and Confidentiality Determinations for
Petroleum and Natural Gas Systems'' in Docket ID No. EPA-HQ-OAR-2014-
0831 for a complete listing of all comments and responses. See the
memorandum ``Final Data Category Assignments and Confidentiality
Determinations for Data Elements (excluding inputs to emission
equations) in the `Greenhouse Gas Reporting Rule: 2015 Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems;
Final Rule' '' in Docket ID No. EPA-HQ-OAR-2014-0831 for a complete
listing of final data category assignments and confidentiality
determinations, and a discussion of changes since proposal.
Comment: One commenter requested that the EPA reconsider the
determination that the quantity of produced gas throughput in the
calendar year and the quantity of produced gas consumed by the facility
in the calendar year are ``not CBI.'' The commenter noted that the
quantity of natural gas received and the quantity of processed gas
leaving processing plants was maintained as CBI in the 2014 amendments
(79 FR 70352; November 25, 2014). The commenter also stated that
information on fuel consumed at gathering and boosting facilities is
not typically publically available, and when this information is
combined with the quantity of produced gas throughput, it directly
indicates the fuel efficiency of a station. The commenter noted that
while the EPA is correct that the agreements are long-term for a given
well, revealing information about one facility's fuel efficiency could
cause competitive harm by affecting contracts for other facilities
owned by that company, especially if there are smaller gathering and
boosting facilities in the area that do not have to report this
information to the GHGRP.
The commenter also requested that the EPA clarify a number of the
reporting elements in 40 CFR
[[Page 64280]]
98.236(aa)(10). Specifically, the commenter requested clarification of
the terms ``produced gas,'' ``produced condensate,'' ``produced oil,''
``throughput,'' and ``consumed'' as they are used in proposed 40 CFR
98.236(aa)(10). The commenter also asserted that the data element in 40
CFR 98.236(aa)(10)(ii) (``quantity of produced gas consumed'') would be
redundant with subpart C and should not be finalized. Finally, the
commenter stated that the requirement to report the ``quantity of gas
flared, vented and/or unaccounted for in the calendar year'' in 40 CFR
98.236(10)(aa)(v) would undermine over 5 years of rule development,
public comment, reconsiderations, and petitioner negotiations because
it would require reporting of emissions that are otherwise exempted
(e.g., blowdowns below 50 ft\3\).
Response: The EPA reviewed these comments and has clarified the
reporting elements in 40 CFR 98.236(aa)(10) for the final rule. The
final reporting requirements include: (1) The quantity of gas received
by the gathering and boosting facility in the calendar year, in
thousand standard cubic feet; (2) the quantity of gas transported to a
natural gas processing facility, a natural gas transmission pipeline, a
natural gas distribution pipeline, or another gathering and boosting
facility in the calendar year, in thousand standard cubic feet; (3) the
quantity of all hydrocarbon liquids received by the gathering and
boosting facility in the calendar year, in barrels; and (4) the
quantity of all hydrocarbon liquids transported to a natural gas
processing facility, a natural gas transmission pipeline, a natural gas
distribution pipeline, or another gathering and boosting facility in
the calendar year, in barrels. The EPA has determined that these
quantities will be easily accessible for all reporters and are more
consistent with the reporting requirements for the Onshore Natural Gas
Processing segment. The EPA is finalizing the CBI determinations for
these quantities as ``not CBI,'' as proposed.
The final reporting requirements do not include the terms
``produced gas,'' ``produced condensate,'' ``produced oil,''
``throughput,'' or ``consumed,'' so no clarification regarding the use
of those terms is needed. In particular, the final rule does not
include a requirement to report the quantity of produced gas consumed
by the facility. The difference between the quantities received by a
gathering and boosting facility and the quantities exiting the
gathering and boosting facility is expected to include the quantity of
gas consumed by the facility as well as the quantity of gas flared or
vented in one lump sum. Therefore, the reporting requirements do not
directly indicate the fuel efficiency of the stations in a gathering
and boosting facility.
Comment: One commenter reiterated previously stated concerns over
the disclosure of information for exploratory wells, especially when
they are located in stepout areas where no prior reporting exists for a
given sub-basin. The commenter supported the EPA's proposal to defer
reporting of data elements related to oil well completions and
workovers with hydraulic fracturing for exploratory wells, but
expressed concern that EPA has not provided such a delay in reporting
for all emissions data and data elements that are associated with
exploratory wells. Specifically, the commenter stated that the EPA
failed to provide a necessary 2-year deferral in reporting for the
following data elements, which are as business sensitive and
confidential as the other information for which the EPA proposed to
defer reporting for 2 years:
40 CFR 98.236(g)(5)(iii)(A)--If you used Equation W-12C
to calculate the average gas production rate for an oil well, the
gas to oil ratio for the well in standard cubic feet of gas per
barrel of oil.
40 CFR 98.236(g)(5)(iii)(B)--If you used Equation W-12C
to calculate the average gas production rate for an oil well, the
volume of oil produced during the first 30 days of production after
completions of each newly drilled well or well workover using
hydraulic fracturing, in barrels.
40 CFR 98.236(g)(6)(i)--If you used Equation W-10B to
calculate annual volumetric total gas emissions for completions that
vent gas to the atmosphere, the vented natural gas volume, in
standard cubic feet, for each well in the sub-basin.
40 CFR 98.236(g)(6)(ii)--If you used Equation W-10B to
calculate annual volumetric total gas emissions for completions that
vent gas to the atmosphere, the flow rate at the beginning of the
period of time when sufficient quantities of gas are present to
enable separation, in standard cubic feet per hour, for each well in
the sub-basin.
40 CFR 98.236(g)(7)--For each oil well completion or
workover and well type combination, annual gas emissions.
40 CFR 98.236(g)(8)--For each oil well completion or
workover and well type combination, annual CO2 emissions.
40 CFR 98.236(g)(9)--For each oil well completion or
workover and well type combination, annual CH4 emissions.
40 CFR 98.236(g)(10)--For each oil well completion or
workover and well type combination, the total N2O
emissions, if the well emissions were vented to a flare.
Response: The EPA reviewed the data elements identified by the
commenter as having disclosure concerns for exploratory wells
(delineation wells and wildcat wells). Consistent with the EPA's
previous decisions related to exploratory wells under part 98 (79 FR
63750, October 24, 2014; 79 FR 70352, November 25, 2014), the EPA has
determined that, for gas well completions or workovers with hydraulic
fracturing of wildcat wells and/or delineation wells, early public
disclosure of some of the additional data elements identified by the
commenter could reveal the well productivity of wildcat wells and/or
delineation wells, thereby resulting in the loss of investment value.
The additional data elements that could reveal well productivity
for wildcat and/or delineation wells are as follows:
The gas to oil ratio for the well (40 CFR
98.236(g)(5)(iii)(A))
The volume of oil produced during the first 30 days of
production after completions of each newly drilled well or well
workover using hydraulic fracturing (40 CFR 98.236(g)(5)(iii)(B))
As the EPA has previously noted (79 FR 70352, November 25, 2014),
in the interim period before these data are reported to the EPA, the
EPA will be able to verify the majority of the emissions using data
elements that will be reported to the EPA. For the seven total data
elements that may be delayed for 2 years, the EPA will verify emissions
using other data reported to the EPA, and will conclude verification
upon receipt of the data. The EPA agrees with the commenter that a 2-
year delay of reporting is sufficient to prevent early public
disclosure of these data and will provide sufficient time for the
reporter to thoroughly conduct an assessment of the well. Given the
results of this evaluation, the EPA determined that, for these data
elements, in those cases where delineation wells or wildcat wells are
the only wells in a sub-basin, reporters should be provided an option
to delay reporting of the given data element for 2 reporting years
starting in 2015. In such cases, if the 2-year delay in reporting is
used, the reporter must indicate for each delayed reporting element
that wildcat wells and/or delineation wells are the only wells in a
sub-basin that can be used for the measurement in the current reporting
year. In addition, when reporters report the delayed data elements
after the 2-year delay, they must also report the well identification
numbers for the applicable wildcat and/or delineation wells in the sub-
basin for which the reporting element was delayed. For example, if a
delineation or wildcat well is completed in 2015 in a sub-basin that
[[Page 64281]]
has only delineation or wildcat wells or these are the only wells for
which measurements can be made, then the reporter may: (1) Elect to
report these seven data elements in their 2016 annual report submitted
by March 31, 2017, or (2) elect to delay reporting of these data
elements for up to 2 years. If the reporter elects to delay reporting,
then the well identification numbers for the wildcat and delineation
wells in the sub-basin for which reporting has been delayed and the
data elements delayed from reporting must be reported no later than
March 31, 2019.
The following inputs meet the definition of emission data in 40 CFR
2.301(a)(2)(i) because they indicate the amount or frequency of gas
emitted by the facility: Volume of natural gas vented (reported under
40 CFR 98.236(g)(6)(i)) and flow rate at the beginning of the period of
time when sufficient quantities of gas are present to enable separation
(reported under 40 CFR 98.236(g)(6)(ii)). Without corresponding
activity data, such as a count of the exploratory wells in a sub-basin
or production or flow rate data for a sub-basin containing only
exploratory wells, there is no potential to disclose business sensitive
information based on these data elements. Therefore, the EPA is not
providing an option to delay reporting of these data elements for 2
reporting years.
Similarly, the data element annual gas emissions (reported under 40
CFR 98.236(g)(7)) meets the definition of emission data in 40 CFR
2.301(a)(2)(i) and is assigned to the ``Emissions'' data category
because it indicates the amount of gas emitted by the facility. In
addition, the following data elements meet the definition of emission
data in 40 CFR 2.301(a)(2)(i) and are assigned to the ``Emissions''
data category because they are emissions of pollutants emitted by the
source: annual CO2 emissions (reported under 40 CFR
98.236(g)(8)), annual CH4 emissions (reported under 40 CFR
98.236(g)(9)), and annual nitrous oxide (N2O) emissions if
the well emissions were vented to a flare (reported under 40 CFR
98.236(g)(10)). For these data elements that are assigned to the
``Emissions'' data category, the commenter did not claim or provide any
justification for why these data elements do not meet the definition of
emission data. Without corresponding activity data, such as a count of
the exploratory wells in a sub-basin or production or flow rate data
for a sub-basin containing only exploratory wells, there is no
potential to disclose business sensitive information based on these
data elements. Therefore, the EPA is not providing an option to delay
reporting of these data elements for 2 reporting years.
IV. Impacts of the Final Amendments to Subpart W
A. Impacts of the Final Amendments
The final amendments to subpart W add monitoring and reporting
requirements for reporters in three industry segments: Onshore
Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas
Gathering and Boosting, and Onshore Natural Gas Transmission Pipeline.
The EPA is adding 213 new data elements to the reporting requirements.
The new data elements impose additional burden and costs because, for
each of the new data elements that are required to be reported,
reporters are required to calculate the data element using readily
available data and report the value to the EPA via e-GGRT as part of
the annual report currently required under part 98.
The EPA calculated the increase in reporting and recordkeeping
burden associated with the new data elements by adjusting labor hours
upwards per reporter for all affected industry segments. For all three
segments, an estimate of 10 hours per year per reporter was allotted
for reporting via e-GGRT and 10 hours per year per reporter was
allotted for recordkeeping.
Costs to reporters associated with this rulemaking are expressed as
labor costs (i.e., the cost of labor by facility staff to comply with
the amendments), capital costs for equipment and travel, and operation
and maintenance (O&M) costs.
Reporters in the Onshore Petroleum and Natural Gas Production
segment have to monitor and report emissions and data elements
associated with oil well completions and workovers with hydraulic
fracturing. Reporters in this segment also have to report the well
identification numbers associated with individual oil and gas wells.
The addition of the requirement to report emissions associated with oil
well completions and workovers with hydraulic fracturing is expected to
cause an increase in the amount of emissions that count towards
determining applicability under subpart W. The addition of reporting
requirements for oil wells with hydraulic fracturing is expected to
affect 246 existing reporters and to cause approximately 50 new
reporters to exceed the reporting threshold for the onshore petroleum
and natural gas production facility. These numbers have not changed
from proposal.
The 50 new reporters will be required to estimate and report
emissions data and related data elements associated with several
different emission sources within this new industry segment, including
acid gas removal units, associated natural gas venting and flaring,
storage tanks, dehydrators, equipment leaks, liquids unloading, and
pneumatic devices.
Reporters in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment must estimate and report emissions data and related
data elements associated with several different emission sources within
this new industry segment, including acid gas removal units, storage
tanks, blowdown vents, dehydrators, equipment leaks, flare stacks, and
pneumatic devices. Approximately 200 new reporters are expected to be
subject to subpart W due to the amendments for the Onshore Petroleum
and Natural Gas Gathering and Boosting segment in this rulemaking. This
number has not changed from proposal.
Reporters in the Onshore Natural Gas Transmission Pipeline segment
will need to estimate and report emissions data and related data
elements associated with transmission pipeline blowdown activities.
Approximately 183 new reporters in this segment are expected to be
subject to subpart W. This number increased from 150 to 183 since
proposal due to public comment.
The EPA received multiple comments regarding the impacts of the
proposed amendments. After evaluating these comments and reviewing
other changes from proposal, the EPA revised the impacts assessment
slightly from proposal. The final amendments to subpart W are not
expected to significantly change the burden calculated at proposal.
The EPA has determined that the cost associated with this final
action will be $7,190,235 each year and has worked to minimize burden
to reporters where practicable. See the memorandum, ``Assessment of
Impacts of the 2015 Final Revisions to Subpart W'' in Docket ID No.
EPA-HQ-OAR-2014-0831 for additional information.
B. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the impacts of the proposed amendments to subpart W of part 98. We note
that numerous commenters asserted that the burden was underestimated,
and some provided suggestions for improvement, but most of those
comments did not include the detailed information the EPA needed to
assess the comment
[[Page 64282]]
fully, such as a suggestion for a revised burden estimate, support for
the suggestion, and an explanation of why the suggested value is
representative of all sources subject to the same requirements. See
``Response to Public Comments on Greenhouse Gas Reporting Rule: 2015
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems'' in Docket ID No. EPA-HQ-OAR-2014-0831 for a complete
listing of all comments and responses.
Comment: One commenter asked for an explanation for the estimate of
200 respondents in the Onshore Petroleum and Natural Gas Gathering and
Boosting segment. The commenter noted that the EPA estimated the number
of reporters in the Onshore Natural Gas Processing industry segment as
291 reporters. The commenter stated by the nature of the industry, any
company with a processing plant will most likely also have an
associated gathering system subject to reporting and suggested that the
number of reporters in the Onshore Petroleum and Natural Gas Gathering
and Boosting industry segment should total 291, at minimum, but
potentially more.
Response: Due to differences in the definitions of the two industry
segments, the EPA disagrees that the number of reporters in the Onshore
Petroleum and Natural Gas Gathering and Boosting segment should match
the number of reporters in the Onshore Natural Gas Processing segment.
The EPA estimate of 200 respondents was based on the regulatory
analysis for Office of Pipeline Safety (OPS) safety regulations. In the
analysis, it was estimated that 50 percent of the 400 natural gas
gathering pipeline operators under regulation are small entities
operating small diameter, low pressure (Type B) gathering lines and
fifty percent are large diameter, high pressure lines (Type A)
potentially subject to the safety regulation (depending upon proximity
to population centers).\11\
---------------------------------------------------------------------------
\11\ U.S. Department of Transportation. Pipeline and Hazardous
Materials Safety Administration. Draft Regulatory Evaluation,
Regulated Natural Gas Gathering Lines, Regulatory Analysis, Docket
RSPA-1998-4868. Available at www.viadata.com/pipeliner/library_docs/Gatheringanalysis.pdf.
---------------------------------------------------------------------------
Comment: One commenter noted that the EPA estimated that there are
150 reporters for Onshore Natural Gas Transmission Pipeline facilities
at proposal. However, the commenter stated that the EPA should expect
183 reporters in the segment based on the number of operators that are
required to complete a PHMSA annual report (PHMSA F-7100-2) or are
regulated by FERC under section 311 of the NGPA.
Response: The EPA agrees with the suggested change. The preamble to
the final amendments, the final Supporting Statement, and the
memorandum ``Assessment of Impacts of the 2015 Final Revisions to
Subpart W'' (see Docket ID No. EPA-HQ-OAR-2014-0831) have been updated
to reflect the change from 150 reporters to 183 reporters in the
Onshore Natural Gas Transmission Pipeline segment.
Comment: Two commenters objected to the collection of well
identification numbers. One commenter noted that collection would
require significant resources and would be unduly burdensome on
operators. The other commenter stated that the burdens associated with
collecting and reporting this data far outweigh any minimal benefits in
data quality.
Response: The EPA is finalizing the well identification number
reporting requirements for well-specific data as proposed, but the EPA
is not requiring well identification numbers to be reported in this
rulemaking for equipment other than wells. See section II.D of this
preamble for additional discussion responding to this comment.
V. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is not a significant regulatory action and was
therefore not submitted to the Office of Management and Budget (OMB)
for review.
In addition, the EPA prepared an analysis of the potential costs
associated with the final amendments to subpart W. This analysis is
contained in the memorandum ``Assessment of Impacts of the 2015 Final
Revisions to Subpart W.'' A copy of the analysis is available in the
docket for this action (see Docket ID No. EPA-HQ-OAR-2014-0831) and the
analysis is briefly summarized in section IV of this preamble.
B. Paperwork Reduction Act (PRA)
The information collection activities in this rule have been
submitted for approval to the OMB under the PRA. The Information
Collection Request (ICR) document that the EPA prepared has been
assigned EPA ICR number 2300.16. You can find a copy of the ICR in the
docket for this rule, and it is briefly summarized here. The
information collection requirements are not enforceable until OMB
approves them.
This action adds monitoring and reporting requirements for
reporters in three industry segments: Onshore Petroleum and Natural Gas
Production, Onshore Petroleum and Natural Gas Gathering and Boosting,
and Onshore Natural Gas Transmission Pipeline. Data collection
complements the Inventory of U.S. Greenhouse Gas Emissions and Sinks
(Inventory) and provides a critical tool for communities to identify
nearby sources of GHGs and provide information to state and local
governments. The data can be used to complement atmospheric GHG studies
and inform updates to emission inventories. Various activity data are
collected that can be used to improve understanding of the occurrence
of emissions from a variety of sources.
Data collected must be made available to the public unless the data
qualify for CBI treatment under the CAA and EPA regulations. All data
determined by the EPA to be CBI are safeguarded in accordance with
regulations in 40 CFR chapter 1, part 2, subpart B.
Respondents/Affected Entities: The respondents in this information
collection include owners and operators of petroleum and natural gas
systems facilities that must report their GHG emissions to the EPA to
comply with subpart W of part 98.
Respondent's Obligation To Respond: The respondent's obligation to
respond is mandatory under the authority provided in CAA section 114.
Estimated Number of Respondents: Approximately 3,300 respondents
per year.
Frequency of Response: Annual.
Total Estimated Burden: 317,100 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total Estimated Cost: $29.2 million (per year), includes $1.1
million annualized capital and 2.8 million operation & maintenance
costs.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB
approves this ICR, the Agency will announce that approval in the
Federal Register and publish a technical amendment to 40 CFR part 9 to
display the OMB control number for the approved information collection
activities contained in this final rule.
C. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. The
small entities
[[Page 64283]]
subject to the requirements of this action are: (1) A small business as
defined by the Small Business Administration's regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
The Agency has determined that a few small businesses may
experience an insignificant impact. Details of this analysis are
presented in section IV.B of the preamble to the proposed amendments
(79 FR 76267; December 9, 2014).
Although this final rule will not have a significant economic
impact on a substantial number of small entities, the EPA nonetheless
has tried to reduce the impact of this rule on small entities. As part
of the process of finalizing the subpart W 2010 final rule, the EPA
took several steps to evaluate the effect of the rule on small
entities. For example, the EPA determined appropriate thresholds that
reduced the number of small businesses reporting. In addition, the EPA
supports a ``help desk'' for the rule, which is available to answer
questions on the provisions in the rule. Finally, the EPA continues to
conduct significant outreach on the GHG reporting rule and maintains an
``open door'' policy for stakeholders to help inform the EPA's
understanding of key issues for the industries.
D. Unfunded Mandates Reform Act (UMRA)
This action does not contain an unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments. This action imposes
no enforceable duty on any state, local, or tribal governments or the
private sector.
E. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action has tribal implications. However, it will neither
impose substantial direct compliance costs on federally recognized
tribal governments, nor preempt tribal law. This regulation will apply
directly to petroleum and natural gas facilities that emit GHGs.
Although few facilities that will be subject to the rule are likely to
be owned by tribal governments, the EPA has sought opportunities to
provide information to tribal governments and representatives during
the development of the proposed and final subpart W that was
promulgated on November 30, 2010 (75 FR 74458).
The EPA consulted with tribal officials under the EPA Policy on
Consultation and Coordination with Indian Tribes early in the process
of developing this regulation to permit them to have meaningful and
timely input into its development. A summary of that consultation is
provided in section IV.F of the preamble to the re-proposal of subpart
W published on April 12, 2010 (75 FR 18608), and section IV.F of the
preamble to the subpart W 2010 final rule published on November 30,
2010 (75 FR 74458).
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern environmental health or safety risks,
that the EPA has reason to believe may disproportionately affect
children, per the definition of ``covered regulatory action'' in
section 2-202 of the Executive Order. This action is not subject to
Executive Order 13045 because it does not concern an environmental
health risk or safety risks.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This action is not subject to Executive Order 13211, because it is
not a significant regulatory action under Executive Order 12866.
I. National Technology Transfer and Advancement Act (NTTAA)
This rulemaking does not involve technical standards.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
The EPA believes the human health or environmental risk addressed
by this action will not have potential disproportionately high and
adverse human health or environmental effects on minority, low-income
or indigenous populations because it does not affect the level of
protection provided to human health or the environment. Instead, this
rule addresses information collection and reporting procedures.
K. Congressional Review Act (CRA)
This action is subject to the CRA, and the EPA will submit a rule
report to each House of the Congress and to the Comptroller General of
the United States. This action is not a ``major rule'' as defined by 5
U.S.C. 804(2).
List of Subjects in 40 CFR Part 98
Environmental protection, Administrative practice and procedure,
Greenhouse gases, Reporting and recordkeeping requirements.
Dated: October 1, 2015.
Gina McCarthy,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is amended as follows:
PART 98--MANDATORY GREENHOUSE GAS REPORTING
0
1. The authority citation for part 98 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart W--Petroleum and Natural Gas Systems
0
2. Section 98.230 is amended by adding paragraphs (a)(9) and (10) to
read as follows:
Sec. 98.230 Definition of the source category.
(a) * * *
(9) Onshore petroleum and natural gas gathering and boosting.
Onshore petroleum and natural gas gathering and boosting means
gathering pipelines and other equipment used to collect petroleum and/
or natural gas from onshore production gas or oil wells and used to
compress, dehydrate, sweeten, or transport the petroleum and/or natural
gas to a natural gas processing facility, a natural gas transmission
pipeline or to a natural gas distribution pipeline. Gathering and
boosting equipment includes, but is not limited to gathering pipelines,
separators, compressors, acid gas removal units, dehydrators, pneumatic
devices/pumps, storage vessels, engines, boilers, heaters, and flares.
Gathering and boosting equipment does not include equipment reported
under any other industry segment defined in this section. Gathering
pipelines operating on a vacuum and gathering pipelines with a GOR)
less than 300 standard cubic feet per stock tank barrel (scf/STB) are
not included in this industry segment (oil
[[Page 64284]]
here refers to hydrocarbon liquids of all API gravities).
(10) Onshore natural gas transmission pipeline. Onshore natural gas
transmission pipeline means all natural gas transmission pipelines as
defined in Sec. 98.238.
* * * * *
0
3. Section 98.231 is amended by revising paragraph (a) to read as
follows:
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), except for the industry
segments in paragraphs (a)(1) through (4) of this section.
(1) Facilities must report emissions from the onshore petroleum and
natural gas production industry segment only if emission sources
specified in Sec. 98.232(c) emit 25,000 metric tons of CO2
equivalent or more per year.
(2) Facilities must report emissions from the natural gas
distribution industry segment only if emission sources specified in
Sec. 98.232(i) emit 25,000 metric tons of CO2 equivalent or
more per year.
(3) Facilities must report emissions from the onshore petroleum and
natural gas gathering and boosting industry segment only if emission
sources specified in Sec. 98.232(j) emit 25,000 metric tons of
CO2 equivalent or more per year.
(4) Facilities must report emissions from the onshore natural gas
transmission pipeline industry segment only if emission sources
specified in Sec. 98.232(m) emit 25,000 metric tons of CO2
equivalent or more per year.
* * * * *
0
4. Section 98.232 is amended by:
0
a. Revising paragraphs (a) and (c)(6) and (8);
0
b. Adding paragraph (j);
0
c. Revising paragraph (k); and
0
d. Adding paragraph (m).
The revisions and additions read as follows:
Sec. 98.232 GHGs to report.
(a) You must report CO2, CH4, and
N2O emissions from each industry segment specified in
paragraphs (b) through (j) and (m) of this section, CO2,
CH4, and N2O emissions from each flare as
specified in paragraphs (b) through (j) of this section, and stationary
and portable combustion emissions as applicable as specified in
paragraph (k) of this section.
* * * * *
(c) * * *
(6) Well venting during well completions with hydraulic fracturing
that have a GOR of 300 scf/STB or greater (oil here refers to
hydrocarbon liquids produced of all API gravities).
* * * * *
(8) Well venting during well workovers with hydraulic fracturing
that have a GOR of 300 scf/STB or greater (oil here refers to
hydrocarbon liquids produced of all API gravities).
* * * * *
(j) For an onshore petroleum and natural gas gathering and boosting
facility, report CO2, CH4, and N2O
emissions from the following source types:
(1) Natural gas pneumatic device venting.
(2) Natural gas driven pneumatic pump venting.
(3) Acid gas removal vents.
(4) Dehydrator vents.
(5) Blowdown vent stacks.
(6) Storage tank vented emissions.
(7) Flare stack emissions.
(8) Centrifugal compressor venting.
(9) Reciprocating compressor venting.
(10) 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).
(11) Gathering pipeline equipment leaks.
(12) You must use the methods in Sec. 98.233(z) and report under
this subpart the emissions of CO2, CH4, and
N2O from stationary or portable fuel combustion equipment
that cannot move on roadways under its own power and drive train, and
that is located at an onshore petroleum and natural gas gathering and
boosting facility as defined in Sec. 98.238. Stationary or portable
equipment includes the following equipment, which are integral to the
movement of natural gas: Natural gas dehydrators, natural gas
compressors, electrical generators, steam boilers, and process heaters.
(k) Report under subpart C of this part (General Stationary Fuel
Combustion Sources) the emissions of CO2, CH4,
and N2O from each stationary fuel combustion unit by
following the requirements of subpart C except for facilities under
onshore petroleum and natural gas production, onshore petroleum and
natural gas gathering and boosting, and natural gas distribution.
Onshore petroleum and natural gas production facilities must report
stationary and portable combustion emissions as specified in paragraph
(c) of this section. Natural gas distribution facilities must report
stationary combustion emissions as specified in paragraph (i) of this
section. Onshore petroleum and natural gas gathering and boosting
facilities must report stationary and portable combustion emissions as
specified in paragraph (j) of this section.
* * * * *
(m) For onshore natural gas transmission pipeline, report pipeline
blowdown CO2 and CH4 emissions from blowdown vent
stacks.
0
5. Section 98.233 is amended by:
0
a. Revising the parameters ``EFt'' and ``GHGi''
of Equation W-1 in paragraph (a);
0
b. Revising paragraph (a)(2);
0
c. Revising the parameter ``EF'' of Equation W-2 in paragraph (c);
0
d. Revising paragraph (d)(8)(iii);
0
e. Revising paragraphs (g) introductory text, (g)(1) introductory text,
(g)(1)(i), and paragraph (g)(1)(ii) heading;
0
f. Revising the parameters ``FRMs,'' ``FRs,p''
and ``PRs,p'' of Equation W-12A in paragraph (g)(1)(iii);
0
g. Revising the parameters ``FRMi,'' and
``PRs,p'' of Equation W-12B in paragraph (g)(1)(iv);
0
h. Revising paragraphs (g)(1)(v) and (vi);
0
i. Adding paragraph (g)(1)(vii);
0
j. Revising paragraph (g)(2) introductory text;
0
k. Adding paragraph (g)(2)(iv);
0
l. Revising paragraph (g)(4) introductory text;
0
m. Revising paragraph (i)(2) introductory text;
0
n. Revising the parameters ``Ta'' and ``Pa'' of
Equation W-14A in paragraph (i)(2)(i);
0
o. Revising paragraphs (j) introductory text, (j)(1) through (3), and
(j)(6);
0
p. Revising paragraph (n)(2)(i);
0
q. Revising paragraphs (o) introductory text and (o)(10);
0
r. Revising paragraphs (p) introductory text and (p)(10);
0
s. Revising paragraphs (r) introductory text, (r)(2) introductory text,
and (r)(2)(i);
0
t. Revising paragraphs (u)(2)(i) and (iii); and
0
x. Revising paragraphs (z) introductory text and (z)(1)(ii).
The revisions and additions read as follows:
Sec. 98.233 Calculating GHG emissions.
* * * * *
(a) * * *
* * * * *
EFt = Population emission factors for natural gas
pneumatic device vents (in standard cubic feet per hour per device)
of each type ``t'' listed in Tables W-1A, W-3, and W-4 of this
subpart for onshore petroleum and natural gas production,
[[Page 64285]]
onshore natural gas transmission compression, and underground
natural gas storage facilities, respectively. Onshore petroleum and
natural gas gathering and boosting facilities must use the
population emission factors listed in Table W-1A of this subpart.
GHGi = For onshore petroleum and natural gas production
facilities, onshore petroleum and natural gas gathering and boosting
facilities, onshore natural gas transmission compression facilities,
and underground natural gas storage facilities, concentration of
GHGi, CH4 or CO2, in produced
natural gas or processed natural gas for each facility as specified
in paragraphs (u)(2)(i), (iii), and (iv) of this section.
* * * * *
(2) For the onshore petroleum and natural gas production industry
segment, you have the option in the first two consecutive calendar
years to determine ``Countt'' for Equation W-1 of this
section for each type of natural gas pneumatic device (continuous high
bleed, continuous low bleed, and intermittent bleed) using engineering
estimates based on best available data. For the onshore petroleum and
natural gas gathering and boosting industry segment, you have the
option in the first two consecutive calendar years to determine
``Countt'' for Equation W-1 for each type of natural gas
pneumatic device (continuous high bleed, continuous low bleed, and
intermittent bleed) using engineering estimates based on best available
data.
* * * * *
(c) * * *
* * * * *
EF = Population emissions factors for natural gas driven pneumatic
pumps (in standard cubic feet per hour per pump) listed in Table W-
1A of this subpart for onshore petroleum and natural gas production
and onshore petroleum and natural gas gathering and boosting
facilities.
* * * * *
(d) * * *
(8) * * *
(iii) If a continuous gas analyzer is not available or installed,
you may use the outlet pipeline quality specification for
CO2 in natural gas.
* * * * *
(g) Well venting during completions and workovers with hydraulic
fracturing. Calculate annual volumetric natural gas emissions from gas
well and oil well venting during completions and workovers involving
hydraulic fracturing using Equation W-10A or Equation W-10B of this
section. Equation W-10A applies to well venting when the gas flowback
rate is measured from a specified number of example completions or
workovers and Equation W-10B applies when the gas flowback vent or
flare volume is measured for each completion or workover. Completion
and workover activities are separated into two periods, an initial
period when flowback is routed to open pits or tanks and a subsequent
period when gas content is sufficient to route the flowback to a
separator or when the gas content is sufficient to allow measurement by
the devices specified in paragraph (g)(1) of this section, regardless
of whether a separator is actually utilized. If you elect to use
Equation W-10A, you must follow the procedures specified in paragraph
(g)(1). If you elect to use Equation W-10B, you must use a recording
flow meter installed on the vent line, downstream of a separator and
ahead of a flare or vent, to measure the gas flowback. For either
equation, emissions must be calculated separately for completions and
workovers, for each sub-basin, and for each well type combination
identified in paragraph (g)(2) of this section. You must calculate
CH4 and CO2 volumetric and mass emissions as
specified in paragraph (g)(3) of this section. If emissions from well
venting during completions and workovers with hydraulic fracturing are
routed to a flare, you must calculate CH4, CO2,
and N2O annual emissions as specified in paragraph (g)(4) of
this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.007
Where:
Es,n = Annual volumetric natural gas emissions in
standard cubic feet from gas venting during well completions or
workovers following hydraulic fracturing for each sub-basin and well
type combination.
W = Total number of wells completed or worked over using hydraulic
fracturing in a sub-basin and well type combination.
Tp,s = Cumulative amount of time of flowback, after
sufficient quantities of gas are present to enable separation, where
gas vented or flared for the completion or workover, in hours, for
each well, p, in a sub-basin and well type combination during the
reporting year. This may include non-contiguous periods of venting
or flaring.
Tp,i = Cumulative amount of time of flowback to open
tanks/pits, from when gas is first detected until sufficient
quantities of gas are present to enable separation, for the
completion or workover, in hours, for each well, p, in a sub-basin
and well type combination during the reporting year. This may
include non-contiguous periods of routing to open tanks/pits but
does not include periods when the oil well ceases to produce fluids
to the surface.
FRMs = Ratio of average gas flowback, during the period
when sufficient quantities of gas are present to enable separation,
of well completions and workovers from hydraulic fracturing to 30-
day production rate for the sub-basin and well type combination,
calculated using procedures specified in paragraph (g)(1)(iii) of
this section.
FRMi = Ratio of initial gas flowback rate during well
completions and workovers from hydraulic fracturing to 30-day gas
production rate for the sub-basin and well type combination,
calculated using procedures specified in paragraph (g)(1)(iv) of
this section, for the period of flow to open tanks/pits.
PRs,p = Average gas production flow rate during the first
30 days of production after completions of newly drilled wells or
well workovers using hydraulic fracturing in standard cubic feet per
hour of each well p, that was measured in the sub-basin and well
type combination. If applicable, PRs,p may be calculated
for oil wells using procedures specified in paragraph (g)(1)(vii) of
this section.
EnFs,p = Volume of N2 injected gas in cubic
feet at standard conditions that was injected into the reservoir
during an energized fracture job or during flowback for each well,
p, as determined by using an appropriate meter according to methods
described in Sec. 98.234(b), or by using receipts of gas purchases
that are used for the energized fracture job or injection during
flowback. Convert to standard conditions using paragraph (t) of this
section. If the fracture process did
[[Page 64286]]
not inject gas into the reservoir or if the injected gas is
CO2 then EnFs,p is 0.
FVs,p = Flow volume of vented or flared gas for each
well, p, in standard cubic feet measured using a recording flow
meter (digital or analog) on the vent line to measure gas flowback
during the separation period of the completion or workover according
to methods set forth in Sec. 98.234(b).
FRp,i = Flow rate vented or flared of each well, p, in
standard cubic feet per hour measured using a recording flow meter
(digital or analog) on the vent line to measure the flowback, at the
beginning of the period of time when sufficient quantities of gas
are present to enable separation, of the completion or workover
according to methods set forth in Sec. 98.234(b).
(1) If you elect to use Equation W-10A of this section on gas
wells, you must use Calculation Method 1 as specified in paragraph
(g)(1)(i) of this section, or Calculation Method 2 as specified in
paragraph (g)(1)(ii) of this section, to determine the value of
FRMs and FRMi. If you elect to use Equation W-10A
of this section on oil wells, you must use Calculation Method 1 as
specified in paragraph (g)(1)(i) to determine the value of
FRMs and FRMi. These values must be based on the
flow rate for flowback gases, once sufficient gas is present to enable
separation. The number of measurements or calculations required to
estimate FRMs and FRMi must be determined
individually for completions and workovers per sub-basin and well type
combination as follows: Complete measurements or calculations for at
least one completion or workover for less than or equal to 25
completions or workovers for each well type combination within a sub-
basin; complete measurements or calculations for at least two
completions or workovers for 26 to 50 completions or workovers for each
sub-basin and well type combination; complete measurements or
calculations for at least three completions or workovers for 51 to 100
completions or workovers for each sub-basin and well type combination;
complete measurements or calculations for at least four completions or
workovers for 101 to 250 completions or workovers for each sub-basin
and well type combination; and complete measurements or calculations
for at least five completions or workovers for greater than 250
completions or workovers for each sub-basin and well type combination.
(i) Calculation Method 1. You must use Equation W-12A of this
section as specified in paragraph (g)(1)(iii) of this section to
determine the value of FRMs. You must use Equation W-12B of
this section as specified in paragraph (g)(1)(iv) of this section to
determine the value of FRMi. The procedures specified in
paragraphs (g)(1)(v) and (vi) of this section also apply. When making
gas flowback measurements for use in Equations W-12A and W-12B of this
section, you must use a recording flow meter (digital or analog)
installed on the vent line, downstream of a separator and ahead of a
flare or vent, to measure the gas flowback rates in units of standard
cubic feet per hour according to methods set forth in Sec. 98.234(b).
(ii) Calculation Method 2 (for gas wells). * * *
(iii) * * *
* * * * *
FRMs = Ratio of average gas flowback rate, during the
period of time when sufficient quantities of gas are present to
enable separation, of well completions and workovers from hydraulic
fracturing to 30-day gas production rate for each sub-basin and well
type combination.
FRs,p = Measured average gas flowback rate from
Calculation Method 1 described in paragraph (g)(1)(i) of this
section or calculated average flowback rate from Calculation Method
2 described in paragraph (g)(1)(ii) of this section, during the
separation period in standard cubic feet per hour for well(s) p for
each sub-basin and well type combination. Convert measured and
calculated FRa values from actual conditions upstream of
the restriction orifice (FRa) to standard conditions
(FRs,p) for each well p using Equation W-33 in paragraph
(t) of this section. You may not use flow volume as used in Equation
W-10B of this section converted to a flow rate for this parameter.
PRs,p = Average gas production flow rate during the first
30 days of production after completions of newly drilled wells or
well workovers using hydraulic fracturing, in standard cubic feet
per hour for each well, p, that was measured in the sub-basin and
well type combination. For oil wells for which production is not
measured continuously during the first 30 days of production, the
average flow rate may be based on individual well production tests
conducted within the first 30 days of production. Alternatively, if
applicable, PRs,p may be calculated for oil wells using
procedures specified in paragraph (g)(1)(vii) of this section.
* * * * *
(iv) * * *
* * * * *
FRMi = Ratio of initial gas flowback rate during well
completions and workovers from hydraulic fracturing to 30-day gas
production rate for the sub-basin and well type combination, for the
period of flow to open tanks/pits.
* * * * *
PRs,p = Average gas production flow rate during the first
30-days of production after completions of newly drilled wells or
well workovers using hydraulic fracturing, in standard cubic feet
per hour of each well, p, that was measured in the sub-basin and
well type combination. For oil wells for which production is not
measured continuously during the first 30 days of production, the
average flow rate may be based on individual well production tests
conducted within the first 30 days of production. Alternatively, if
applicable, PRs,p may be calculated for oil wells using
procedures specified in paragraph (g)(1)(vii) of this section.
* * * * *
(v) For Equation W-10A of this section, the ratio of gas flowback
rate during well completions and workovers from hydraulic fracturing to
30-day gas production rate are applied to all well completions and well
workovers, respectively, in the sub-basin and well type combination for
the total number of hours of flowback and for the first 30 day average
gas production rate for each of these wells.
(vi) For Equations W-12A and W-12B of this section, calculate new
flowback rates for well completions and well workovers in each sub-
basin and well type combination once every two years starting in the
first calendar year of data collection.
(vii) For oil wells where the gas production rate is not metered
and you elect to use Equation W-10A of this section, calculate the
average gas production rate (PRs,p) using Equation W-12C of
this section. If GOR cannot be determined from your available data,
then you must use one of the procedures specified in paragraph
(g)(1)(vii)(A) or (B) of this section to determine GOR. If GOR from
each well is not available, use the GOR from a cluster of wells in the
same sub-basin category.
[GRAPHIC] [TIFF OMITTED] TR22OC15.008
[[Page 64287]]
Where:
PRs,p = Average gas production flow rate during the first
30 days of production after completions of newly drilled wells or
well workovers using hydraulic fracturing in standard cubic feet per
hour of well p, in the sub-basin and well type combination.
GORp = Average gas to oil ratio during the first 30 days
of production after completions of newly drilled wells or workovers
using hydraulic fracturing in standard cubic feet of gas per barrel
of oil for each well p, that was measured in the sub-basin and well
type combination; oil here refers to hydrocarbon liquids produced of
all API gravities.
Vp = Volume of oil produced during the first 30 days of
production after completions of newly drilled wells or well
workovers using hydraulic fracturing in barrels of each well p, that
was measured in the sub-basin and well type combination.
720 = Conversion from 30 days of production to hourly production
rate.
(A) You may use an appropriate standard method published by a
consensus-based standards organization if such a method exists.
(B) You may use an industry standard practice as described in Sec.
98.234(b).
(2) For paragraphs (g) introductory text and (g)(1) of this
section, measurements and calculations are completed separately for
workovers and completions per sub-basin and well type combination. A
well type combination is a unique combination of the parameters listed
in paragraphs (g)(2)(i) through (iv) of this section.
* * * * *
(iv) Oil well or gas well.
* * * * *
(4) Calculate annual emissions from well venting during well
completions and workovers from hydraulic fracturing where all or a
portion of the gas is flared as specified in paragraphs (g)(4)(i) and
(ii) of this section.
* * * * *
(i) * * *
(2) Method for determining emissions from blowdown vent stacks
according to equipment or event type. If you elect to determine
emissions according to each equipment or event type, using unique
physical volumes as calculated in paragraph (i)(1) of this section, you
must calculate emissions as specified in paragraph (i)(2)(i) of this
section and either paragraph (i)(2)(ii) or, if applicable, paragraph
(i)(2)(iii) of this section for each equipment or event type. For
industry segments other than onshore natural gas transmission pipeline,
equipment or event types must be grouped into the following seven
categories: Facility piping (i.e., piping within the facility boundary
other than physical volumes associated with distribution pipelines),
pipeline venting (i.e., physical volumes associated with distribution
pipelines vented within the facility boundary), compressors, scrubbers/
strainers, pig launchers and receivers, emergency shutdowns (this
category includes emergency shutdown blowdown emissions regardless of
equipment type), and all other equipment with a physical volume greater
than or equal to 50 cubic feet. If a blowdown event resulted in
emissions from multiple equipment types and the emissions cannot be
apportioned to the different equipment types, then categorize the
blowdown event as the equipment type that represented the largest
portion of the emissions for the blowdown event. For the onshore
natural gas transmission pipeline segment, pipeline segments or event
types must be grouped into the following eight categories: Pipeline
integrity work (e.g., the preparation work of modifying facilities,
ongoing assessments, maintenance or mitigation), traditional operations
or pipeline maintenance, equipment replacement or repair (e.g.,
valves), pipe abandonment, new construction or modification of
pipelines including commissioning and change of service, operational
precaution during activities (e.g. excavation near pipelines),
emergency shutdowns including pipeline incidents as defined in 49 CFR
191.3, and all other pipeline segments with a physical volume greater
than or equal to 50 cubic feet. If a blowdown event resulted in
emissions from multiple categories and the emissions cannot be
apportioned to the different categories, then categorize the blowdown
event in the category that represented the largest portion of the
emissions for the blowdown event.
(i) * * *
* * * * *
Ta = Temperature at actual conditions in the unique
physical volume ([deg]F). For emergency blowdowns at onshore
petroleum and natural gas gathering and boosting facilities,
engineering estimates based on best available information may be
used to determine the temperature.
* * * * *
Pa = Absolute pressure at actual conditions in the unique
physical volume (psia). For emergency blowdowns at onshore petroleum
and natural gas gathering and boosting facilities, engineering
estimates based on best available information may be used to
determine the pressure.
* * * * *
(j) Onshore production and onshore petroleum and natural gas
gathering and boosting storage tanks. Calculate CH4,
CO2, and N2O (when flared) emissions from
atmospheric pressure fixed roof storage tanks receiving hydrocarbon
produced liquids from onshore petroleum and natural gas production
facilities and onshore petroleum and natural gas gathering and boosting
facilities (including stationary liquid storage not owned or operated
by the reporter), as specified in this paragraph (j). For gas-liquid
separators or onshore petroleum and natural gas gathering and boosting
non-separator equipment (e.g., stabilizers, slug catchers) with annual
average daily throughput of oil greater than or equal to 10 barrels per
day, calculate annual CH4 and CO2 using
Calculation Method 1 or 2 as specified in paragraphs (j)(1) and (2) of
this section. For wells flowing directly to atmospheric storage tanks
without passing through a separator with throughput greater than or
equal to 10 barrels per day, calculate annual CH4 and
CO2 emissions using Calculation Method 2 as specified in
paragraph (j)(2) of this section. For hydrocarbon liquids flowing to
gas-liquid separators or non-separator equipment or directly to
atmospheric storage tanks with throughput less than 10 barrels per day,
use Calculation Method 3 as specified in paragraph (j)(3) of this
section. If you use Calculation Method 1 or Calculation Method 2 for
separators, you must also calculate emissions that may have occurred
due to dump valves not closing properly using the method specified in
paragraph (j)(6) of this section. If emissions from atmospheric
pressure fixed roof storage tanks are routed to a vapor recovery
system, you must adjust the emissions downward according to paragraph
(j)(4) of this section. If emissions from atmospheric pressure fixed
roof storage tanks are routed to a flare, you must calculate
CH4, CO2, and N2O annual emissions as
specified in paragraph (j)(5) of this section.
(1) Calculation Method 1. Calculate annual CH4 and
CO2 emissions from onshore production storage tanks and
onshore petroleum and natural gas gathering and boosting storage tanks
using operating conditions in the last gas-liquid separator or non-
separator equipment before liquid transfer to storage tanks. Calculate
flashing emissions with a software program, such as AspenTech
HYSYS[supreg] or API 4697 E&P Tank, that uses the Peng-Robinson
equation of state, models flashing emissions, and speciates
CH4 and CO2 emissions that will result when the
oil from the separator or non-separator equipment enters an atmospheric
pressure storage tank. The following parameters must be determined for
typical operating
[[Page 64288]]
conditions over the year by engineering estimate and process knowledge
based on best available data, and must be used at a minimum to
characterize emissions from liquid transferred to tanks:
(i) Separator or non-separator equipment temperature.
(ii) Separator or non-separator equipment 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 or non-separator equipment oil composition and Reid
vapor pressure. If this data is not available, determine these
parameters by using one of the methods described in paragraphs
(j)(1)(vii)(A) through (C) of this section.
(A) If separator or non-separator equipment oil composition and
Reid vapor pressure default data are provided with the software
program, select the default values that most closely match your
separator or non-separator equipment pressure first, and API gravity
secondarily.
(B) If separator or non-separator equipment oil composition and
Reid vapor pressure data are available through your previous analysis,
select the latest available analysis that is representative of produced
crude oil or condensate from the sub-basin category for onshore
petroleum and natural gas production or from the county for onshore
petroleum and natural gas gathering and boosting.
(C) Analyze a representative sample of separator or non-separator
equipment oil in each sub-basin category for onshore petroleum and
natural gas production or each county for onshore petroleum and natural
gas gathering and boosting for oil composition and Reid vapor pressure
using an appropriate standard method published by a consensus-based
standards organization.
(2) Calculation Method 2. Calculate annual CH4 and
CO2 emissions using the methods in paragraph (j)(2)(i) of
this section for gas-liquid separators with annual average daily
throughput of oil greater than or equal to 10 barrels per day.
Calculate annual CH4 and CO2 emissions using the
methods in paragraph (j)(2)(ii) of this section for wells with annual
average daily oil production greater than or equal to 10 barrels per
day that flow directly to atmospheric storage tanks in onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting (if applicable). Calculate annual
CH4 and CO2 emissions using the methods in
paragraph (j)(2)(iii) of this section for non-separator equipment with
annual average daily hydrocarbon liquids throughput greater than or
equal to 10 barrels per day that flow directly to atmospheric storage
tanks in onshore petroleum and natural gas gathering and boosting.
(i) Flow to storage tank after passing through a separator. Assume
that all of the CH4 and 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)
to sample and analyze separator oil composition at separator pressure
and temperature.
(ii) Flow to storage tank direct from wells. Calculate
CH4 and CO2 emissions using either of the methods
in paragraph (j)(2)(ii)(A) or (B) of this section.
(A) If well production oil and gas compositions are available
through a previous analysis, select the latest available analysis that
is representative of produced oil and gas from the sub-basin category
and assume all of the CH4 and CO2 in both oil and
gas are emitted from the tank.
(B) 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 the 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.
(iii) Flow to storage tank direct from non-separator equipment.
Calculate CH4 and CO2 emissions using either of
the methods in paragraph (j)(2)(iii)(A) or (B) of this section.
(A) If other non-separator equipment liquid and gas compositions
are available through a previous analysis, select the latest available
analysis that is representative of liquid and gas from non-separator
equipment in the same county and assume all of the CH4 and
CO2 in both hydrocarbon liquids and gas are emitted from the
tank.
(B) If non-separator equipment liquid and gas compositions are not
available, use default liquid and gas compositions in software
programs, such as API 4697 E&P Tank, that most closely match the non-
separator equipment gas/liquid ratio and API gravity and assume all of
the CH4 and CO2 in both hydrocarbon liquids and
gas are emitted from the tank.
(3) Calculation Method 3. Calculate CH4 and
CO2 emissions using Equation W-15 of this section:
[GRAPHIC] [TIFF OMITTED] TR22OC15.009
Where:
Es,i = Annual total volumetric GHG emissions (either
CO2 or CH4) at standard conditions in cubic
feet.
EFi = Population emission factor for separators, wells,
or non-separator equipment in thousand standard cubic feet per
separator, well, or non-separator equipment per year, for crude oil
use 4.2 for CH4 and 2.8 for CO2 at
60[emsp14][deg]F and 14.7 psia, and for gas condensate use 17.6 for
CH4 and 2.8 for CO2 at 60 [deg]F and 14.7
psia.
Count = Total number of separators, wells, or non-separator
equipment with annual average daily throughput less than 10 barrels
per day. Count only separators, wells, or non-separator equipment
that feed oil directly to the storage tank.
1,000 = Conversion from thousand standard cubic feet to standard
cubic feet.
* * * * *
(6) If you use Calculation Method 1 or Calculation Method 2 in
paragraph (j)(1) or (2) of this section, calculate emissions from
occurrences of gas-liquid separator liquid dump valves not closing
during the calendar year by using Equation W-16 of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.010
[[Page 64289]]
Where:
Es,i,o = Annual volumetric GHG emissions at standard
conditions from each storage tank in cubic feet that resulted from
the dump valve on the gas-liquid separator not closing properly.
En = Storage tank emissions as determined in paragraphs
(j)(1), (j)(2) and, if applicable, (j)(4) of this section in
standard cubic feet per year.
Tn = Total time a dump valve is not closing properly in
the calendar year in hours. Estimate Tn based on
maintenance, operations, or routine separator inspections that
indicate the period of time when the valve was malfunctioning in
open or partially open position.
CFn = Correction factor for tank emissions for time
period Tn is 2.87 for crude oil production. Correction
factor for tank emissions for time period Tn is 4.37 for
gas condensate production.
8,760 = Conversion to hourly emissions.
* * * * *
(n) * * *
(2) * * *
(i) For onshore natural gas production and onshore petroleum and
natural gas gathering and boosting, determine the GHG mole fraction
using paragraph (u)(2)(i) of this section.
* * * * *
(o) Centrifugal compressor venting. If you are required to report
emissions from centrifugal compressor venting as specified in Sec.
98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct
volumetric emission measurements specified in paragraph (o)(1) of this
section using methods specified in paragraphs (o)(2) through (5) of
this section; perform calculations specified in paragraphs (o)(6)
through (9) of this section; and calculate CH4 and
CO2 mass emissions as specified in paragraph (o)(11) of this
section. If emissions from a compressor source are routed to a flare,
paragraphs (o)(1) through (11) do not apply and instead you must
calculate CH4, CO2, and N2O emissions
as specified in paragraph (o)(12) of this section. If emissions from a
compressor source are captured for fuel use or are routed to a thermal
oxidizer, paragraphs (o)(1) through (12) do not apply and instead you
must calculate and report emissions as specified in subpart C of this
part. If emissions from a compressor source are routed to vapor
recovery, paragraphs (o)(1) through (12) do not apply. If you are
required to report emissions from centrifugal compressor venting at an
onshore petroleum and natural gas production facility as specified in
Sec. 98.232(c)(19) or an onshore petroleum and natural gas gathering
and boosting facility as specified in Sec. 98.232(j)(8), you must
calculate volumetric emissions as specified in paragraph (o)(10); and
calculate CH4 and CO2 mass emissions as specified
in paragraph (o)(11).
* * * * *
(10) Method for calculating volumetric GHG emissions from wet seal
oil degassing vents at an onshore petroleum and natural gas production
facility or an onshore petroleum and natural gas gathering and boosting
facility. You must calculate emissions from centrifugal compressor wet
seal oil degassing vents at an onshore petroleum and natural gas
production facility or an onshore petroleum and natural gas gathering
and boosting facility using Equation W-25 of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.011
Where:
Es,i = Annual volumetric GHGi (either
CH4 or CO2) emissions from centrifugal
compressor wet seals, at standard conditions, in cubic feet.
Count = Total number of centrifugal compressors that have wet seal
oil degassing vents.
EFi,s = Emission factor for GHGi. Use 1.2 x
10\7\ standard cubic feet per year per compressor for CH4
and 5.30 x 10\5\ standard cubic feet per year per compressor for
CO2 at 60 [deg]F and 14.7 psia.
* * * * *
(p) Reciprocating compressor venting. If you are required to report
emissions from reciprocating compressor venting as specified in Sec.
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct
volumetric emission measurements specified in paragraph (p)(1) of this
section using methods specified in paragraphs (p)(2) through (5) of
this section; perform calculations specified in paragraphs (p)(6)
through (9) of this section; and calculate CH4 and
CO2 mass emissions as specified in paragraph (p)(11) of this
section. If emissions from a compressor source are routed to a flare,
paragraphs (p)(1) through (11) do not apply and instead you must
calculate CH4, CO2, and N2O emissions
as specified in paragraph (p)(12) of this section. If emissions from a
compressor source are captured for fuel use or are routed to a thermal
oxidizer, paragraphs (p)(1) through (12) do not apply and instead you
must calculate and report emissions as specified in subpart C of this
part. If emissions from a compressor source are routed to vapor
recovery, paragraphs (p)(1) through (12) do not apply. If you are
required to report emissions from reciprocating compressor venting at
an onshore petroleum and natural gas production facility as specified
in Sec. 98.232(c)(11) or an onshore petroleum and natural gas
gathering and boosting facility as specified in Sec. 98.232(j)(5), you
must calculate volumetric emissions as specified in paragraph (p)(10);
and calculate CH4 and CO2 mass emissions as
specified in paragraph (p)(11).
* * * * *
(10) Method for calculating volumetric GHG emissions from
reciprocating compressor venting at an onshore petroleum and natural
gas production facility or an onshore petroleum and natural gas
gathering and boosting facility. You must calculate emissions from
reciprocating compressor venting at an onshore petroleum and natural
gas production facility or an onshore petroleum and natural gas
gathering and boosting facility using Equation W-29D of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.012
Where:
Es,i = Annual volumetric GHGi (either
CH4 or CO2) emissions from reciprocating
compressors, at standard conditions, in cubic feet.
Count = Total number of reciprocating compressors.
EFi,s = Emission factor for GHGi. Use 9.48 x
10\3\ standard cubic feet per year per compressor for CH4
and 5.27 x 10\2\ standard cubic feet per year per compressor for
CO2 at 60 [deg]F and 14.7 psia.
* * * * *
[[Page 64290]]
(r) Equipment leaks by population count. This paragraph (r) applies
to emissions sources listed in Sec. 98.232 (c)(21), (f)(5), (g)(3),
(h)(4), (i)(2), (i)(3), (i)(4), (i)(5), (i)(6), (j)(10), and (j)(11) on
streams with gas content greater than 10 percent CH4 plus
CO2 by weight. Emissions sources in streams with gas content
less than or equal to 10 percent CH4 plus CO2 by
weight are exempt from the requirements of this paragraph (r) and do
not need to be reported. Tubing systems equal to or less than one half
inch diameter are exempt from the requirements of paragraph (r) of this
section and do not need to be reported. You must calculate emissions
from all emission sources listed in this paragraph using Equation W-32A
of this section, except for natural gas distribution facility emission
sources listed in Sec. 98.232(i)(3). Natural gas distribution facility
emission sources listed in Sec. 98.232(i)(3) must calculate emissions
using Equation W-32B of this section and according to paragraph
(r)(6)(ii) of this section.
[GRAPHIC] [TIFF OMITTED] TR22OC15.013
Where:
Es,e,i = Annual volumetric emissions of GHGi
from the emission source type in standard cubic feet. The emission
source type may be a component (e.g. connector, open-ended line,
etc.), below grade metering-regulating station, below grade
transmission-distribution transfer station, distribution main,
distribution service, or gathering pipeline.
Es,MR,i = Annual volumetric emissions of GHGi
from all meter/regulator runs at above grade metering regulating
stations that are not above grade transmission-distribution transfer
stations or, when used to calculate emissions according to paragraph
(q)(9) of this section, the annual volumetric emissions of
GHGi from all meter/regulator runs at above grade
transmission-distribution transfer stations, in standard cubic feet.
Counte = Total number of the emission source type at the
facility. For onshore petroleum and natural gas production
facilities and onshore petroleum and natural gas gathering and
boosting facilities, 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. Onshore
petroleum and natural gas gathering and boosting facilities must
also count the miles of gathering pipelines by material type
(protected steel, unprotected steel, plastic, or cast iron).
Underground natural gas storage facilities must count each component
listed in Table W-4 of this subpart. LNG storage facilities must
count the number of vapor recovery compressors. LNG import and
export facilities must count the number of vapor recovery
compressors. Natural gas distribution facilities must count: (1) The
number of distribution services by material type; (2) miles of
distribution mains by material type; and (3) number of below grade
metering-regulating stations, by pressure type; as listed in Table
W-7 of this subpart.
CountMR = Total number of meter/regulator runs at above
grade metering-regulating stations that are not above grade
transmission-distribution transfer stations or, when used to
calculate emissions according to paragraph (q)(9) of this section,
the total number of meter/regulator runs at above grade
transmission-distribution transfer stations.
EFs,e = Population emission factor for the specific
emission source type, as listed in Tables W-1A and W-4 through 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.
EFs,MR,i = Meter/regulator run population emission factor
for GHGi based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic
feet of GHGi per operational hour of all meter/regulator
runs, as determined in Equation W-31 of this section.
GHGi = For onshore petroleum and natural gas production
facilities and onshore petroleum and natural gas gathering and
boosting facilities, concentration of GHGi,
CH4, or CO2, in produced natural gas as
defined in paragraph (u)(2) of this section; for onshore natural gas
transmission compression and underground natural gas storage,
GHGi equals 0.975 for CH4 and 1.1 x
10-2 for CO2; for LNG storage and LNG import
and export equipment, GHGi equals 1 for CH4
and 0 for CO2; and for natural gas distribution,
GHGi equals 1 for CH4 and 1.1 x
10-2 CO2.
Te = Average estimated time that each emission source
type associated with the equipment leak emission was operational in
the calendar year, in hours, using engineering estimate based on
best available data.
Tw,avg = Average estimated time that each meter/regulator
run was operational in the calendar year, in hours per meter/
regulator run, using engineering estimate based on best available
data.
* * * * *
(2) Onshore petroleum and natural gas production facilities and
onshore petroleum and natural gas gathering and boosting facilities
must use the appropriate default whole gas population emission factors
listed in Table W-1A of this subpart. Major equipment and components
associated with gas wells and onshore petroleum and natural gas
gathering and boosting systems are considered gas service components in
reference to Table W-1A 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 W-1A 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 calculation methods described in this
paragraph (r)(2), except for miles of gathering pipelines by material
type, which must be determined using Component Count Method 2 in
paragraph (r)(2)(ii) of this section. The same calculation method must
be used for the entire calendar year.
(i) Component Count Method 1. For all onshore petroleum and natural
gas production operations and onshore petroleum and natural gas
gathering and boosting 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. For meters/piping, use one meters/piping per well-pad
for onshore petroleum and natural gas production operations and the
number of meters in the facility for onshore petroleum and natural gas
gathering and boosting operations.
(B) Multiply major equipment counts by the average component counts
listed in Table W-1B of this subpart for onshore natural gas production
and onshore petroleum and natural gas gathering and boosting; and Table
W-1C of this subpart for onshore oil production. Use the appropriate
factor
[[Page 64291]]
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.
* * * * *
(u) * * *
(2) * * *
(i) GHG mole fraction in produced natural gas for onshore petroleum
and natural gas production facilities and onshore petroleum and natural
gas gathering and boosting facilities. If you have a continuous gas
composition analyzer for produced natural gas, you must use an annual
average of these values for determining the mole fraction. If you do
not have a continuous gas composition analyzer, then you must use an
annual average gas composition based on your most recent available
analysis of the sub-basin category or facility, as applicable to the
emission source.
* * * * *
(iii) GHG mole fraction in transmission pipeline natural gas that
passes through the facility for the onshore natural gas transmission
compression industry segment and the onshore natural gas transmission
pipeline industry segment. You may use either a default 95 percent
methane and 1 percent carbon dioxide fraction for GHG mole fraction in
natural gas or site specific engineering estimates based on best
available data.
* * * * *
(z) Onshore petroleum and natural gas production, onshore petroleum
and natural gas gathering and boosting, and natural gas distribution
combustion emissions. Calculate CO2, CH4, and
N2O combustion-related emissions from stationary or portable
equipment, except as specified in paragraphs (z)(3) and (4) of this
section, as follows:
(1) * * *
(ii) Emissions from fuel combusted in stationary or portable
equipment at onshore petroleum and natural gas production facilities,
at onshore petroleum and natural gas gathering and boosting facilities,
and at natural gas distribution facilities will be reported according
to the requirements specified in Sec. 98.236(z) and not according to
the reporting requirements specified in subpart C of this part.
* * * * *
0
6. Section 98.234 is amended by adding paragraph (g) to read as
follows:
Sec. 98.234 Monitoring and QA/QC requirements.
* * * * *
(g) Special reporting provisions for best available monitoring
methods in reporting year 2016--(1) Best available monitoring methods.
From January 1, 2016, to December 31, 2016, you must use the
calculation methodologies and equations in Sec. 98.233 but you may use
the best available monitoring method as described in paragraph (g)(2)
of this section for any parameter specified in paragraphs (g)(3)
through (6) of this section for which it is not reasonably feasible to
acquire, install, and operate a required piece of monitoring equipment
by January 1, 2016. Starting no later than January 1, 2017, you must
discontinue using best available methods and begin following all
applicable monitoring and QA/QC requirements of this part. For onshore
petroleum and natural gas production, this paragraph (g)(1) only
applies if emissions from well completions and workovers of oil wells
with hydraulic fracturing cause your facility to exceed the reporting
threshold in Sec. 98.231(a)(1).
(2) Best available monitoring methods means any of the following
methods:
(i) Monitoring methods currently used by the facility that do not
meet the specifications of this subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(3) Best available monitoring methods for well-related measurement
data for oil wells with hydraulic fracturing. You may use best
available monitoring methods for any well-related measurement data that
cannot reasonably be measured according to the monitoring and QA/QC
requirements of this subpart for venting during well completions and
workovers of oil wells with hydraulic fracturing.
(4) Best available monitoring methods for measurement data for
onshore petroleum and natural gas gathering and boosting facilities.
You may use best available monitoring methods for any leak detection
and/or measurement data that cannot reasonably be measured according to
the monitoring and QA/QC requirements of this subpart for acid gas
removal vents as specified in Sec. 98.233(d).
(5) Best available monitoring methods for measurement data for
natural gas transmission pipelines. You may use best available
monitoring methods for any measurement data for natural gas
transmission pipelines that cannot reasonably be obtained according to
the monitoring and QA/QC requirements of this subpart for blowdown vent
stacks.
(6) Best available monitoring methods for specified activity data.
You may use best available monitoring methods for activity data as
listed in paragraphs (g)(6)(i) through (iii) of this section that
cannot reasonably be obtained according to the monitoring and QA/QC
requirements of this subpart for well completions and workovers of oil
wells with hydraulic fracturing, onshore petroleum and natural gas
gathering and boosting facilities, or natural gas transmission
pipelines.
(i) Cumulative hours of venting, days, or times of operation in
Sec. 98.233(e), (g), (o), (p), and (r).
(ii) Number of blowdowns, completions, workovers, or other events
in Sec. 98.233(g) and (i).
(iii) Cumulative volume produced, volume input or output, or volume
of fuel used in paragraphs Sec. 98.233(d), (e), (j), (n), and (z).
* * * * *
0
7. Section 98.236 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Adding paragraphs (a)(9) and (10);
0
c. Revising paragraphs (d)(1)(i) and (vi);
0
d. Revising paragraphs (e)(1)(i) and (xviii);
0
e. Revising paragraphs (f)(1)(ii), (f)(1)(xi)(A), (f)(1)(xii)(A), and
(f)(2)(i);
0
f. Revising paragraphs (g) introductory text, (g)(1), (g)(2), (g)(5),
and (g)(6);
0
g. Revising paragraphs (h)(1)(i) and (iv), (h)(2)(i) and (iv),
(h)(3)(i), and (h)(4)(i);
0
h. Revising paragraphs (i) introductory text and (i)(1) introductory
text;
0
i. Adding paragraph (i)(3);
0
j. Revising paragraphs (j) introductory text and (j)(1) introductory
text;
0
k. Revising paragraphs (j)(1)(i), (iii), (iv) (v), (vii), and (viii);
0
l. Revising paragraphs (j)(2)(i) introductory text, (j)(2)(i)(A)
through (C), (j)(2)(ii), (j)(2)(iii) introductory text, (j)(2)(iii)(A)
and (B), and (j)(3) introductory text;
0
m. Revising paragraph (l)(1) introductory text;
0
n. Redesignating paragraphs (l)(1)(ii) through (vi) as paragraphs
(l)(1)(iii) through (vii), respectively;
0
o. Adding paragraph (l)(1)(ii);
0
p. Revising newly designated paragraph (l)(1)(v);
0
q. Revising paragraph (l)(2) introductory text;
0
r. Redesignating paragraphs (l)(2)(ii) through (vii) as paragraphs
(l)(2)(iii) through (viii), respectively;
0
s. Adding paragraph (l)(2)(ii);
0
t. Revising newly designated paragraph (l)(2)(v);
0
u. Revising paragraph (l)(3) introductory text;
0
v. Redesignating paragraphs (l)(3)(ii) through (v) as paragraphs
(l)(3)(iii) through (vi), respectively;
0
w. Adding paragraph (l)(3)(ii);
0
x. Revising newly designated paragraph (l)(3)(iv);
[[Page 64292]]
0
y. Revising paragraph (l)(4) introductory text;
0
a. Redesignating paragraphs (l)(4)(ii) through (vi) as paragraphs
(l)(4)(iii) through (vii), respectively;
0
aa. Adding paragraph (l)(4)(ii);
0
bb. Revising newly designated paragraph (l)(4)(iv);
0
cc. Revising paragraphs (m)(1), (m)(5), (m)(6), (m)(7)(i), (m)(8)(i);
0
dd. Revising paragraph (n)(1);
0
ee. Revising paragraphs (o) introductory text and (o)(5) introductory
text;
0
ff. Revising paragraphs (p) introductory text and (p)(5) introductory
text;
0
gg. Revising paragraphs (r)(1) introductory text, (r)(1)(i), (r)(3)
introductory text, and (r)(3)(ii) introductory text;
0
hh. Revising paragraph (z) introductory text;
0
ii. Revising paragraphs (aa) introductory text and (aa)(1)(ii)(D)
through (H);
0
jj. Adding paragraphs (aa)(10) and (11); and
0
kk. Revising paragraph (cc).
The revisions and additions read as follows:
Sec. 98.236 Data reporting requirements.
* * * * *
(a) The annual report must include the information specified in
paragraphs (a)(1) through (10) of this section for each applicable
industry segment. The annual report must also include annual emissions
totals, in metric tons of each GHG, for each applicable industry
segment listed in paragraphs (a)(1) through (10), and each applicable
emission source listed in paragraphs (b) through (z) of this section.
* * * * *
(9) Onshore petroleum and natural gas gathering and boosting. For
the equipment/activities specified in paragraphs (a)(9)(i) through (xi)
of this section, report the information specified in the applicable
paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified
in paragraph (b) of this section.
(ii) Natural gas driven pneumatic pumps. Report the information
specified in paragraph (c) of this section.
(iii) Acid gas removal units. Report the information specified in
paragraph (d) of this section.
(iv) Dehydrators. Report the information specified in paragraph (e)
of this section.
(v) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
(vi) Storage tanks. Report the information specified in paragraph
(j) of this section.
(vii) Flare stacks. Report the information specified in paragraph
(n) of this section.
(viii) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
(ix) Reciprocating compressors. Report the information specified in
paragraph (p) of this section.
(x) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
(xi) Combustion equipment. Report the information specified in
paragraph (z) of this section.
(10) Onshore natural gas transmission pipeline. For blowdown vent
stacks, report the information specified in paragraph (i) of this
section.
* * * * *
(d) * * *
(1) * * *
(i) A unique name or ID number for the acid gas removal unit. For
the onshore petroleum and natural gas production and the onshore
petroleum and natural gas gathering and boosting industry segments, a
different name or ID may be used for a single acid gas removal unit for
each location it operates at in a given year.
* * * * *
(vi) Sub-basin ID that best represents the wells supplying gas to
the unit (for the onshore petroleum and natural gas production industry
segment only) or name of the county that best represents the equipment
supplying gas to the unit (for the onshore petroleum and natural gas
gathering and boosting industry segment only).
* * * * *
(e) * * *
(1) * * *
(i) A unique name or ID number for the dehydrator. For the onshore
petroleum and natural gas production and the onshore petroleum and
natural gas gathering and boosting industry segments, a different name
or ID may be used for a single dehydrator for each location it operates
at in a given year.
* * * * *
(xviii) Sub-basin ID that best represents the wells supplying gas
to the dehydrator (for the onshore petroleum and natural gas production
industry segment only) or name of the county that best represents the
equipment supplying gas to the dehydrator (for the onshore petroleum
and natural gas gathering and boosting industry segment only).
* * * * *
(f) * * *
(1) * * *
(ii) Well tubing diameter and pressure group ID and a list of the
well ID numbers associated with each sub-basin and well tubing diameter
and pressure group ID.
* * * * *
(xi) * * *
(A) Well ID number of tested well.
* * * * *
(xii) * * *
(A) Well ID number.
* * * * *
(2) * * *
(i) Sub-basin ID and a list of the well ID numbers associated with
each sub-basin.
* * * * *
(g) Completions and workovers with hydraulic fracturing. You must
indicate whether your facility had any well completions or workovers
with hydraulic fracturing during the calendar year. If your facility
had well completions or workovers with hydraulic fracturing during the
calendar year, then you must report information specified in paragraphs
(g)(1) through (10) of this section, for each sub-basin and well type
combination. Report information separately for completions and
workovers.
(1) Sub-basin ID and a list of the well ID numbers associated with
each sub-basin that had completions or workovers with hydraulic
fracturing during the calendar year.
(2) Well type combination (horizontal or vertical, gas well or oil
well).
* * * * *
(5) If you used Equation W-10A of Sec. 98.233 to calculate annual
volumetric total gas emissions, then you must report the information
specified in paragraphs (g)(5)(i) through (iii) of this section.
(i) Cumulative gas flowback time, in hours, from when gas is first
detected until sufficient quantities are present to enable separation,
and the cumulative flowback time, in hours, after sufficient quantities
of gas are present to enable separation (sum of ``Tp,i'' and
sum of ``Tp,s'' values used in Equation W-10A of Sec.
98.233). You may delay the reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells are the only wells included in this number. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec. 98.236(cc) the total number of hours of flowback from all
wells during completions or workovers and the well ID number(s) for the
well(s) included in the number.
(ii) For the measured well(s), the flowback rate, in standard cubic
feet per
[[Page 64293]]
hour (average of ``FRs,p'' values used in Equation W-12A of
Sec. 98.233), and the well ID numbers of the wells for which it is
measured. You may delay the reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that can be used for the measurement. If you
elect to delay reporting of this data element, you must report by the
date specified in Sec. 98.236(cc) the measured flowback rate during
well completion or workover and the well ID number(s) for the well(s)
included in the measurement.
(iii) If you used Equation W-12C of Sec. 98.233 to calculate the
average gas production rate for an oil well, then you must report the
information specified in paragraphs (g)(5)(iii)(A) and (B) of this
section.
(A) Gas to oil ratio for the well in standard cubic feet of gas per
barrel of oil (``GORp'' in Equation W-12C of Sec. 98.233).
You may delay the reporting of this data element if you indicate in the
annual report that wildcat wells and/or delineation wells are the only
wells that can be used for the measurement. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec. 98.236(cc) the gas to oil ratio for the well and the well ID
number for the well.
(B) Volume of oil produced during the first 30 days of production
after completions of each newly drilled well or well workover using
hydraulic fracturing, in barrels (``Vp'' in Equation W-12C
of Sec. 98.233). You may delay the reporting of this data element if
you indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that can be used for the measurement. If you
elect to delay reporting of this data element, you must report by the
date specified in Sec. 98.236(cc) the volume of oil produced during
the first 30 days of production after well completion or workover and
the well ID number for the well.
(6) If you used Equation W-10B of Sec. 98.233 to calculate annual
volumetric total gas emissions, then you must report the information
specified in paragraphs (g)(6)(i) through (iii) of this section.
(i) Vented natural gas volume, in standard cubic feet, for each
well in the sub-basin (``FVs,p'' in Equation W-10B of Sec.
98.233).
(ii) Flow rate at the beginning of the period of time when
sufficient quantities of gas are present to enable separation, in
standard cubic feet per hour, for each well in the sub-basin
(``FRp,i'' in Equation W-10B of Sec. 98.233).
(iii) The well ID number for which vented natural gas volume was
measured.
* * * * *
(h) * * *
(1) * * *
(i) Sub-basin ID and a list of the well ID numbers associated with
each sub-basin for gas well completions without hydraulic fracturing
and without flaring.
* * * * *
(iv) Average daily gas production rate for all completions without
hydraulic fracturing in the sub-basin without flaring, in standard
cubic feet per hour (average of all ``Vp'' used in Equation
W-13B of Sec. 98.233). You may delay reporting of this data element if
you indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that can be used for the measurement. If you
elect to delay reporting of this data element, you must report by the
date specified in Sec. 98.236(cc) the measured average daily gas
production rate for all wells during completions and the well ID
number(s) for the well(s) included in the measurement.
* * * * *
(2) * * *
(i) Sub-basin ID and a list of the well ID numbers associated with
each sub-basin for gas well completions without hydraulic fracturing
and with flaring.
* * * * *
(iv) Average daily gas production rate for all completions without
hydraulic fracturing in the sub-basin with flaring, in standard cubic
feet per hour (the average of all ``Vp'' from Equation W-13B
of Sec. 98.233). You may delay reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that can be used for the measurement. If you
elect to delay reporting of this data element, you must report by the
date specified in Sec. 98.236(cc) the measured average daily gas
production rate for all wells during completions and the well ID
number(s) for the well(s) included in the measurement.
* * * * *
(3) * * *
(i) Sub-basin ID and a list of the well ID numbers associated with
each sub-basin for gas well workovers without hydraulic fracturing and
without flaring.
* * * * *
(4) * * *
(i) Sub-basin ID and a list of well ID numbers associated with each
sub-basin for gas well workovers without hydraulic fracturing and with
flaring.
* * * * *
(i) Blowdown vent stacks. You must indicate whether your facility
has blowdown vent stacks. If your facility has blowdown vent stacks,
then you must report whether emissions were calculated by equipment or
event type or by using flow meters or a combination of both. If you
calculated emissions by equipment or event type for any blowdown vent
stacks, then you must report the information specified in paragraph
(i)(1) of this section considering, in aggregate, all blowdown vent
stacks for which emissions were calculated by equipment or event type.
If you calculated emissions using flow meters for any blowdown vent
stacks, then you must report the information specified in paragraph
(i)(2) of this section considering, in aggregate, all blowdown vent
stacks for which emissions were calculated using flow meters. For the
onshore natural gas transmission pipeline segment, you must also report
the information in paragraph (i)(3) of this section.
(1) Report by equipment or event type. If you calculated emissions
from blowdown vent stacks by the seven categories listed in Sec.
98.233(i)(2) for industry segments other than the onshore natural gas
transmission pipeline segment, then you must report the equipment or
event types and the information specified in paragraphs (i)(1)(i)
through (iii) of this section for each equipment or event type. If a
blowdown event resulted in emissions from multiple equipment types, and
the emissions cannot be apportioned to the different equipment types,
then you may report the information in paragraphs (i)(1)(i) through
(iii) of this section for the equipment type that represented the
largest portion of the emissions for the blowdown event. If you
calculated emissions from blowdown vent stacks by the eight categories
listed in Sec. 98.233(i)(2) for the onshore natural gas transmission
pipeline segment, then you must report the pipeline segments or event
types and the information specified in paragraphs (i)(1)(i) through
(iii) of this section for each ``equipment or event type'' (i.e.,
category). If a blowdown event resulted in emissions from multiple
categories, and the emissions cannot be apportioned to the different
categories, then you may report the information in paragraphs (i)(1)(i)
through (iii) of this section for the ``equipment or event type''
(i.e., category) that represented the largest portion of the emissions
for the blowdown event.
* * * * *
[[Page 64294]]
(3) Onshore natural gas transmission pipeline segment. Report the
information in paragraphs (i)(3)(i) through (iii) of this section for
each state.
(i) Annual CO2 emissions in metric tons CO2.
(ii) Annual CH4 emissions in metric tons CH4.
(iii) Annual number of blowdown events.
(j) Onshore production and onshore petroleum and natural gas
gathering and boosting storage tanks. You must indicate whether your
facility sends produced oil to atmospheric tanks. If your facility
sends produced oil to atmospheric tanks, then you must indicate which
Calculation Method(s) you used to calculate GHG emissions, and you must
report the information specified in paragraphs (j)(1) and (2) of this
section as applicable. If you used Calculation Method 1 or Calculation
Method 2 of Sec. 98.233(j), and any atmospheric tanks were observed to
have malfunctioning dump valves during the calendar year, then you must
indicate that dump valves were malfunctioning and you must report the
information specified in paragraph (j)(3) of this section.
(1) If you used Calculation Method 1 or Calculation Method 2 of
Sec. 98.233(j) to calculate GHG emissions, then you must report the
information specified in paragraphs (j)(1)(i) through (xvi) of this
section for each sub-basin (for onshore production) or county (for
onshore petroleum and natural gas gathering and boosting) and by
calculation method. Onshore petroleum and natural gas gathering and
boosting facilities do not report the information specified in
paragraphs (j)(1)(ix) and (xi) of this section.
(i) Sub-basin ID (for onshore production) or county name (for
onshore petroleum and natural gas gathering and boosting).
* * * * *
(iii) The total annual oil volume from gas-liquid separators and
direct from wells or non-separator equipment that is sent to applicable
onshore production and onshore petroleum and natural gas gathering and
boosting storage tanks, in barrels. You may delay reporting of this
data element for onshore production if you indicate in the annual
report that wildcat wells and delineation wells are the only wells in
the sub-basin with oil production greater than or equal to 10 barrels
per day and flowing to gas-liquid separators or direct to storage
tanks. If you elect to delay reporting of this data element, you must
report by the date specified in Sec. 98.236(cc) the total volume of
oil from all wells and the well ID number(s) for the well(s) included
in this volume.
(iv) The average gas-liquid separator or non-separator equipment
temperature, in degrees Fahrenheit.
(v) The average gas-liquid separator or non-separator equipment
pressure, in pounds per square inch gauge.
* * * * *
(vii) The minimum and maximum concentration (mole fraction) of
CO2 in flash gas from onshore production and onshore natural
gas gathering and boosting storage tanks.
(viii) The minimum and maximum concentration (mole fraction) of
CH4 in flash gas from onshore production and onshore natural
gas gathering and boosting storage tanks.
* * * * *
(2) * * *
(i) Report the information specified in paragraphs (j)(2)(i)(A)
through (F) of this section, at the basin level, for atmospheric tanks
where emissions were calculated using Calculation Method 3 of Sec.
98.233(j). Onshore gathering and boosting facilities do not report the
information specified in paragraphs (j)(2)(i)(E) and (F) of this
section.
(A) The total annual oil/condensate throughput that is sent to all
atmospheric tanks in the basin, in barrels. You may delay reporting of
this data element for onshore production if you indicate in the annual
report that wildcat wells and delineation wells are the only wells in
the sub-basin with oil/condensate production less than 10 barrels per
day and that send oil/condensate to atmospheric tanks. If you elect to
delay reporting of this data element, you must report by the date
specified in Sec. 98.236(cc) the total annual oil/condensate
throughput from all wells and the well ID number(s) for the well(s)
included in this volume.
(B) An estimate of the fraction of oil/condensate throughput
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric
tanks in the basin that controlled emissions with flares.
(C) An estimate of the fraction of oil/condensate throughput
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric
tanks in the basin that controlled emissions with vapor recovery
systems.
* * * * *
(ii) Report the information specified in paragraphs (j)(2)(ii)(A)
through (D) of this section for each sub-basin (for onshore production)
or county (for onshore petroleum and natural gas gathering and
boosting) with atmospheric tanks whose emissions were calculated using
Calculation Method 3 of Sec. 98.233(j) and that did not control
emissions with flares.
(A) Sub-basin ID (for onshore production) or county name (for
onshore petroleum and natural gas gathering and boosting).
(B) The number of atmospheric tanks in the sub-basin (for onshore
production) or county (for onshore petroleum and natural gas gathering
and boosting) that did not control emissions with flares.
(C) Annual CO2 emissions, in metric tons CO2,
from atmospheric tanks in the sub-basin (for onshore production) or
county (for onshore petroleum and natural gas gathering and boosting)
that did not control emissions with flares, calculated using Equation
W-15 of Sec. 98.233(j) and adjusted for vapor recovery, if applicable.
(D) Annual CH4 emissions, in metric tons CH4,
from atmospheric tanks in the sub-basin (for onshore production) or
county (for onshore petroleum and natural gas gathering and boosting)
that did not control emissions with flares, calculated using Equation
W-15 of Sec. 98.233(j) and adjusted for vapor recovery, if applicable.
(iii) Report the information specified in paragraphs (j)(2)(iii)(A)
through (E) of this section for each sub-basin (for onshore production)
or county (for onshore petroleum and natural gas gathering and
boosting) with atmospheric tanks whose emissions were calculated using
Calculation Method 3 of Sec. 98.233(j) and that controlled emissions
with flares.
(A) Sub-basin ID (for onshore production) or county name (for
onshore petroleum and natural gas gathering and boosting).
(B) The number of atmospheric tanks in the sub-basin (for onshore
production) or county (for onshore petroleum and natural gas gathering
and boosting) that controlled emissions with flares.
* * * * *
(3) If you used Calculation Method 1 or Calculation Method 2 of
Sec. 98.233(j), and any gas-liquid separator liquid dump values did
not close properly during the calendar year, then you must report the
information specified in paragraphs (j)(3)(i) through (iv) of this
section for each sub-basin (for onshore production) or county (for
onshore petroleum and natural gas gathering and boosting).
* * * * *
(l) * * *
(1) If you used Equation W-17A of Sec. 98.233 to calculate annual
volumetric natural gas emissions at actual
[[Page 64295]]
conditions from oil wells and the emissions are not vented to a flare,
then you must report the information specified in paragraphs (l)(1)(i)
through (vii) of this section.
* * * * *
(ii) Well ID numbers for the wells tested in the calendar year.
* * * * *
(v) Average flow rate for well(s) tested, in barrels of oil per
day. You may delay reporting of this data element if you indicate in
the annual report that wildcat wells and/or delineation wells are the
only wells that are tested. If you elect to delay reporting of this
data element, you must report by the date specified in Sec. 98.236(cc)
the measured average flow rate for well(s) tested and the well ID
number(s) for the well(s) included in the measurement.
* * * * *
(2) If you used Equation W-17A of Sec. 98.233 to calculate annual
volumetric natural gas emissions at actual conditions from oil wells
and the emissions are vented to a flare, then you must report the
information specified in paragraphs (l)(2)(i) through (viii) of this
section.
* * * * *
(ii) Well ID numbers for the wells tested in the calendar year.
* * * * *
(v) Average flow rate for well(s) tested, in barrels of oil per
day. You may delay reporting of this data element if you indicate in
the annual report that wildcat wells and/or delineation wells are the
only wells that are tested. If you elect to delay reporting of this
data element, you must report by the date specified in Sec. 98.236(cc)
the measured average flow rate for well(s) tested and the well ID
number(s) for the well(s) included in the measurement.
* * * * *
(3) If you used Equation W-17B of Sec. 98.233 to calculate annual
volumetric natural gas emissions at actual conditions from gas wells
and the emissions were not vented to a flare, then you must report the
information specified in paragraphs (l)(3)(i) through (vi) of this
section.
* * * * *
(ii) Well ID numbers for the wells tested in the calendar year.
* * * * *
(iv) Average annual production rate for well(s) tested, in actual
cubic feet per day. You may delay reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that are tested. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec. 98.236(cc) the measured average annual production rate for
well(s) tested and the well ID number(s) for the well(s) included in
the measurement.
* * * * *
(4) If you used Equation W-17B of Sec. 98.233 to calculate annual
volumetric natural gas emissions at actual conditions from gas wells
and the emissions were vented to a flare, then you must report the
information specified in paragraphs (l)(4)(i) through (vii) of this
section.
* * * * *
(ii) Well ID numbers for the wells tested in the calendar year.
* * * * *
(iv) Average annual production rate for well(s) tested, in actual
cubic feet per day. You may delay reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells are the only wells that are tested. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec. 98.236(cc) the measured average annual production rate for
well(s) tested and the well ID number(s) for the well(s) included in
the measurement.
* * * * *
(m) * * *
(1) Sub-basin ID and a list of well ID numbers for wells for which
associated gas was vented or flared.
* * * * *
(5) Volume of oil produced, in barrels, in the calendar year during
the time periods in which associated gas was vented or flared (the sum
of ``Vp,q'' used in Equation W-18 of Sec. 98.233). You may
delay reporting of this data element if you indicate in the annual
report that wildcat wells and/or delineation wells are the only wells
from which associated gas was vented or flared. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec. 98.236(cc) the volume of oil produced for well(s) with
associated gas venting and flaring and the well ID number(s) for the
well(s) included in the measurement.
(6) Total volume of associated gas sent to sales, in standard cubic
feet, in the calendar year during time periods in which associated gas
was vented or flared (the sum of ``SG'' values used in Equation W-18 of
Sec. 98.233(m)). You may delay reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells from which associated gas was vented or flared. If you elect to
delay reporting of this data element, you must report by the date
specified in Sec. 98.236(cc) the measured total volume of associated
gas sent to sales for well(s) with associated gas venting and flaring
and the well ID number(s) for the well(s) included in the measurement.
(7) * * *
(i) Total number of wells for which associated gas was vented
directly to the atmosphere without flaring and a list of their well ID
numbers.
* * * * *
(8) * * *
(i) Total number of wells for which associated gas was flared and a
list of their well ID numbers.
* * * * *
(n) * * *
(1) Unique name or ID for the flare stack. For the onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting industry segments, a different name or ID
may be used for a single flare stack for each location where it
operates at in a given calendar year.
* * * * *
(o) Centrifugal compressors. You must indicate whether your
facility has centrifugal compressors. You must report the information
specified in paragraphs (o)(1) and (2) of this section for all
centrifugal compressors at your facility. For each compressor source or
manifolded group of compressor sources that you conduct as found leak
measurements as specified in Sec. 98.233(o)(2) or (4), you must report
the information specified in paragraph (o)(3) of this section. For each
compressor source or manifolded group of compressor sources that you
conduct continuous monitoring as specified in Sec. 98.233(o)(3) or
(5), you must report the information specified in paragraph (o)(4) of
this section. Centrifugal compressors in onshore petroleum and natural
gas production and onshore petroleum and natural gas gathering and
boosting are not required to report information in paragraphs (o)(1)
through (4) of this section and instead must report the information
specified in paragraph (o)(5) of this section.
* * * * *
(5) Onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting. Centrifugal
compressors with wet seal degassing vents in onshore petroleum and
natural gas production and onshore petroleum and natural gas gathering
and boosting must report the information specified in paragraphs
(o)(5)(i) through (iii) of this section.
* * * * *
(p) Reciprocating compressors. You must indicate whether your
facility has reciprocating compressors. You must report the information
specified in
[[Page 64296]]
paragraphs (p)(1) and (2) of this section for all reciprocating
compressors at your facility. For each compressor source or manifolded
group of compressor sources that you conduct as found leak measurements
as specified in Sec. 98.233(p)(2) or (4), you must report the
information specified in paragraph (p)(3) of this section. For each
compressor source or manifolded group of compressor sources that you
conduct continuous monitoring as specified in Sec. 98.233(p)(3) or
(5), you must report the information specified in paragraph (p)(4) of
this section. Reciprocating compressors in onshore petroleum and
natural gas production and onshore petroleum and natural gas gathering
and boosting are not required to report information in paragraphs
(p)(1) through (4) of this section and instead must report the
information specified in paragraph (p)(5) of this section.
* * * * *
(5) Onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting. Reciprocating
compressors in onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting must report the
information specified in paragraphs (p)(5)(i) through (iii) of this
section.
* * * * *
(r) * * *
(1) You must indicate whether your facility contains any of the
emission source types required to use Equation W-32A of Sec. 98.233.
You must report the information specified in paragraphs (r)(1)(i)
through (v) of this section separately for each emission source type
required to use Equation W-32A that is located at your facility.
Onshore petroleum and natural gas production facilities and onshore
petroleum and natural gas gathering and boosting facilities must report
the information specified in paragraphs (r)(1)(i) through (v)
separately by component type, service type, and geographic location
(i.e., Eastern U.S. or Western U.S.).
(i) Emission source type. Onshore petroleum and natural gas
production facilities and onshore petroleum and natural gas gathering
and boosting facilities must report the component type, service type
and geographic location.
* * * * *
(3) Onshore petroleum and natural gas production facilities and
onshore petroleum and natural gas gathering and boosting facilities
must also report the information specified in paragraphs (r)(3)(i) and
(ii) of this section.
* * * * *
(ii) Onshore petroleum and natural gas production facilities and
onshore petroleum and natural gas gathering and boosting facilities
must report the information specified in paragraphs (r)(3)(ii)(A) and
(B) of this section, for each major equipment type, production type
(i.e., natural gas or crude oil), and geographic location combination
in Tables W-1B and W-1C of this subpart.
* * * * *
(z) Combustion equipment at onshore petroleum and natural gas
production facilities, onshore petroleum and natural gas gathering and
boosting facilities, and natural gas distribution facilities. If your
facility is required by Sec. 98.232(c)(22), (i)(7), or (j)(12) to
report emissions from combustion equipment, then you must indicate
whether your facility has any combustion units subject to reporting
according to paragraph (a)(1)(xvii), (a)(8)(i), or (a)(9)(xi) of this
section. If your facility contains any combustion units subject to
reporting according to paragraph (a)(1)(xvii), (a)(8)(i), or (a)(9)(xi)
of this section, then you must report the information specified in
paragraphs (z)(1) and (2) of this section, as applicable.
* * * * *
(aa) Each facility must report the information specified in
paragraphs (aa)(1) through (11) of this section, for each applicable
industry segment, by using best available data. If a quantity required
to be reported is zero, you must report zero as the value.
(1) * * *
(ii) * * *
(D) The number of producing wells at the end of the calendar year
and a list of the well ID numbers (exclude only those wells permanently
taken out of production, i.e., plugged and abandoned).
(E) The number of producing wells acquired during the calendar year
and a list of the well ID numbers.
(F) The number of producing wells divested during the calendar year
and a list of the well ID numbers.
(G) The number of wells completed during the calendar year and a
list of the well ID numbers.
(H) The number of wells permanently taken out of production (i.e.,
plugged and abandoned) during the calendar year and a list of the well
ID numbers.
* * * * *
(10) For onshore petroleum and natural gas gathering and boosting
facilities, report the quantities specified in paragraphs (aa)(10)(i)
through (iv) of this section.
(i) The quantity of gas received by the gathering and boosting
facility in the calendar year, in thousand standard cubic feet.
(ii) The quantity of gas transported to a natural gas processing
facility, a natural gas transmission pipeline, a natural gas
distribution pipeline, or another gathering and boosting facility in
the calendar year, in thousand standard cubic feet.
(iii) The quantity of all hydrocarbon liquids received by the
gathering and boosting facility in the calendar year, in barrels.
(iv) The quantity of all hydrocarbon liquids transported to a
natural gas processing facility, a natural gas transmission pipeline, a
natural gas distribution pipeline, or another gathering and boosting
facility in the calendar year, in barrels.
(11) For onshore natural gas transmission pipeline facilities,
report the quantities specified in paragraphs (aa)(11)(i) through (vi)
of this section.
(i) The quantity of natural gas received at all custody transfer
stations in the calendar year, in thousand standard cubic feet. This
value may include meter corrections, but only for the calendar year
covered by the annual report.
(ii) The quantity of natural gas withdrawn from in-system storage
in the calendar year, in thousand standard cubic feet.
(iii) The quantity of natural gas added to in-system storage in the
calendar year, in thousand standard cubic feet.
(iv) The quantity of natural gas transferred to third parties such
as LDCs or other transmission pipelines, in thousand standard cubic
feet.
(v) The quantity of natural gas consumed by the transmission
pipeline facility for operational purposes, in thousand standard cubic
feet.
(vi) The miles of transmission pipeline for each state in the
facility.
* * * * *
(cc) If you elect to delay reporting the information in paragraph
(g)(5)(i), (g)(5)(ii), (g)(5)(iii)(A), (g)(5)(iii)(B), (h)(1)(iv),
(h)(2)(iv), (j)(1)(iii), (j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv),
(l)(3)(iii), (l)(4)(iii), (m)(5), or (m)(6) of this section, you must
report the information required in that paragraph no later than the
date 2 years following the date specified in Sec. 98.3(b) introductory
text.
0
8. Section 98.238 is amended by adding definitions for ``Facility with
respect to onshore petroleum and natural gas gathering and boosting for
purposes of reporting under this subpart and for the corresponding
subpart A requirements,'' ``Facility with respect to the onshore
natural gas transmission pipeline segment,'' ``Gathering and
[[Page 64297]]
boosting system,'' ``Gathering and boosting system owner or operator,''
``Onshore natural gas transmission pipeline owner or operator,'' and
``Well identification (ID) number'' in alphabetical order to read as
follows:
Sec. 98.238 Definitions.
* * * * *
Facility with respect to onshore petroleum and natural gas
gathering and boosting for purposes of reporting under this subpart and
for the corresponding subpart A requirements means all gathering
pipelines and other equipment located along those pipelines that are
under common ownership or common control by a gathering and boosting
system owner or operator and that are located in a single hydrocarbon
basin as defined in this section. Where a person owns or operates more
than one gathering and boosting system in a basin (for example,
separate gathering lines that are not connected), then all gathering
and boosting equipment that the person owns or operates in the basin
would be considered one facility. Any gathering and boosting equipment
that is associated with a single gathering and boosting system,
including leased, rented, or contracted activities, is considered to be
under common control of the owner or operator of the gathering and
boosting system that contains the pipeline. The facility does not
include equipment and pipelines that are part of any other industry
segment defined in this subpart.
* * * * *
Facility with respect to the onshore natural gas transmission
pipeline segment means the total U.S. mileage of natural gas
transmission pipelines, as defined in this section, owned and operated
by an onshore natural gas transmission pipeline owner or operator as
defined in this section. The facility does not include pipelines that
are part of any other industry segment defined in this subpart.
* * * * *
Gathering and boosting system means a single network of pipelines,
compressors and process equipment, including equipment to perform
natural gas compression, dehydration, and acid gas removal, that has
one or more connection points to gas and oil production and a
downstream endpoint, typically a gas processing plant, transmission
pipeline, LDC pipeline, or other gathering and boosting system.
Gathering and boosting system owner or operator means any person
that holds a contract in which they agree to transport petroleum or
natural gas from one or more onshore petroleum and natural gas
production wells to a natural gas processing facility, another
gathering and boosting system, a natural gas transmission pipeline, or
a distribution pipeline, or any person responsible for custody of the
petroleum or natural gas transported.
* * * * *
Onshore natural gas transmission pipeline owner or operator means,
for interstate pipelines, the person identified as the transmission
pipeline owner or operator on the Certificate of Public Convenience and
Necessity issued under 15 U.S.C. 717f, or, for intrastate pipelines,
the person identified as the owner or operator on the transmission
pipeline's Statement of Operating Conditions under section 311 of the
Natural Gas Policy Act, or for pipelines that fall under the ``Hinshaw
Exemption'' as referenced in section 1(c) of the Natural Gas Act, 15
U.S.C. 717-717 (w)(1994), the person identified as the owner or
operator on blanket certificates issued under 18 CFR 284.224. If an
intrastate pipeline is not subject to section 311 of the Natural Gas
Policy Act (NGPA), the onshore natural gas transmission pipeline owner
or operator is the person identified as the owner or operator on
reports to the state regulatory body regulating rates and charges for
the sale of natural gas to consumers.
* * * * *
Well identification (ID) number means the unique and permanent
identification number assigned to a petroleum or natural gas well. If
the well has been assigned a US Well Number, the well ID number
required in this subpart is the US Well Number. If a US Well Number has
not been assigned to the well, the well ID number is the identifier
established by the well's permitting authority.
* * * * *
0
9. Revise Table W-1A of subpart W of part 98 to read as follows:
Table W-1A to Subpart W of Part 98--Default Whole Gas Emission Factors
for Onshore Petroleum and Natural Gas Production Facilities and Onshore
Petroleum and Natural Gas Gathering and Boosting Facilities
------------------------------------------------------------------------
Onshore petroleum and natural gas production
and Onshore petroleum and natural gas gathering Emission factor (scf/
and boosting hour/component)
------------------------------------------------------------------------
Eastern U.S.
------------------------------------------------------------------------
Population Emission Factors--All Components, Gas Service \1\
------------------------------------------------------------------------
Valve.......................................... 0.027
Connector...................................... 0.003
Open-ended Line................................ 0.061
Pressure Relief Valve.......................... 0.040
Low Continuous Bleed Pneumatic Device Vents \2\ 1.39
High Continuous Bleed Pneumatic Device Vents 37.3
\2\...........................................
Intermittent Bleed Pneumatic Device Vents \2\.. 13.5
Pneumatic Pumps \3\............................ 13.3
------------------------------------------------------------------------
Population Emission Factors--All Components, Light Crude Service \4\
------------------------------------------------------------------------
Valve.......................................... 0.05
Flange......................................... 0.003
Connector...................................... 0.007
Open-ended Line................................ 0.05
Pump........................................... 0.01
Other \5\...................................... 0.30
------------------------------------------------------------------------
Population Emission Factors--All Components, Heavy Crude Service \6\
------------------------------------------------------------------------
Valve.......................................... 0.0005
Flange......................................... 0.0009
Connector (other).............................. 0.0003
[[Page 64298]]
Open-ended Line................................ 0.006
Other \5\...................................... 0.003
------------------------------------------------------------------------
Population Emission Factors--Gathering Pipelines, by Material Type \7\
------------------------------------------------------------------------
Protected Steel................................ 0.47
Unprotected Steel.............................. 16.59
Plastic/Composite.............................. 2.50
Cast Iron...................................... 27.60
------------------------------------------------------------------------
Western U.S.
------------------------------------------------------------------------
Population Emission Factors--All Components, Gas Service \1\
------------------------------------------------------------------------
Valve.......................................... 0.121
Connector...................................... 0.017
Open-ended Line................................ 0.031
Pressure Relief Valve.......................... 0.193
Low Continuous Bleed Pneumatic Device Vents \2\ 1.39
High Continuous Bleed Pneumatic Device Vents 37.3
\2\...........................................
Intermittent Bleed Pneumatic Device Vents \2\.. 13.5
Pneumatic Pumps \3\............................ 13.3
------------------------------------------------------------------------
Population Emission Factors--All Components, Light Crude Service \4\
------------------------------------------------------------------------
Valve.......................................... 0.05
Flange......................................... 0.003
Connector (other).............................. 0.007
Open-ended Line................................ 0.05
Pump........................................... 0.01
Other \5\...................................... 0.30
------------------------------------------------------------------------
Population Emission Factors--All Components, Heavy Crude Service \6\
------------------------------------------------------------------------
Valve.......................................... 0.0005
Flange......................................... 0.0009
Connector (other).............................. 0.0003
Open-ended Line................................ 0.006
Other \5\...................................... 0.003
------------------------------------------------------------------------
Population Emission Factors--Gathering Pipelines by Material Type \7\
------------------------------------------------------------------------
Protected Steel................................ 0.47
Unprotected Steel.............................. 16.59
Plastic/Composite.............................. 2.50
Cast Iron...................................... 27.60
------------------------------------------------------------------------
\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.''
\7\ Emission factors are in units of ``scf/hour/mile of pipeline.''
0
10. Amend Table W-1B of subpart W of part 98 by revising the table
heading to read as follows:
Table W-1B to Subpart W of Part 98--Default Average Component Counts for
Major Onshore Natural Gas Production Equipment and Onshore Petroleum and
Natural Gas Gathering and Boosting Equipment
* * * * *
[FR Doc. 2015-25840 Filed 10-21-15; 08:45 am]
BILLING CODE 6560-50-P
