[Federal Register Volume 76, Number 247 (Friday, December 23, 2011)]
[Rules and Regulations]
[Pages 80553-80595]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-31532]
[[Page 80553]]
Vol. 76
Friday,
No. 247
December 23, 2011
Part IV
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Part 98
Mandatory Reporting of Greenhouse Gases: Technical Revisions to the
Petroleum and Natural Gas Systems Category of the Greenhouse Gas
Reporting Rule; Final Rule
Federal Register / Vol. 76 , No. 247 / Friday, December 23, 2011 /
Rules and Regulations
[[Page 80554]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 98
[EPA-HQ-OAR-2011-0512; FRL-9501-9]
RIN 2060-AR09
Mandatory Reporting of Greenhouse Gases: Technical Revisions to
the Petroleum and Natural Gas Systems Category of the Greenhouse Gas
Reporting Rule
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: EPA is finalizing technical corrections and revisions to the
petroleum and natural gas systems source category of the Greenhouse Gas
Reporting Rule. Final changes include providing clarification on
existing requirements, increasing flexibility for certain calculation
methods, amending data reporting requirements, clarifying terms and
definitions, and technical corrections.
DATES: This rule is effective on December 28, 2011.
ADDRESSES: EPA has established a docket for this action under Docket ID
No. EPA-HQ-OAR-2011-0512. All documents in the docket are listed in the
http://www.regulations.gov index.
Although listed in the index, some information may not be 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 is publicly available in hard copy only. Publicly available docket
materials are available either electronically through http://www.regulations.gov or in hard copy at the EPA's Docket Center, EPA/DC,
EPA West Building, Room 3334, 1301 Constitution Av., NW., Washington,
DC. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday
through Friday, excluding legal holidays. The telephone number for the
Public Reading Room is (202) 566-1744, and the telephone number for the
Air Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division,
Office of Atmospheric Programs (MC-6207J), Environmental Protection
Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone
number: (202) 343-9263; fax number: (202) 343-2342; email address:
GHGReportingRule@epa.gov. For technical information and implementation
materials, please go to the Web site http://www.epa.gov/climatechange/emissions/subpart/w.html. To submit a question, select Rule Help
Center, followed by ``Contact Us.''
Worldwide Web (WWW). In addition to being available in Docket ID
No. EPA-HQ-OAR-2011-0512, following the Administrator's signature, an
electronic copy of this final rule will also be available through the
WWW on EPA's Greenhouse Gas Reporting Program Web site at http://www.epa.gov/climatechange/emissions/ghgrulemaking.html.
SUPPLEMENTARY INFORMATION:
Regulated Entities. The Administrator determined that this action
is subject to the provisions of Clean Air Act (CAA) section 307(d).
These amended regulations could affect owners or operators of petroleum
and natural gas systems. Regulated entities may include those listed in
Table 1 of this preamble:
Table 1--Examples of Affected Entities by Category
------------------------------------------------------------------------
Examples of affected
Source category NAICS facilities
------------------------------------------------------------------------
486210 Pipeline
transportation of
natural gas.
Petroleum and Natural Gas Systems. 221210 Natural gas
distribution
facilities.
211 Extractors of crude
petroleum and
natural gas.
211112 Natural gas liquid
extraction
facilities.
------------------------------------------------------------------------
Table 1 of this preamble is not intended to be exhaustive, but
rather provides a guide for readers regarding facilities likely to be
affected by this action. Other types of facilities not listed in the
table could also be affected. To determine whether you are affected by
this action, you should carefully examine the applicability criteria
found in 40 CFR Part 98 subpart A, 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? This final rule is effective on
December 28, 2011. Section 553(d) of the Administrative Procedure Act
(APA), 5 U.S.C. Chapter 5, generally provides that rules may not take
effect earlier than 30 days after they are published in the Federal
Register. EPA is issuing this final rule under section CAA 307(d)(1),
which states: ``The provisions of section 553 through 557 * * * of
Title 5 shall not, except as expressly provided in this section, apply
to actions to which this subsection applies.'' Thus, section 553(d) of
the APA does not apply to this rule. EPA is nevertheless acting
consistently with the purposes underlying APA section 553(d) in making
this rule effective on December 28, 2011. Section 5 U.S.C. 553(d)(3)
allows an effective date less than 30 days after publication ``as
otherwise provided by the agency for good cause found and published
with the rule.'' As explained below, EPA finds that there is good cause
for parts of this rule to become effective on December 28, 2011 even
though this will result in an effective date fewer than 30 days from
the date of publication in the Federal Register.
The purpose of the 30-day waiting period prescribed in 5 U.S.C.
553(d) is to give affected parties a reasonable time to adjust their
behavior and prepare before the final rule takes effect. That purpose,
to provide affected parties a reasonable time to prepare for the rule
before it comes into effect, is not necessary in this case, as most of
the affected provisions in the final rule clarify existing provisions,
provide flexibilities to sources covered by the reporting rule, or
otherwise relieve a restriction. For example, this final rule clarifies
the definition of some of the industry segments, and in some cases,
provides further flexibility relating to reporting obligations that
would otherwise have been required by the November 2010 Subpart W (the
2010 final rule) 75 FR 74458. Therefore, EPA finds good cause exists to
make this rule effective on December 28, 2011.
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
[[Page 80555]]
Court) by February 21, 2012. 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 EPA to convene a proceeding for reconsideration, ``[i]f
the person raising an objection can demonstrate to EPA that it was
impracticable to raise such objection within [the period for public
comment] or if the grounds for such objection arose after the period
for public comment (but within the time specified for judicial review)
and if such objection is of central relevance to the outcome of 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, Ariel Rios
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, under CAA section 307(b)(2), the requirements established by this
final rule may not be challenged separately in any civil or criminal
proceedings brought by EPA to enforce these requirements.
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
AGA American Gas Association
AGR Acid Gas Removal
API American Petroleum Institute
AXPC American Exploration and Production Council
BAMM Best Available Monitoring Methods
BOEMRE Bureau of Ocean Energy Management, Regulation and Enforcement
CAA Clean Air Act
CBI confidential business information
CEC Chesapeake Energy Corporation
CEMS continuous emission monitoring systems
cfd cubic feet per day
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e CO2-equivalent
COR certificate of representation
e-GGRT electronic greenhouse gas reporting tool
EIA Economic Impact Analysis
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
FCML Field Code Master List
FERC Federal Energy Regulatory Commission
FR Federal Register
GHG greenhouse gas
GPA Gas Processors Association
GOR gas to oil ratio
GRI Gas Research Institute
Hp horsepower
GWP global warming potential
HHV high heat value
IBR incorporation by reference
ICR information collection request
LDC Local Distribution Company
ISO International Organization for Standardization
kg kilograms
LDCs local natural gas distribution companies
LNG liquefied natural gas
M&R meters and regulators
mmBtu million British thermal units
mmHg millimeters of Mercury
MMscfd million standard cubic feet per day
mTCO2e million metric tons carbon dioxide equivalent
MRR mandatory GHG reporting rule
N2O nitrous oxide
NAICS North American Industry Classification System
NGLs natural gas liquids
NPS nominal pipe size
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality, Planning and Standards
OMB Office of Management and Budget
PHMSA Pipeline and Hazardous Material Safety Administration
QA/QC quality assurance/quality control
RFA Regulatory Flexibility Act
SBA Small Business Administration
SBREFA Small Business Regulatory Enforcement and Fairness Act
T-D Transmission Distribution
TSD technical support document
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
USC United States Code
Table of Contents
I. Background
A. Organization of This Preamble
B. Background
C. Legal Authority
D. How Confidential Business Information Determinations and the
Deferral of Inputs to Emission Equations Are Affected by This Action
E. How do these amendments apply to 2012 reports?
II. Overview of Final Amendments to the General Provisions, and
Petroleum and Natural Gas Systems Source Category and Responses to
Major Public Comments
A. Amendments to the General Provisions
B. Responses to Major Comments Submitted on the General
Provisions
C. Final Amendments to the Petroleum and Natural Gas Systems
Source Category
D. Responses to Major Comments Submitted on the Petroleum and
Natural Gas Systems Source Category
III. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act
I. Background
A. Organization of This Preamble
This preamble consists of three sections. The first section
provides a brief history of 40 CFR part 98 and 40 CFR part 98, subpart
W (``subpart W'').
The second section of this preamble summarizes the revisions made
to specific requirements for subparts A and W being incorporated by
this action. The amendments finalized in this action reflect the
changes to subpart W proposed in two separate proposed rules (76 FR
56010, 76 FR 47392). This section also describes the major changes made
to this source category since proposal and provides a brief summary of
significant public comments and EPA's responses. Additional responses
to significant comments can be located in the document, ``Mandatory
Reporting of Greenhouse Gases--Technical Revisions to the Petroleum and
Natural Gas Systems Category of the Greenhouse Gas Reporting Rule:
EPA's Response to Public Comments'' see EPA-HQ-OAR-2011-0512.
Finally, the last section discusses the various statutory and
executive order requirements applicable to this rulemaking.
B. Background
This action finalizes amendments to provisions in 40 CFR part 98,
subpart A. The 2009 final GHG reporting rule was signed by the EPA
Administrator Lisa Jackson on September 22, 2009 and published in the
Federal Register on October 30, 2009 (74 FR 56260, October 30, 2009
hereinafter ``GHGRP''). The 2009 final rule, which became effective on
December 29, 2009, includes reporting of GHGs from various facilities
and suppliers consistent with the 2008 Consolidated Appropriation Act
(Consolidated Appropriations Act, 2008, Public Law 110-161, 121 Stat.
1844,
[[Page 80556]]
2128). Subsequent notices were published in 2010 finalizing the
requirements for subpart W (74 FR 74458).
In an earlier action, EPA proposed minor technical corrections to
specific provisions in various subparts of the greenhouse gas reporting
rule, including subpart W on August 4, 2011 (76 FR 47392), hereinafter
``GHGRP Corrections Proposal''). In that action, EPA proposed several
corrections to specific provisions in subpart W to address minor errors
in equations and to correct certain erroneous citations.
In this action, EPA is finalizing amendments to provisions in
subpart W that were proposed in both the September 9, 2011 GHGRP
Revisions Proposal action and the August 4, 2011 GHGRP Corrections
Proposal action. Responses to comments submitted on both actions can be
found in section II.C of this preamble and also under the document
``Mandatory Reporting of Greenhouse Gases--Technical Revisions to the
Petroleum and Natural Gas Systems Category of the Greenhouse Gas
Reporting Rule: EPA's Response to Public Comments'' See EPA-HQ-OAR-
2011-0512.
C. Legal Authority
The EPA is promulgating these rule amendments under its existing
CAA authority, specifically authorities provided in CAA section 114.
As stated in the preamble to the 2009 final rule (74 FR 56260,
October 30, 2009), CAA section 114 provides EPA broad authority to
require the information mandated by 40 CFR part 98 because such data
would inform and are relevant to the EPA's obligation to carry out a
wide variety of CAA provisions. As discussed in the preamble to the
initial proposal (74 FR 16448, April 10, 2009), CAA section 114(a)(1)
authorizes the Administrator to require emissions sources, persons
subject to the CAA, manufacturers of process or control equipment, and
persons whom the Administrator believes may have necessary information
to monitor and report emissions and provide such other information the
Administrator requests for the purposes of carrying out any provision
of the CAA. For further information about the EPA's legal authority,
see the preambles to the proposed and final rule, and related Response
to Comments documents.
D. How Confidential Business Information Determinations and the
Deferral of Inputs to Emission Equations Are Affected by This Action
The EPA finalized several rulemakings during 2011 in response to
concerns related to the reporting and publication of information that
may be considered confidential business information (CBI). For more
information on the final action to defer the reporting deadline for
data elements that are used by direct emitter reporters as inputs to
emissions equations under EPA's Greenhouse Gas Reporting Program,
please see the Final CBI Deferral Rule (75 FR 53057, August 25, 2011,
hereinafter referred to the ``Final CBI Deferral Rule''). For more
information generally on the various actions related to treatment of
data that may be considered CBI, please see the GHG Reporting Program
Web site dedicated to CBI at http://www.epa.gov/climatechange/emissions/CBI.html.
On May 26, 2011, the EPA published confidentiality determinations
for certain data elements required to be reported under 40 CFR part 98
and finalized amendments to the Special Rules Governing Certain
Information Obtained Under the Clean Air Act, which authorizes the EPA
to release or withhold as confidential reported data according to the
confidentiality determinations for such data without taking further
procedural steps (76 FR 30782, 2011 hereinafter referred to as the
``Final CBI Rule''). The Final CBI Rule addressed reporting of data
elements in 34 subparts which were determined not to be inputs to
emission equations and therefore are always CBI and which are not
eligible to be CBI. That rule did not make confidentiality
determinations for eight subparts, including subpart W, for which
reporting requirements were finalized after publication of the July 7,
2010 CBI proposal (75 FR 39094) and December 27, 2010 supplemental CBI
proposal (75 FR 43889).
On August 25, 2011, the EPA published a final rule that deferred
the reporting deadline for data elements that are used by direct
emitter reporters as inputs to emission equations under the Mandatory
Greenhouse Gas Reporting Rule (76 FR 53057, Final CBI Deferral Rule).
The Final CBI Deferral Rule, included deferral of the deadline for
reporting inputs to emissions equations based on the 2010 final rule
for 40 CFR part 98, subpart W (75 FR 74458).
EPA intends to propose and finalize CBI determinations for 40 CFR
part 98, subpart W in a separate action (or actions). This final rule
does not affect the deferral of reporting nor the date until which the
deadline is set for reporting those inputs to emissions equations for
subpart W, which were finalized in the Final CBI Deferral Rule. For
subpart W, EPA intends to finalize a deferral of any new or revised
inputs affected by this final action prior to the 2012 reporting
deadline.
E. How do these amendments apply to 2012 reports?
We have determined that it is feasible for owners and operators
covered by this rule to implement these technical amendments for the
2011 reporting year because the revisions primarily provide additional
clarification regarding applicability, and the existing regulatory
requirements generally do not change the type of information that must
be collected, and do not materially affect how GHG emissions or
quantities are calculated. Our rationale for this determination is
explained in the preamble to the proposed rule amendments.\1\
---------------------------------------------------------------------------
\1\ 76 FR 56010 (September 9, 2011).
---------------------------------------------------------------------------
In response to comments submitted on the proposed rulemaking, we
have reviewed the final amendments and determined that they can be
implemented, as finalized, for the 2011 reporting year. Although in
limited cases these amendments may introduce revisions to calculation
procedures from those proposed (e.g., for taking measurements at the
sub-basin level as opposed to the field level), in response to comment,
EPA has introduced flexibilities in the final rule in order to ensure
that there are no new monitoring requirements for 2011.
As an example of the flexibility introduced in this final rule, in
the GHGRP Revisions Proposal, EPA proposed an alternative approach to
taking measurement at the field level, as suggested by industry, by
proposing to take measurement at a sub-basin level. Industry requested
that EPA reconsider the use of a field-level measurement plan for
specific emissions sources including well venting for liquids unloading
and well venting for well completions/workovers, by stating that it was
not clear how to assign a field name to new wells, nor how to address
wells that were not contained in the 2008 EIA Field Code Master List
which was incorporated by reference in the Subpart W Final Rule. The
foundation of the sub-basin approach is defining a sub-basin category
through the use of a county level designation and the distinction of
the type of hydrocarbon formation. The hydrocarbon formations
[[Page 80557]]
can be grouped into five types: Oil, high permeability gas, shale gas,
coal seam, or other tight reservoir rock. For example, wells producing
coal bed methane from formation ``X'' with wellhead coordinates within
county ``A'' would be one sub-basin category. Further, wells producing
from tight formation ``Y'' with wellhead coordinates within county
``A'' would be a second sub-basin category. In the event that a
specific county includes more than one formation (e.g., coal bed
methane and tight sands), then the reporter would use the most specific
designation (e.g., coal bed methane). EPA analyzed the approach
suggested by the industry and believes that the sub-basin category
provides similar quality data as the EIA field code would provide,
while still achieving the appropriate level of data representativeness.
Please see Economic Impact Analysis Memorandum in Docket ID EPA-HQ-OAR-
2011-0512.
Therefore, as industry suggested, EPA proposed the alternative
approach of using a sub-basin measurement level for measurement of
specific emission sources in the onshore production industry segment,
and is finalizing that approach in this action. For example, commenters
were generally supportive of EPA's proposed change to require
calculation and reporting for onshore production at the sub-basin
level, as opposed to the field level. However, one commenter requested
to continue to use field as a classification mechanism for groups of
wells within each basin. The commenter stated that they had already
conducted field-level calculations for 2011. In response to this
concern, and for the 2011 reporting year only, EPA is allowing
reporters who took measurement at the field level to apply those
measurements to the equivalent sub-basins applicable to their facility
as a best available monitoring method (BAMM). The use of a field-level
measurement as a BAMM for a sub-basin measurement fits within a
recently finalized action (76 FR 59533), where EPA granted subpart W
reporters the option to use BAMM for all of 2011 without reporters
being required to submit a request for approval from the Administrator.
For data collection in 2012 and beyond, reporters must use the sub-
basin level for data collection.
By way of further example, the 2010 final rule required facilities
to assume that pneumatic pumps and pneumatic devices were operational
the entire year. We proposed that instead of assuming operation for
8,760 hours per year, facilities would use their actual operating
hours. While many reporters agreed with the proposed amendment, they
encouraged EPA to retain the option of assuming 100 percent operation
during the reporting year, so as not to require facilities to track
operating hours. In this action, reporters now have the option to use
actual operating hours or the default of 8,760 hours per year for both
pneumatic devices and pneumatic pumps when calculating GHG emissions
using equation W-1 and W-2 in 40 CFR 98.233(a) and (b) respectively.
Thus in any given data collection year, reporters now have the option
of using the default or entering their estimated amount of hours for
operation of their pneumatic devices and pumps. This option will not be
limited to the 2011 data collection year.
Lastly, the 2010 final rule requires reporters to take measurement
once in a two year cycle, beginning with the first year of data
collection, for emission sources including the gas well venting from
completions or workovers with hydraulic fracturing emission source
type. In this action, EPA is revising several provisions related to
these emission sources and because the revisions are expected to be
published late in the 2011 data collection year, EPA is allowing
reporters additional flexibility by giving the option to take their
first measurement in the second year as opposed to the first year, as
is stated in the rule, 40 CFR 98.234(g). Reporters who chose this
option must take their measurement before the September 28, 2011
reporting deadline for subpart W.
II. Overview of Final Amendments to the General Provisions, and
Petroleum and Natural Gas Systems Source Category and Responses to
Major Public Comments
A. Amendments to the General Provisions
Purpose and Scope. In this action, EPA is amending 40 CFR 98.1 of
the general provisions by adding paragraph (c) which states that for
the purposes of applying the terms owner and operator used in subpart
A, facilities required to report under the onshore petroleum and
natural gas production industry segment of 40 CFR part 98, subpart W
will use the definition of onshore petroleum and natural gas production
owner or operator in 40 CFR 98.238.
Definitions. EPA is finalizing amendments to definitions in 40 CFR
98.6. First, we are amending the text for the definition for continuous
bleed pneumatic devices, in 40 CFR 98.6 to clarify that continuous
bleed devices supply natural gas to process control devices, and not
measurement devices, as suggested by the 2010 final rule.
Secondly, we are amending the definition of intermittent bleed
pneumatic devices, as proposed, to clarify that these devices
automatically maintain the process conditions and that the devices are
snap-acting or throttling devices that discharge all or a portion of
the full volume of the actuator intermittently when control action is
necessary.
There were no other major changes to 40 CFR subpart A since the
proposal.
B. Responses to Major Comments Submitted on the General Provisions
1. Further Delineation of Types of Intermittent Bleed Pneumatic Devices
Comment: Commenters were generally supportive of EPA's proposal to
clarify the definitions for pneumatic devices in the September 9, 2011
GHGRP Revisions Proposal. One commenter, however, specifically noted
that further clarification to the definition for intermittent devices
was necessary beyond the proposal and requested that EPA list out
examples of intermittent bleed devices.
Response: EPA believes that the definition for intermittent bleed
pneumatic devices finalized in this action is sufficient for reporters
to use as a guideline in determining what would constitute an
intermittent bleed pneumatic device. The definition for intermittent
pneumatic devices finalized in this action clarifies that these types
of pneumatic devices automatically maintain the process conditions and
discharge all or a portion of the full volume of the actuator
intermittently.
C. Final Amendments to the Petroleum and Natural Gas Systems Source
Category
In this action, EPA is amending several provisions to the Final
Subpart W Rule published in November 2010. The major amendments are
listed in this section, followed by a more detailed summary of the
final amendments to the various provisions. Where appropriate, it is
indicated that an amendment was finalized as proposed, or an amendment
as finalized that differed from the GHGRP Corrections proposal or the
GHGRP Revisions proposal. Other changes and clarifications included in
this section are administrative in nature. For a full description of
the rationale for these and any other significant change to 40 CFR part
98, subpart W, see the ``Mandatory Reporting of Greenhouse Gases--
Technical Revisions to the Petroleum and Natural Gas Systems
[[Page 80558]]
Category of the Greenhouse Gas Reporting Rule: EPA's Response to Public
Comments'' and section II.D Responses to Major Comments Submitted on
the Petroleum and Natural Gas Systems Source Category.
Major Changes Since Proposal
1. Calculating GHG Emissions
Inclusion of clarification for emergency blowdown vent
stack emission sources that are covered under 40 CFR 98.233(i).
Revising calculation methodologies for natural gas
distribution industry segment in 40 CFR 98.233(q) and 40 CFR 98.233(r)
to allow for reporters to use a 5-year rolling survey plan.
Revising the emission factor for intermittent pneumatic
devices.
2. Data Reporting Requirements
Not adopting the proposed amendments to include reporting
of a unique name or ID for specified emissions sources under the
onshore petroleum and natural gas production industry segment
throughout 40 CFR 98.236.
Replacing the term ``a unique name or ID number for the
blowdown vent stack'' in 40 CFR 98.236(c)(7)(iii) to ``a unique name or
ID number for the unique volume type.''
Inclusion of data reporting requirements for natural gas
distribution industry segment to reflect the 5-year rolling survey
plan.
3. Definitions
Revising definition for associated with a well-pad in 40
CFR 98.238 by revising the last sentence.
Inclusion of a definition for a 5th sub-basin category for
oil in the 40 CFR 98.238 sub-basin definitions.
4. Emission Factor Tables
Revising emission factors in tables W-1A, W-2, W-3, W-4,
W-5, W-6, and W-7 to adjust for 60[ordm] standard temperature and 14.7
psia pressure.
The final amendments are organized following the different sections
of the subpart W regulatory text beginning with 40 CFR 98.230 and going
through 98.238. As described above in Section II.E., one of the major
changes is for the onshore petroleum and natural gas production
industry segment, where the reporting level has been changed from the
field level to the sub-basin level.
Source Category Definitions. In general, we are finalizing
amendments to the source category definitions as proposed to clarify
both the coverage of individual industry segments and the boundaries
for different industry segments. The purpose of these amendments is
primarily to clarify the coverage of the rule and ensure applicability
under 40 CFR part 98 is as originally intended.
Onshore Petroleum and Natural Gas Production. We are making several
amendments to the definition for the onshore petroleum and natural gas
production (also referred to as onshore production) industry segment in
40 CFR 98.230(a)(2). First, EPA is revising the term ``associated with
a well-pad'' to state that the onshore production industry segment
includes equipment that is ``on a single well-pad or associated with a
single well-pad.'' These equipment are included in the onshore
production industry segment irrespective of the point of emissions from
that equipment (e.g., if emissions from one or more pieces of onshore
oil and gas production equipment are sent to a common header either to
a flare or vent, that vent or flare would also be included). Next, EPA
is amending the definition to clarify that both dehydrators and storage
vessels that are on a single well-pad or associated with a single well-
pad are included as types of equipment that are considered part of the
onshore production industry segment if they are owned or operated by
the onshore production owner or operator, including equipment that is
leased, contracted or rented.
Finally, we are revising the text to state that enhanced oil
recovery (EOR) operations that use either CO2 or natural gas
are a part of this industry segment.
Onshore Natural Gas Processing. EPA is including several
clarifications to the onshore natural gas processing industry segment
definition in 40 CFR 98.230(a)(3). First, we are striking the term
``and recovers'' from the first sentence, in order to more clearly
characterize the unique activities performed at natural gas processing
plants. Second, we are revising the text to clarify that this industry
segment includes one or a combination of the following three processes:
separation of natural gas liquids (NGLs) from produced natural gas,
separation of non-methane gases from produced natural gas, or
separation of NGLs into one or more component mixtures. Third, we are
amending the definition to clarify that separation means one or more of
the following processes: forced extraction of natural gas liquids,
sulfur and carbon dioxide removal, fractionation of NGLs, or the
capture of CO2 separated from natural gas streams. Fourth,
we are striking the phrase ``this industry segment does not include
reporting of emissions from gathering lines and boosting stations''
because the final amendments already clarify the definition of
``onshore natural gas processing'' and therefore, it is unnecessary to
discuss that which is excluded. Fifth, we are revising the threshold
contained in the definition of the onshore natural gas processing
segment to be 25 million standard cubic feet annual average daily
throughput. Finally, we are replacing out the term ``facility'' with
the term ``plant''.
Onshore Natural Gas Transmission Compression. EPA is finalizing
several clarifications to the onshore natural gas transmission
compression industry segment definition in 40 CFR 98.230(a)(4). First,
we are removing the term ``at elevated pressure'' to address confusion
associated with what ``elevated pressure'' actually meant. Next, we are
including a definition in 40 CFR 98.238 of transmission pipeline to
address concerns that this term was undefined and could have a broader
meaning than that which was intended in the 2010 final rule. We are
defining a transmission pipeline to mean 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).
Next, we are clarifying the definition for the transmission
compression industry segment. The final rule provides that natural gas
transmission compression facilities not only move natural gas from
production fields or gas processing plants, but also move natural gas
coming from other transmission compressors. In addition, we are
explicitly stating that natural gas transmission compression facilities
not only move natural gas into distribution pipelines, but also into
liquefied natural gas storage or into underground storage.
We are removing the term ``natural gas dehydration'' from the
industry segment definition because this term did not represent a
unique characteristic of facilities with natural gas transmission
compression. Finally, we are removing the reference to ``gathering
lines and boosting stations'' and ``facility'' for the same reasons as
explained above relating to the onshore processing industry segment
definition.
Natural Gas Distribution. EPA is amending the natural gas
distribution industry segment definition to further clarify
applicability under the rule. First, we are replacing the term ``city
gate station'' with the term ``metering-regulating station'' in 40 CFR
98.230(a)(8). This amendment is designed to more clearly express EPA's
intent using language readily understood by industry. As a
[[Page 80559]]
harmonizing change, we are also adding a definition for the term
``metering-regulating station'' in 40 CFR 98.238 to state that, ``[a]n
above ground station that meters the flow rate, regulates the pressure,
or both, of natural gas in a natural gas distribution facility. This
does not include customer meters, customer regulators, or farm taps''.
With this amendment, we are clarifying key concepts in the definition,
without actually changing coverage by the rule.
We are removing the parenthetical term ``(not interstate
transmission pipelines or intrastate transmission pipelines)'' as this
statement was not necessary. Instead we are adding a definition for
``distribution pipeline'' in 40 CFR 98.238 that clarifies that
``distribution pipelines'' are only those designated as such by the
Pipeline and Hazardous Material Safety Administration (PHMSA) 49 CFR
192.3.
Next, we are removing the term ``excluding customer meters'' and
``physically deliver natural gas to end users'' because the definition
for ``meter-regulator'' stations described above already addresses this
exclusion.
Finally, we are amending the industry segment definition to
explicitly state that the LDC reporting as a single facility is that
which is operated in a single state and regulated as a separate
operating company by a public utility commission or that is operated as
an independent municipally-owned distribution system. This change
ensures that the definition of LDC is consistent between subpart W and
subpart NN.
Greenhouse Gases to Report. We are amending several provisions for
the greenhouse gases that must be reported in 40 CFR 98.232.
We are amending 40 CFR 98.232(c) to clarify that the source listed
in 40 CFR 98.232(c)(1) through (22) are on a single well-pad or
associated with a single well-pad. This change is consistent with the
final changes to the onshore production industry segment definition in
40 CFR 98.230(a)(2) described above. In 40 CFR 98.232 (c)(22), EPA is
replacing the term ``production well pad'' with ``petroleum and natural
gas production facility as defined in 98.238''. This change makes the
term consistent with language used throughout Subpart W.
Next, we are amending 40 CFR 98.232(i) by replacing the term
``custody transfer city gate station'' with the term ``transmission-
distribution transfer station'' and replacing the term ``non-custody
transfer station'' with the term ``metering-regulating station.'' We
are amending the source types for this industry segment by removing the
text ``Customer meters are excluded.'' This text was removed because it
was no longer necessary with the addition of the term ``transmission-
distribution transfer station'' and its definition. Further we are
amending 40 CFR 98.232(i) to state that CO2, CH4
and N2O emissions are to be reported from the natural gas
distribution industry segment. This clarification is consistent with
the calculation procedures in 40 CFR 98.233. Finally, EPA added
emissions sources that were already required to be reported under 40
CFR part 98, subpart W but were not listed under 40 CFR 98.232 (i)
(i.e., pipeline main equipment leaks, service line equipment leaks, and
stationary combustion).
Next, we are removing and reserving 40 CFR 98.232(j), as proposed,
in order to address concerns raised that the inclusion of this
provision resulted in confusion amongst reporters as they were unsure
how this provision aligned with the flare emissions that are captured
under the applicable emissions source calculations throughout 40 CFR
98.233. Accordingly, we are also finalizing, as proposed, the
introductory sentences to 40 CFR 98.232(d), (e), (f), (g), (h), and (i)
to clarify that N2O emissions are also required to be
reported under these industry segments. We are making a harmonizing
change to 40 CFR 98.232(a), to remove the reference to 40 CFR 98.232
(j).
Lastly, we are amending 40 CFR 98.232(k) to clarify that the
onshore petroleum and natural gas production and natural gas
distribution industry segments are to report their combustion emissions
under 40 CFR part 98, subpart W, while the remaining industry segments
are to report their combustion emissions under subpart C of part 98.
Calculating Greenhouse Gas Emissions. We are making several
clarifications, corrections, and amendments throughout 40 CFR 98.233.
Natural Gas Pneumatic Device Venting
EPA is modifying Equation W-1 by adding the subscript ``t'' to the
equation to represent the different device types. EPA is removing the
subscript ``s,'' and the word ``standard'' from the definition of
parameter Masss,i because mass emissions do not need to be
reported at standard conditions. EPA is amending Equation W-1, to
include a parameter ``T'' that estimates the total number of hours in a
year the devices were operational instead of assuming that the natural
gas pneumatic devices was operating the whole year. However, EPA has
provided a value of 8,760 hours for reporters to use as a default
option. Further, EPA is clarifying that compositions in 40 CFR
98.233(u)(2)(i) may be used for the onshore petroleum and natural gas
production in the definition for ``GHGi''. However, for
onshore natural gas transmission compression, and underground natural
gas storage industry segments, set values of 0.975 for CH4
and 1.1 x 10-2 for CO2 are used. The value of
0.975 represents the methane fraction of total hydrocarbon (THC) which
is the basis of the emission factors in Tables W-3 for Natural Gas
Transmission Compression and Table W-4 for Underground Natural Gas
Storage where the non-hydrocarbon fraction of pipeline quality gas
(made up of primarily carbon dioxide and nitrogen) is approximately 2%.
The carbon dioxide fraction of total hydrocarbons in Tables W-3 and W-4
is determined from public records on pipeline gas quality. The value of
1.1 x 10-2 represents the ratio of CO2 to methane
in transmission gas. Under the parameter definition of
Convi, EPA amended the value of emission factors to 0.000403
for CH4 and 0.00005262 for CO2 to account for an
error in the previous factor not being adjusted to standard conditions.
EPA is revising 40 CFR 98.233(a) by adding 40 CFR 98.233(a)(3), which
allows reporters to determine the type of pneumatic devices using
engineering estimation based on best available information. This
amendment is in response to questions about how to determine whether a
pneumatic device is continuous high bleed, continuous low bleed, or
intermittent bleed and the burden associated with determining the type
of pneumatic device.
Lastly, the data reporting requirements in 40 CFR 98.236(c)(1)(iv),
which are associated with pneumatic devices, have been clarified to
require aggregate emissions to be reported for all continuous high
bleed pneumatic devices, for all intermittent bleed pneumatic devices,
and for all continuous low bleed pneumatic devices separately at the
facility level.
Natural Gas Driven Pneumatic Pump Venting
We are amending Equation W-2 in 40 CFR 98.233(c), to include a
parameter ``T'' that estimates the total number of hours in a year the
pumps were operational instead of assuming that the pneumatic pump was
operating the whole year. EPA has provided a value of 8,760 hours for
reporters to use as a default option. EPA is removing the subscript
``s,'' since mass emissions do not need to be reported at standard
conditions.
[[Page 80560]]
Acid Gas Removal (AGR) Vents. EPA is amending 40 CFR 98.233(d) to
clarify EPA's intent and to correct errors.
We are revising provisions in 40 CFR 98.233(d) to clarify how the
four different methods are to be used for determining GHG emissions
from acid gas removal units. First, we are amending 40 CFR 98.233(d)(1)
to specify that the use of CEMS is required if a CO2
concentration monitor and volumetric flow rate monitor are installed.
This amendment was made to clarify what conditions must be met to
satisfy Tier 4 calculation requirement in Subpart C for Acid Gas
Removal vents. EPA is allowing reporters the flexibility to follow the
calculation, quality assurance, reporting, and recordkeeping
requirements in Tier 4 in Subpart C, manufacturer instructions, or
industry standard practice for CEMS units already in place.
EPA is revising 40 CFR 98.233(d)(2), (d)(3), and (d)(4) to clarify
that if a facility has a vent meter but no CEMs available, then they
would use Calculation Methodology 2. If a facility has neither a CEMs
available nor a vent meter in place (with the added flexibility to use
industry consensus standards to calibrate the vent meters), then either
Calculation Methodology 3 or 4 of 40 CFR 98.233(d) may be used.
Next, we are revising the equation used for estimating
CO2 emissions from acid gas removal vents in Equation W-4A
and Equation W-4B in Calculation Methodology 3 in 40 CFR 98.233(d).
This new equation addresses issues that arose with the previous
equation, because that equation was better suited to situations where
the change in CO2 volume fraction between the inlet gas and
the outlet gas would be relatively low, such as 1 percent. These two
new equations will increase the accuracy of the calculation while
adding no additional burden to reporters because the same parameters
are monitored. Further details on the revised equations have been
provided in the memo ``Acid Gas Removal Vents--Engineering Calculation
Revisions'' located in the docket: EPA-HQ-OAR-2011-0512.
EPA is amending several associated data reporting requirements in
40 CFR 98.236(c)(3). First, we are clarifying that the annual average
CO2 content should be reported for volume fraction
measurements undertaken in 40 CFR 98.233(d). Second, we are clarifying
that reporters must report the annual quantity of CO2
recovered from the AGR unit and the CO2 emissions from the
AGR unit separately. Third, we are finalizing the reporting of a unique
ID for each AGR unit in industry segments other than onshore petroleum
and natural gas production, as proposed (see Section II.D. of the
preamble for further details on this issue). Lastly, we are asking
reporters to indicate which methodology they are using to calculate
emissions from AGRs.
Dehydrator Vents. EPA is amending several of the provisions in 40
CFR 98.233(e) for calculating GHGs from dehydrator vents.
First, we are clarifying that the equipment threshold referenced
throughout this section for glycol dehydrators is based on annual
average daily throughput at standard conditions. This amendment was
necessary to address ambiguity in the final rule provisions regarding
determination of the average throughput.
Next, we are clarifying that gases other than natural gas, such as
nitrogen, flash gas from the flash tanks, or dry gas from the absorber,
that are used as stripping gases satisfy the requirements stated in 40
CFR 98.233(e)(1)(vii). EPA is also correcting the citation in 40 CFR
98.233(e)(1)(xi), (e)(1)(xi)(A) through (e)(1)(xi)(C).
Further, EPA clarified parameters in Equation W-5. EPA has
finalized the use of 60 degree Fahrenheit and 14.7 psia as standard
conditions for all of subpart W; therefore, parameter EFi
was revised to reflect the standard conditions. In addition, EPA
clarified that the parameter 1,000 converts emissions from thousand
standard cubic feet to standard cubic feet instead of cubic feet.
Next, we are also amending 40 CFR 98.233(e)(6) to clarify that GHG
mass emissions from glycol dehydrators are to be calculated from
volumetric GHG emissions using calculations in 40 CFR 98.233(v) where
as GHG volumetric and mass emissions from desiccant dehydrators should
be calculated using paragraphs 40 CFR 98.233(u) and 98.233(v).
Accordingly, we are clarifying in 40 CFR 98.236(c)(4) the
requirement to report vented and flared emissions separately. We are
also clarifying the data reporting requirements by specifying that
should any vent gas controls be used on glycol dehydrators with a
throughput less than 0.4 million standard cubic feet, that reporters
must indicate that in their annual reports. Additionally, we are
finalizing the reporting of a unique ID, as proposed, for each glycol
dehydrator in industry segments other than onshore petroleum and
natural gas production (see Section II.D. of the preamble for further
details on this issue). Finally, we are clarifying that emissions from
desiccant dehydrators must be reported at the facility level.
Well Venting for Liquids Unloadings. First, we are revising 40 CFR
98.233(f) Calculation Methodology 1 by finalizing several amendments
that were proposed, including that sampling is to be done at a sub-
basin level as opposed to a field-level. Further, we are finalizing the
provision stating that the average flow rate must be determined for one
well in a tubing diameter group and pressure group in each sub-basin
category. As proposed in the GHGRP Revisions Proposal, EPA has also
added a definition for the term ``pressure groups'' in 40 CFR 98.238 to
inform reporters of the ranges for the pressure groupings that are
applicable to the sub-basins, and the types of pressures that may be
used for those groupings. The pressure ranges, as proposed and
finalized, were optimized using HPDI well counts in 5 psig pressure
increments from zero gauge pressure to 200 psig. The fifth
``unbounded'' pressure range is ``greater than 200 psig,'' which EPA
believes will have very few well liquids unloading venting to the
atmosphere. The three tubing diameter ranges, equal or less than 1
inch, greater than 1 inch and equal or less than 2 inch, and greater
than 2 inch, were derived from gas well tubing suppliers'
specifications, as proposed. The relevancy of these pressure ranges and
tubing diameter ranges is that liquids unloading venting is dependent
on both the shut-in pressure of the reservoir (shut-in by liquids
accumulation) and velocity of gas pushing liquids up the tubing, which
is a function of tubing diameter. For further background on the
selection of these pressure groupings and for the analysis done see
``2011 Technical Revisions to the Petroleum and Natural Gas Systems
Category of the GHG Reporting Rule: Summary of questions raised on
Subpart W'' docket number EPA-HQ-OAR-2011-0512-0015 and ``Sub-Basin
Entity Pressure Range Analysis'' docket number EPA-HQ-OAR-2011-0016.
EPA also clarified in 40 CFR 98.233 (f)(1)(i)(B) that the
determined flow rate can be used for all other wells in that tubing
diameter group and pressure group in a sub-basin category. Finally EPA
clarified in 40 CFR 98.233 (f)(1)(i)(C) that a new producing sub-basin
category must determine an average flow rate during the beginning of
the first year of production.
In this action, we are also including corrections to Equation W-7,
as proposed. EPA is modifying Equation W-7 to address the ambiguity
regarding tubing diameter group and pressure group combinations in a
sub-basin. Furthermore the subscripts ``t'' and ``q''
[[Page 80561]]
were removed along with a summation sign to clarify that emissions are
calculated for all wells in a tubing diameter group and pressure group
in a sub-basin. Accordingly, subscripts ``h'' and ``p'' represent wells
of the same tubing diameter group and pressure group.
EPA is revising Equation W-8 and W-9 by correcting the definition
for parameter Ea,n to be Es,n to accurately
reflect that the calculated emissions should be in standard conditions
and not actual conditions. The parameter definition was also modified
to state that the emissions are at standard conditions. These revisions
from actual conditions to standard conditions were necessary to
maintain uniformity in the approach to calculating GHG emissions across
40 CFR subpart W. EPA is including revisions to the parameters in
Equation W-8 and W-9 to account for each unloading instance, q, and for
each well, p, in a pressure grouping and sub-basin category. In
addition, the parameter W was added to define the limits of the
summation. These amendments address ambiguity with the summation
operation in the 2010 final rule for this equation.
Next, we are amending the definition for ``SFRp'' to
state that the average sales flow rate of gas is to be obtained at
standard conditions. We are also clarifying that Equation W-33 is to be
used to convert the sales flow rate from actual to standard conditions.
In addition, the definition for parameter WDp has been
clarified to mean the distance between the either the top of the well
or the lowest packer to the bottom of the well. Furthermore,
CDp in Equation W-8 and TDp in Equation W-9
represent the internal diameter of the casing and tubing, respectively.
Finally, the reference to 40 CFR 98.233 (t) in 40 CFR 98.233 (f)(2) and
98.233 (f)(30) has been removed to avoid double correction for standard
conditions.
For parameter SPp in Equation W-8, EPA is allowing the
use of shut-in pressure, surface pressure, or casing-to-tubing pressure
of one well from the same sub-basin multiplied by the tubing pressure
of each well in the same sub-basin. For parameter SPp in
Equation W-9, EPA is allowing the use of an engineering estimate based
on best available data to determine the sales line pressure. EPA is
adding options and flexibility because of comments suggesting that the
shut-in pressure is not known for all wells. Finally, the units for
SPp in Equation W-8 and W-9 have been corrected from pounds
per square inch absolute instead of pounds per square inch atmosphere.
Accordingly, in the data reporting requirements in 40 CFR
98.236(c)(5), we are making a harmonizing change, consistent with the
amendments described above. Separate reporting requirements have been
included for Calculation Methodology 2 and 3 because emissions are not
reported by well tubing diameter grouping and pressure grouping within
each sub-basin category as in Calculation Methodology 1. All added
requirements are data elements used in the engineering calculation in
Equation W-8 and W-9.
Gas Well Venting During Completions and Workovers from Hydraulic
Fracturing. EPA is amending 40 CFR 98.233(g) to account for the changes
in aggregation from field level to sub-basin category for taking
measurements, as proposed. First, we are replacing the term ``field''
with ``sub-basin and well type (horizontal vs. vertical) combination''
in the parameter definitions and clarifying that the GHG emissions are
determined for each sub-basin and well type combination.
Next, we are amending Equation W-10A and adding Equation W-10B.
Reporters can use Equation W-10A if the backflow from all the wells in
a sub-basin and well-type combination are not being metered, where as
reporters can use Equation W-10B if the backflow volumes from all wells
in a sub-basin and well-type combination are being metered.
In Equation W-10A, the time period parameter Tp is
redefined to be the time of backflow for the completion or workover.
Equation W-10A has a new parameter, FRM, which represents the ratio of
backflow during completions and workovers to 30-day production rate.
FRM is calculated in Equation W-12 by dividing the metered flowback
volume from the measured well(s) by the 30 day production rate. This
ratio allows reporters to determine a backflow rate for wells that are
not measured using the first 30 days production flow rate
(PRp), which is readily available to reporters. EPA also
added a reference to 40 CFR 98.233 (g)(3) in the parameter definition
of SGp.
EPA is adding Equation W-10B to allow reporters to determine
emissions if the backflow volumes are measured for all wells in a sub-
basin and well-type combination. Reporters must measure the complete
backflow volume during the completion or workover. This is represented
by the parameter FVp in Equation W-10B.
In Equation W-10A and Equation W-10B, EPA is adding the parameter
W, which is the number of wells completed or worked over using
hydraulic fracturing in a sub-basin and well type combination, and,
where appropriate, made the parameters applicable to each well p. These
amendments correct the summation operator to make it mathematically
accurate.
In Equation W-11C, EPA is finalizing amendments to allow reporters
to use best engineering estimate based on best available data to
determine whether the well flow of gas during backflow (i.e.
FRp) is sonic or sub-sonic flow. EPA also clarified in 40
CFR 98.233(g)(1)(ii) that reporters can determine whether to use
Equation W-11A, which is for sub-sonic flow, or Equation W-11B, which
is for sonic flow.
EPA is clarifying that paragraphs 40 CFR 98.233 (g)(1)(iv) and 40
CFR 98.233 (g)(1)(v) are applicable to Equation W-10A only. EPA is
replacing 40 CFR 98.233(g)(3) with 40 CFR 98.233(g)(5). Previously, the
requirements stated in these paragraphs were duplicative.
Lastly, we are finalizing several harmonizing changes to the data
reporting requirements for this emissions source in 40 CFR 98.236
(c)(6)(i). We are indicating in the data reporting requirements that
reporting is required for each sub-basin category and well type
(horizontal or vertical) combination. EPA amended certain requirements
to make them only applicable to Equation W-10A. In addition, EPA is
clarifying that the flow rate and time determinations are for backflow
during the completion or workover and not for when backflow is vented
to the atmosphere or routed to flare. EPA is clarifying that the number
of reduced emissions completions and the volume of gas recovered must
be reported separately for well completions and workovers. EPA is also
clarifying that emission vented directly to the atmosphere must be
reported separately from emissions resulting from flaring of backflow
gas from well completions and workovers with hydraulic fracturing.
Gas Well Venting During Completions and Workovers Without Hydraulic
Fracturing. In this section we are revising the introductory text by
deleting the term ``well workovers not involving hydraulic fracturing''
because it was repetitive. EPA also added a reference to 40 CFR
98.233(v) to convert CH4 and CO2 volumetric
emissions to mass emission.
Second EPA is requiring reporting on a sub-basin level instead of a
field level. Thus, the term ``field'' has been changed to ``sub-basin''
in the definition for the parameter ``Nwo'' and ``f'' in
Equation W-13, consistent with the proposed change from ``field'' to
``sub-basin'' across subpart W. Additionally, we are revising the
parameters and their respective definitions to correctly
[[Page 80562]]
represent standard conditions and not actual conditions. Finally, EPA
is amending the summation operator in Equation W-13 to make it
mathematically accurate. This includes adding the subscript ``p'',
which is an index for each completion without hydraulic fracturing in a
sub-basin, and making specific parameters in Equation W-13 applicable
to each well completion, ``p''.
In the associated reporting requirements in 40 CFR 98.236
(c)(6)(ii), EPA clarified that only a total count of workovers that
flare or vent gas to the atmosphere need to be reported. Additionally,
EPA clarified that emissions from venting to the atmosphere and flaring
must be reported separately.
Blowdown Vent Stacks. In this action, EPA is removing the term
``equipment'' and ``equipment type'' in 40 CFR 98.233(i) and replacing
it with ``unique physical volume'' in this section. EPA also clarified
the types of blowdowns covered. We are deleting the term ``to
atmosphere'' because not every blowdown will result in the blowdown
chamber being brought to atmospheric pressure, thus more fully
portraying EPA's intent to cover these types of ``blowdowns.''
Next, we are clarifying that we only intend to cover the types of
blowdowns typically activated by operators, whether for what an
operator might perceive as an emergency shutdown or when taking
equipment out of service for operational or maintenance purposes. The
term ``activated by operators'' implies that an operator was present at
the time the blowdown was activated, and that the operator(s)
manipulated automated or manual controls to isolate the equipment and
open the blowdown valve(s). Whether the operator perceived this human
intervention to isolate and blowdown equipment as stemming from a
perceived emergency or routine operational or maintenance functions is
unimportant because the operator has full knowledge of the timing and
equipment being isolated and blown down to record for reporting
purposes. It was not EPA's intent to capture automated releases that do
not involve human intervention, such as pressure safety valve releases,
pressure controlled venting, or compressors being automatically shut
down for safety in the absence of operator presence or intervention.
Such automated safety releases or equipment shutdowns may not have
sufficient operator involvement to know the timing and exact nature of
the gas release to make an accurate accounting.
Also in this action, we are revising the numbering of Equation W-14
to be Equation W-14A, and adding an Equation, W-14B. We are adding
Equation W-14B to allow facilities to track blowdowns by each
occurrence. Equation W-14B allows reporters to account for situations
where a unique physical volume may not be blown down to atmospheric
pressure.
For both equations, Vv has been changed to V. We are
also clarifying that the parameter V is the actual physical volume of
the blowdown equipment and not the gas volume. In both equations, the
definition of parameter ``N'' has been changed to the number of times a
particular unique physical volume is blowndown to the atmosphere.
Finally, ``Ts'' has been set at 60 degrees Fahrenheit and
``Ps'' has been set at 14.7 psia.
Accordingly, revisions to 40 CFR 98.236(c)(7) were made to account
for these amendments. We are revising the data reporting requirements
for blowdown vent stacks by stating that emissions from unique volumes
that are blowndown more than once during the calendar year must be
reported by unique physical volume and the number of times that a
particular volume is blowdown must be reported. For unique physical
volumes that are blowndown only once during the calendar year,
reporters can total the emission from all of the unique volumes and
report an aggregate number. In addition, EPA added the requirement to
report the number of unique volumes that are blowndown only once during
the calendar year.
Onshore Production Storage Tanks. EPA is amending several
provisions in 40 CFR 98.233(j) for calculating GHGs from onshore
production storage tanks.
First, we are clarifying that the equipment threshold referenced
throughout this section for onshore production storage tanks is based
on an annual average daily throughput. This clarification was necessary
to address ambiguity in the final rule regarding the determination of
the throughput of oil.
Next, we are making corrections to address erroneous citations in
40 CFR 98.233(j)(1)(vii) and 40 CFR 98.233(j)(2).
Next, in this action, EPA is replacing the term ``field'' in 40 CFR
98.233(j)(1)(vii)(B), 40 CFR 98.233(j)(1)(vii)(C), and 40 CFR
98.233(j)(3)(i) with the term ``sub-basin category'' as per the
discussion in Section II.C of the September 9, 2011 proposal preamble.
EPA is also clarifying that reporting of CH4 and
CO2 emissions determined using Calculation Methodologies 3
and 4 are on an annual basis.
We are revising Equation W-15 to include a multiplier of 1,000 that
converts emissions from thousand standard cubic feet to standard cubic
feet so the calculation results in accurate units. Also, we are
amending the definitions of the parameters, EFi and Count,
to clarify that these parameters must be used for well-pad gas-liquid
separators and for wells sending liquids straight to a tank without
passing through any gas-liquid separators with throughput less than 10
barrels per day. Additionally, EPA is changing standard conditions to
60 degree Fahrenheit and 14.7 psia; therefore, the emission factors for
CH4 and CO2 at 60 degrees Fahrenheit replaced the
existing values at 68 degrees Fahrenheit.
Lastly, in Equation W-16, we are amending the definition for the
parameter En by correcting the erroneous citations, 40 CFR
98.233(j)(3) and (j)(5), and including the accurate citations, 40 CFR
98.233(j)(1), (j)(2), and (j)(4), instead. We are including a
conversion factor in this equation such that the emissions are being
determined on a yearly basis, as opposed to an hourly basis. We are
deleting the parameter Et in the equation, because it is
being accounted for in the revised equation and therefore is not
necessary.
Accordingly, we are clarifying several data reporting requirements
in 40 CFR 98.236(c)(8) for this source. First, for Calculation
Methodologies 1 and 2. Next, for Calculation Methodologies 3, 4, and 5,
vented, flared, and recovered emissions must be reported for each GHG
and all requirements must be reported at a sub-basin level. Next, we
are correcting an erroneous citation in 40 CFR 98.236(c)(8)(ii)(D).
Finally, as proposed, EPA is adding the reporting of vented emissions
for each gas at the sub-basin level for improperly functioning dump
valves. This data reporting requirement is based on the inputs to
Equation W-16 in 40 CFR 98.233(j) and therefore will not place
additional burden on reporters.
Transmission Storage Tanks. EPA is amending several provisions in
40 CFR 98.233(k) for calculating GHGs from transmission storage tanks.
First, we are revising 40 CFR 98.233(k)(1) to include an additional
provision for monitoring the transmission storage tank vapor vent
stack. With this amendment, reporters can either screen their tanks
first by using the optical gas imaging instrument for 5 continuous
minutes and, if a leak is detected, measure the leak according to the
provisions in 40 CFR 98.234 consistent with the 2010 final rule, or
measure the tank vent vapors for 5
[[Page 80563]]
minutes either using a flow meter or high volume sampler, or
alternatively a calibrated bag based on manufacturers specifications
according to the provisions outlined in 40 CFR 98.234.
Next, EPA is clarifying that emissions, determined in 40 CFR
98.233(k)(2) and (k)(4), are on an annual basis. Next, in 40 CFR
98.233(k)(4)(i), we are deleting the erroneous citation to 40 CFR
98.233(j)(1). Lastly, in 40 CFR 98.233(k)(4)(ii), we are clarifying
that flare stack calculation methodology from 40 CFR 98.233(n) should
be used for emissions that are sent to a flare and not from the flare.
EPA is amending two associated data reporting requirements in 40
CFR 98.236(c)(9). We are clarifying that vented and flared emissions
for each GHG, must be reported for each transmission storage tank.
Additionally, we are finalizing the reporting of a unique name or ID
number, as proposed, for each transmission storage tank as per the
discussion in Section II.D of this preamble.
Well Testing Venting and Flaring. EPA is amending the calculation
methodologies under this source to make them applicable to gas wells
and to situations wherein production from a group of wells is routed
through the same pipe. In particular, EPA is adding Equation W-17B
which uses the production rate of a gas well to estimate well testing
venting emissions from gas wells. Additionally, EPA is clarifying that
both equations apply to one or more wells being tested.
EPA is amending the data reporting requirements in 40 CFR
98.236(c)(10), to clarify that for each GHG, reporters must report
emissions from well testing venting and from well testing flaring
separately. These emissions from well testing venting and well testing
flaring are calculated individually in 40 CFR 98.233(l); therefore,
this places no additional burden on reporters.
Associated Gas Venting and Flaring. EPA is revising 40 CFR
98.233(m)(1) to replace the term ``field'' with the term ``sub-basin
category'' as per the discussion in Section II.C of the September 9,
2011, GHGRP Revisions Proposal.
EPA is amending the data reporting requirements in 40 CFR
98.236(c)(11), to clarify that for each GHG, reporters must report
emissions from associated natural gas venting and from associated
natural gas flaring separately. These emissions from associated natural
gas venting and associated natural gas flaring are calculated
separately in 40 CFR 98.233(m); therefore, this places no additional
burden on reporters.
Flare Stack Emissions. EPA is amending several provisions in 40 CFR
98.233(n) for calculating GHGs from flare stacks.
First, we are amending 40 CFR 98.233(n)(2)(ii) to clarify that
reporters of onshore natural gas processing plants that solely
fractionate a liquid stream, must use the GHG mole percent in feed
natural gas liquid for all streams. This amendment addresses the lack
of clarity in the final provisions on how natural gas processing plants
that only fractionate liquid streams would determine their gas
compositions.
Next, we are revising 40 CFR 98.233(n)(2)(iii) to clarify that for
any applicable industry segment, methane, in addition to ethane,
propane, butane, pentane-plus and mixed light hydrocarbons, should be
accounted for when the stream going to the flare is a hydrocarbon
product stream. This correction ensures that the paragraph 40 CFR
98.233(n)(2)(iii) is consistent with the Equation W-21.
Next, we are clarifying the summation operator in Equation W-21 to
make the equation mathematically correct. Additionally, we are
clarifying, in 40 CFR 98.233(n)(11), that source types in 40 CFR 98.233
that send emissions to a flare and use Equations W-19 through W-21,
must determine volumetric flow rate, parameter ``Va'', in
Equation W-19 through W-21, at actual conditions.
EPA did not intend to unnecessarily limit the measurement options
for flares that operate and maintain a continuous emissions monitoring
system (CEMS). EPA is now allowing the reporters to calculate
CO2 emissions from flares that operate and maintain a CEMS,
using Tier 4 Calculation Methodology and all associated calculation,
quality assurance, reporting, and recordkeeping requirements for Tier 4
in subpart C of this part (General Stationary Fuel Combustion Sources).
This includes following the procedures for initial certification of the
CEMS and the ongoing quality assurance requirements for the CEMS
specified in 40 CFR 98.34(c). Also, EPA is exempting the reporting of
CH4 and N2O emissions from flares that operate
and maintain a CEMS.
EPA is making several amendments to the data reporting requirements
in 40 CFR 98.236(c)(12). First, we are amending requirements to clarify
that uncombusted CH4 emissions, combusted CO2
emissions, uncombusted CO2 emissions, and combustion-related
N2O emissions must be reported separately. Second, we are
adding the reporting of combined combusted and uncombusted
CO2 emissions from flares that operate and maintain a CEMS.
These uncombusted CH4, combusted CO2, uncombusted
CO2, combustion-related N2O emissions, and
combined combusted and uncombusted CO2 emissions from flares
that operate and maintain a CEMS are calculated separately in 40 CFR
98.233(n); therefore, these requirements place no additional burden on
reporters. Lastly, we are finalizing the reporting of a unique name or
ID number, as proposed, for each flare stack under onshore natural gas
processing as per the discussion in Section II.D of this preamble.
Centrifugal Compressor Venting. EPA is finalizing amendments that
were made across the sections in 40 CFR 98.233 to standardize reporting
for standard conditions. First, EPA is clarifying two parameter
definitions under this source. First, in Equation W-24, we are amending
the definition of parameter MTm to clarify that flow
measurements must be determined in standard cubic feet per hour.
Second, EPA is changing standard conditions to 60 degrees Fahrenheit
and 14.7 psia; therefore, in Equation W-25, the emission factors for
GHGi at 68 degrees Fahrenheit were removed from the
parameter EFi.
Reciprocating Compressor Venting. EPA is finalizing amendments that
were made across the section in 40 CFR 98.233 to standardize reporting
for standard conditions. First, EPA is clarifying two parameter
definitions under this source. First, in Equation W-28, we are amending
the definition of parameter MTm to clarify that flow
measurements must be determined in standard cubic feet per hour.
Second, EPA is changing standard conditions to 60 degrees Fahrenheit
and 14.7 psia; therefore, in Equation W-29, the emission factors for
GHGi at 68 degrees Fahrenheit were removed from the
parameter EFi.
Leak Detection and Leaker Emission Factors. We are revising 40 CFR
98.233(q)(8) to remove the term ``city gate stations at custody
transfer'' and replace with the term ``transmission-distribution
transfer stations'' for the reasons described in Section II.C of the
September 9, 2011 GHGRP Revisions Proposal. We are also removing the
term ``meters and regulators'' and replacing these terms with above
ground ``metering-regulating stations''.
EPA is revising equation W-30A, previously designated at W-30A in
the November 2010 final rule (75 FR 74458), to clarify the summation
operator to make it mathematically correct. This clarification includes
amending the term ``x'' to be the count of each equipment leak source
as listed in Table
[[Page 80564]]
W-7 and adding Tp, which is the total time the component p
was found leaking and operational. We are also revising the parameter
GHGi. For industry segments listed in 40 CFR 98.230(a)(4)
and (a)(5), GHGi has been revised to 0.974 for CH4 and 1.0 x
10-2 for CO2. For industry segments listed in 40
CFR 98.230(a)(6) and (a)(7), GHGi equals 1 for
CH4 and 0 for CO2. For industry segments listed
in 40 CFR 98.230(a)(8), GHGi equals 1 for CH4 and
1.1x10-2 CO2.
EPA is adding the option in 98.233(q)(8)(A) for natural gas
distribution facilities to conduct monitoring at their transmission-
distribution transfer stations over a multiple year period, not
exceeding five years. For more information on the comments received and
EPA's response to this topic see Section II.D Responses to Major
Comments submitted on the Petroleum and Natural Gas Systems Source
Category of this preamble. Facilities that choose to use the multiple
year option are required to conduct monitoring at roughly the same
number of T-D stations over the cycle without repetition of the same T-
D stations within the cycle.
EPA is also adding a new Equation W-30B to account for emissions
from leaking sources at above ground T-D transfer stations when the
facility chooses to conduct monitoring at T-D transfer stations over a
multiple year cycle. Equation W-30B maintains a rolling sum of
emissions from T-D transfer stations that have been monitored over the
multiple years in the cycle and results in a rolling average in
Equation W-32 for each meter/regulator run. EPA has also added three
terms t, n, and Tp,q that are in Equation W-30B. The term t
defines the calendar year, n defines the number of years in the cycle
over which all T-D transfer stations will be monitored, and
Tp,q defines the total time the leak source p was found
leaking and operational in the multiple year cycle. Finally, EPA has
clarified that Equation W-30A applies to facilities listed in 40 CFR
98.230(a)(3)-(a)(7) and Equation W-30B applies to facilities listed in
40 CFR 98.230(a)(8).
We are amending the data reporting requirements associated with the
changes to 40 CFR 98.233(q) and (r) in 40 CFR 98.236(c)(16). We are
revising the requirements based on the revisions to the data
calculation methodologies for Local Distribution Companies that choose
to use the 5-year rolling survey plan. These revisions include
provisions for facilities to report the total number of T-D stations at
their facility, the number of years over which all T-D transfer
stations will be monitored at least once, and the number of T-D
stations that are being monitored in the calendar year. We are also
amending the reporting requirements in 40 CFR 98.236(c)(16) to clarify
that facilities must report CH4 emissions collectively by
emission source type and CO2 emissions collectively by
emission source type.
Population Count and Emission Factors. We are finalizing several
amendments in 40 CFR 98.233(r). First we are amending the definition of
EFs in equation W-31 by replacing the term ``non-custody
transfer city-gate'' with ``meter/regulator runs'' at above grade
``metering-regulating stations'' for the reason stated in Section II.C
of the September 9, 2011 proposal. We are also clarifying that the
count in equation W-31 applies to the number of ``meter/regulator
runs'' at all ``metering-regulating stations'' combined.
We are also amending the term ``count'' in W-31 to elaborate and
clarify how each industry segment should count the total number of
equipment/components. In that same equation, for industry segments
listed in 40 CFR 98.230 (a)(4) and (a)(5), we are revising
GHGi to 0.952 for CH4 and 1.0 x 10-2
for CO2. For industry segments listed in 40 CFR 98.230(a)(6)
and (a)(7), GHGi equals 1 for CH4 and 0 for
CO2. For industry segments listed in (a)(8), GHGi
equals 1 for CH4 and 1.1 x 10-2 CO2.
Next, EPA is amending 40 CFR 98.233(r)(2)(i) to explicitly state
how meters and piping are to be counted. Based on this amendment,
owners or operators should use one count of meters/piping per well-pad.
Further, EPA is amending 40 CFR 98.233(r)(6)(i) by replacing the
term ``below grade meters and regulators'' with the term, ``below grade
metering-regulation stations''. EPA is also amending 40 CFR
98.233(r)(6)(ii) by referring to ``metering-regulating stations'' in
place of ``city gate'' and to clarify that the emission factor for
meter/regulator runs at all metering-regulating stations in Equation W-
32 is based on ``transmission-distribution transfer stations'' that
were monitored over the years that constitute one complete cycle per 40
CFR 98.233(q)(8)(A).
Lastly, we are revising Equation W-32 by revising definitions to
EF, Es,i, and ``Count'' to reflect the change in terminology
from ``custody transfer'' for above ground ``metering-regulating''
stations. We are also revising Equation W-32 to include a conversion
factor to convert to hourly emissions. Also, equation W-32 is amended
in 40 CFR 98.233(r) so that the equation yields an EF in cubic feet per
meter per hour to be used in Equation W-31 for above ground metering-
regulating stations. Finally, the summation operator has been removed
in Equation W-32 because Es,i represents annual volumetric
GHGi emissions at all T-D transfer stations, making the
summation operator redundant.
Volumetric Emissions. We are amending several provisions in 40 CFR
98.233(t). First, we are clarifying that reporters must calculate
natural gas volumetric emissions at standard conditions by converting
natural gas volumetric emissions at actual temperature and pressure to
standard temperature and pressure. Next, the phrase ``by converting
actual temperature and pressure of natural gas emissions to standard
temperature and pressure of natural gas'' in 40 CFR 98.233(t)(2) was
deleted because of redundancy. Next, EPA has changed standard condition
to 60 degrees Fahrenheit and 14.7 psia; therefore, in Equations W-33
and W-34, EPA is including these standard temperature and pressure
values for Ts and Ps. Lastly, EPA is providing a
ratio of 519.67/527.67 to convert volumetric emissions from 68 [deg]F
to 60 [deg]F for reporters using 68 degrees Fahrenheit for standard
temperature.
GHG Volumetric Emissions. We are amending several provisions in 40
CFR 98.233(u). First, we are clarifying that reporters may determine
the mole fraction of GHGs in natural gas by engineering estimate based
on best available data unless EPA is requiring another method. Next, we
are clarifying that when using a continuous gas composition analyzer,
reporters must use an annual average of the values to determine the GHG
mole fraction in produced natural gas. In addition, when reporters are
not using a continuous gas composition analyzer, reporters must use an
annual average gas composition based on the reporter's most recent
available sample analysis of the sub-basin category or facility,
depending on the emission source, instead of the actual most recent gas
composition based on available analysis in a sub-basin entity.
Next, we are amending 40 CFR 98.233(u)(2)(ii) to clarify that
reporters of onshore natural gas processing plants that solely
fractionate a liquid stream, must use the GHG mole percent in feed
natural gas liquid for all streams. This amendment addresses the lack
of clarity in the final provisions on how natural gas processing plants
that only fractionate liquid streams would determine their gas
compositions.
[[Page 80565]]
We are amending 40 CFR 98.233(u)(2)(iii) through (u)(2)(vii), to
include 95 percent methane/1 percent CO2 default gas
composition for the natural gas transmission compression, underground
natural gas storage, LNG storage, and natural gas distribution industry
segments and for LNG export facilities that receive gas from
transmission pipelines unless specified otherwise in the Calculations
for GHGs sections. Lastly, we are replacing the term ``field'' with the
term ``sub-basin category'' as per the discussion in Section II.C of
the September 9, 2011.
GHG Mass Emissions. We are amending several provisions in 40 CFR
98.233(v). First, we are removing the phrase ``at standard conditions''
from the introductory text and the subscript ``s,'' and the word
``standard'' from the definition of parameter Masss,i
because mass emissions do not need to be reported at standard
conditions. Next, we are revising the definitions of parameters in
Equation W-36 to clarify that the equation also applies to
N2O emissions. N2O emissions are calculated from
stationary combustion and flares, and this edit is needed to convert
the mass emissions of N2O to carbon dioxide equivalents of
gas. Lastly, EPA has changed standard conditions to 60 degree
Fahrenheit and 14.7 psia; therefore, the density values for
CH4, CO2, and N2O at 68 degrees
Fahrenheit were removed from the parameter [rho]i.
EOR injection pump blowdown. We are amending two parameters in
Equation W-37. First, we are removing the subscript ``c'' from the
parameter Massc,i and the phrase ``at critical conditions''
from the definition of parameter Massc,i because mass
emissions do not need to be reported at critical conditions. Second, we
are amending the parameter GHGi and Massc,i, to
read GHGCO2 and Masss,CO2, to clarify that
Equation W-37 only calculates CO2 emissions.
EPA is clarifying the data reporting requirements in 40 CFR
98.236(c)(17) to state that annual emissions for each GHG, must be
reported for each EOR pump.
EOR hydrocarbon liquids dissolved CO2. We are amending
the parameter Masss,CO2 by removing the subscript ``s'' and
the phrase ``at standard conditions'' from the definition of parameter
Masss,CO2 because mass emissions do not need to be reported
at standard conditions.
EPA is clarifying the data reporting requirements in 40 CFR
98.236(c)(18) to state that all parameters, including annual
CO2 emissions, must be at a sub-basin level.
Onshore Production and Distribution Combustion Emissions. EPA is
making several amendments to the provisions in 40 CFR 98.233(z).
First, we are clarifying that Calculation Methodologies in 40 CFR
98.233(z)(1) and (z)(2) apply to all stationary or portable equipment
except external fuel combustion sources with a rated heat capacity
equal to or less than 5 mmBtu/hr. In addition, 40 CFR 98.233(z)(1) and
(z)(2) apply to all internal fuel combustion sources, with a rated heat
capacity equal to or less than 1 mmBtu/hr (not compressor-drivers). EPA
is clarifying that for units below the 5 mmBtu/hr and 1 mmBTU/hr
threshold, outlined in 40 CFR 98.233(z)(3) and (z)(4), reporters do not
need to report combustion emissions or include these emissions for
threshold determination in 40 CFR 98.231(a). Instead, reporters must
report the type and number of each external fuel combustion unit and
each internal fuel combustion unit below the equipment threshold.
EPA is clarifying when owners or operators of onshore production
and distribution facilities must use the methods in 40 CFR subpart C to
calculate combustion-related emissions and when they must use methods
outlined in 40 CFR 98.233(z) to calculate combustion-related emissions.
EPA is clarifying that facilities using subpart C to calculate
emissions can use any Tier listed in subpart C. Regardless of the Tier
used, facilities must follow the corresponding calculation, quality
assurance, reporting, and recordkeeping requirements of that Tier.
EPA is amending the requirements for units combusting field gas,
process vent gas, a blend containing field gas or process vent gas, or
natural gas that is not of pipeline quality or that has a high heat
value of less than 950 Btu per standard cubic feet. In this action, EPA
is allowing the use of company records for the purposes of calibration
for this equipment.
Next, EPA is including an engineering equation, W-39B, to determine
the annual CH4 emissions from portable or stationary fuel
combustion sources. We are also clarifying the summation operator to
make the existing equation, W-39A that calculates annual CO2
emissions from portable or stationary fuel combustion sources,
mathematically accurate. Additionally, we are also including a
combustion efficiency parameter in Equation W-39A.
We are making several amendments to Equation W-40. First, we are
changing the parameter N2O to MassN2O because
this equation calculates the annual N2O mass emissions from
the combustion of a particular type of fuel. Second, we are amending an
incorrect exponent to account for the conversion factor from kilograms
to metric tons. Lastly, we are providing actual values in the
definition of parameter HHV in Equation W-40.
Accordingly, EPA is amending the data reporting requirements in 40
CFR 98.236(c)(19) for external fuel combustion sources with a rated
heat capacity greater than 5 mmBtu/hr, and internal fuel combustion
sources (excluding a compressor-driver), with a rated heat capacity
equal to or less than 1 mmBtu/hr, and internal fuel combustion sources.
First, we are clarifying that for external fuel combustion sources with
a rated heat capacity larger than 5mmBtu/hr, the emissions for each GHG
must be reported by type of unit. Second, we are clarifying that for
internal fuel combustion sources, with a rated heat capacity equal to
or less than 1 mmBtu/hr (excluding a compressor-driver), only the
cumulative number of units must be reported by type of unit. Lastly, we
are clarifying that for internal fuel combustion units, the emissions
for each GHG must be reported by type of unit.
Monitoring and QA/QC Requirements. We are finalizing several
amendments to the monitoring and QA/QC requirements in 40 CFR 98.234.
First, we are amending the language in 40 CFR 98.234(a)(1) by
removing and reserving the text in 40 CFR 98.234(a)(4) and combining it
with 40 CFR 98.234(a)(1), thus resulting in one consolidated paragraph
for optical gas imaging instrument provisions. We are also explicitly
stating exceptions to the requirement under the Alternative work
practice for monitoring equipment leaks. Those exceptions are (1) the
monitoring frequency is annual and (2) the detection sensitivity is 60
grams per hour. In addition, EPA is requiring that the gas chosen
during the instrument check must be methane. Finally, EPA is clarifying
that video recordings are not required to be retained for the purposes
of 40 CFR part 98, subpart W.
Next, we are amending the language in 40 CFR 98.234(a)(2) to state
that Method 21 compliant instruments may be used to monitor
inaccessible emissions sources. It is not EPA's intent here to require
reporters to use unsafe methods to reach inaccessible emission sources
using Method 21 compliant equipment. Rather EPA is allowing the use of
Method 21 compliant leak detection equipment where the reporter can
access inaccessible sources using safe options, such as the use of a
bucket truck. EPA still requires the use of
[[Page 80566]]
optical imaging cameras to reach inaccessible emission sources where
the reporter cannot use Method 21 compliant leak detection equipment
safely. EPA allows the use of method 21 for all source types, although
an optical gas imaging instrument must be used in cases where a
reporter deems a source type inaccessible. EPA expects the reporters
will use an optical gas imaging instrument in order to ensure safety
when monitoring inaccessible source types. Lastly, based on questions
raised by industry, we are clarifying in 40 CFR 98.234(a)(5) the type
of acoustic leak detection devices that may be used. In particular the
``gun'' type instrument, which is aimed at the equipment from a
distance to detect the acoustic signal of leakage, is not an allowable
instrument under this rule. This type of equipment cannot distinguish
between external leakage to the atmosphere and internal, through-valve
leakage, which acoustic leak detection devices are used for under this
rule. EPA is also further specifying that the ``stethoscope'' type
acoustic detector that senses through valve leakage when put in contact
with the valve body, but does not have the leakage estimating
correlations, is permissible for leak detection only under this rule.
We are including an editorial revision in 40 CFR 98.234(c) for
calibrated bagging to specify that those using the calibrated bag for
sampling, must ensure that the emissions are at a temperature below
which the bag manufacturer specifies for safe handling. EPA is also
clarifying in 40 CFR 98.234(d)(3) that emission volumes determined
using the high volume sampler can be converted to standard conditions
using 40 CFR 98.233(t). Finally, we are revising Equation W-41 to
insert missing variables ``a'' and ``b'' from the Peng Robinson
equation.
Data Reporting Requirements. The amendments to the reporting
requirements for various emission source types are discussed under the
corresponding emission source paragraphs in this section of the
preamble. Additionally, EPA is making the following amendments to the
general reporting requirements in 40 CFR 98.236.
First, we are amending 40 CFR 98.236(b) to clarify that facilities
reporting under the offshore petroleum and natural gas production
industry segment must report emissions for each GHG, as applicable to
the source type, for each emissions source type listed in the most
recent Bureau of Ocean Energy Management and Regulatory Enforcement
(BOEMRE) study.
Next, we are clarifying that if a facility operates under more than
one industry segment, reporters must report the data from each piece of
equipment under the industry segment in which the equipment is most
used. Additionally, we are clarifying that if a source type routes gas
to a flare, reporters must report vented and flared emissions
separately for each gas. These vented and flared emissions must be
reported under the respective source type and not under the flare stack
source type.
Finally, EPA is including the reporting of average API gravity of
the hydrocarbon liquids produced, average gas to oil ratio, and average
low pressure separator pressure per oil sub-basin category for onshore
production reporters.
Records that must be retained. EPA is clarifying that records that
must be retained under 40 CFR 98.3(g)(2)(i) of the general provisions
must include an explanation of how company records, engineering
estimation, or best available information are used to calculate each
applicable parameter under this subpart. This requirement is already
included in 40 CFR 98.3(g)(2)(i) and including this requirement in
Subpart W provides further clarity on the records facilities are
required to keep.
Definitions. EPA is amending several definitions in 40 CFR 98.238,
and in some cases, adding and removing definitions in 40 CFR 98.238.
Associated With a Single Well-Pad. We are including a definition
for ``associated with a single well-pad'' to clearly demarcate the
extent of the boundary of onshore production facilities. This
definition more clearly expresses EPA's intent that the association be
defined by the hydrocarbon stream from one or more wells located on a
single well-pad. Where the point of combination is located off that
single well-pad, the association with a single well-pad ends where the
stream from a single well-pad is combined with streams from one or more
additional single well-pads. Storage tanks located on a well pad are
considered part of the onshore production industry segment.
Distribution Pipeline. We are adding a definition for distribution
pipelines to clarify our intent for coverage for the natural gas
distribution industry segment.
Facility With Respect to Natural Gas Distribution. We are revising
the definition for facility with respect to natural gas distribution by
replacing the term ``metering stations, and regulating'' with the term
``metering-regulating'' and by clarifying that the collection of all
distribution pipelines and metering-regulating stations operated by an
LDC within a single state must be included.
Facility With Respect to Onshore Petroleum and Natural Gas
Production. We are revising the definition for facility with respect to
onshore production by clarifying that it includes all petroleum or
natural gas equipment on a single well-pad or associated with a single
well-pad and CO2 EOR operations that are under common
ownership or common control including leased, rented, or contracted
activities by an onshore petroleum and natural gas production owner or
operator and that are located in a single hydrocarbon basin as defined
in Sec. 98.238.
Farm Taps. We are revising the definition for farm taps in 40 CFR
98.238 by removing the statement ``[t]he gas may or may not be metered,
but always does not pass through a city gate station'' as this
statement is unnecessary.
Flare. We are adding a definition of flare, specific to subpart W,
to address questions received during implementation of the 2010 final
rule about what constitutes a flare. This definition clarifies that a
flare may be either at ground level or elevated and that a flare may
use an open or enclosed flame to combust waste gases without energy
recovery. The intent of this definition is to include devices that
combust waste gases without energy recovery.
Forced Extraction of Natural Gas Liquids. We are adding a
definition for forced extraction, as proposed, to limit the use of
forced extraction to specific processes. With this definition, EPA is
clarifying that ``forced extraction of natural gas liquids'' means
removal of ethane or higher carbon number hydrocarbons existing in the
vapor phase in natural gas, by removing ethane or heavier hydrocarbons
derived from natural gas into natural gas liquids by means of a forced
extraction process. Forced extraction processes include but are not
limited to refrigeration, absorption (lean oil), cryogenic expander,
and combinations of these processes.
Gas Well. We are removing the definition of gas well from 40 CFR
98.238. Gas wells are defined within the revised definition of sub-
basin category.
Horizontal Well. We are including a definition for horizontal well
in conjunction with the change from field level reporting to sub-basin
category. With this definition, we are stating that a horizontal well
means a well bore that has a planned deviation from primarily vertical
to a primarily horizontal inclination or declination tracking in
[[Page 80567]]
parallel with and through the target formation.
Metering-regulating Station. We are adding this definition to
clarify that metering-regulating stations are stations that meter the
flowrate, regulate the pressure, or both, of natural gas in a natural
gas distribution facility. These do not include customer meters,
customer regulators, or farm taps.
Natural Gas. We are adding this definition, as proposed, to clarify
that natural gas means a naturally occurring mixture or process
derivative of hydrocarbon and non-hydrocarbon gases found in geologic
formations beneath the earth's surface, of which its constituents
include, but are not limited to, methane, heavier hydrocarbons and
carbon dioxide. Additionally, we are clarifying that natural gas may be
field quality, pipeline quality, or process gas.
Oil Well. We are removing the definition for oil well from 40 CFR
98.238. Oil wells are defined within the revised definition of sub-
basin category.
Pressure Groups. We are adding a definition of pressure groups, as
proposed, as applicable to each sub-basin to clarify that pressure
groups are: Less than or equal to 25 psig; greater than 25 psig and
less than or equal to 60 psig; greater than 60 psig and less than or
equal to 110 psig; greater than 110 psig and less than or equal to 200
psig; and greater than 200 psig. The pressure in the context of
pressure groups is either the well shut-in pressure; well casing
pressure; or you may use the casing-to-tubing pressure of one well from
the same sub-basin multiplied by the tubing pressure for each well in
the sub-basin.
Sub-Basin Category. We are including a definition for a sub-basin
category in conjunction with the change in measurement from field to
sub-basin level. Based on this definition, a sub-basin means a
subdivision of a basin into the unique combination of wells with the
surface coordinates within the boundaries of an individual county and
subsurface completion in one or more of each of the following five
formation types: Oil, high permeability gas, shale gas, coal seam, or
other tight reservoir rock. The distinction between high permeability
gas and tight gas reservoirs shall be designated as follows: High
permeability gas reservoirs with >0.1 millidarci permeability, and
tight gas reservoirs with <=0.1 millidarci permeability. Permeability
for a reservoir type shall be determined by engineering estimate. Wells
that produce from high permeability gas, shale gas, coal seam, or other
tight reservoir rock are considered gas wells; gas wells producing from
more than one of these formation types shall be classified into only
one type based on the formation with the most contribution to
production as determined by engineering knowledge. All wells that
produce hydrocarbon liquids and do not meet the definition of a gas
well in this sub-basin category definition are considered to be in the
oil formation. All emission sources that handle condensate from gas
wells in high permeability gas, shale gas, or tight reservoir rock
formations are considered to be in the formation that the gas well
belongs to and not in the oil formation.
Transmission-Distribution (TD) Transfer Station. As proposed, EPA
is adding a definition for Transmission Distribution (TD) transfer
station to define what was previously termed ``custody transfer'' in
the final rule. This definition was necessary to further clarify EPA's
intent, which was not for the term ``custody transfer'' to be defined
in the context of ownership of gas transfer. The TD transfer station
means a meter-regulating station where a local distribution company
takes part or all of the natural gas from a transmission pipeline and
puts it into a distribution pipeline.
Transmission Pipeline. We are finalizing a definition as proposed
for transmission pipeline to clarify that transmission pipelines are
clearly designated as such by the Federal Energy Regulatory Commission
for interstate transmission pipelines, individual States for intrastate
transmission pipelines, and the Hinshaw exemption under the Natural Gas
Act for Hinshaw transmission pipelines.
Tubing diameter groups. We are finalizing a definition for tubing
diameter groups, as proposed, to clarify that tubing diameter groups
are: less than or equal to 1 inch; greater than 1 inch and less than 2
inch; and greater than or equal to 2 inch.
Tubing systems. We are finalizing a definition of tubing systems,
as proposed, to clarify that tubing systems means piping equal to or
less than one half inch diameter as per nominal pipe size.
Vertical Well. We are finalizing a definition for vertical wells,
as proposed, to coincide with the change from field level reporting to
sub-basin category, EPA is adding a distinction for calculating
emissions from horizontal wells and vertical wells. With this
definition, a vertical well means a well bore that is primarily
vertical but might have some unintentional deviation or one or more
intentional deviations to enter one or more subsurface targets that are
off-set horizontally from the surface location, intercepting the
targets either vertically or at an angle.
Well Testing Venting and Flaring. We are finalizing, as proposed, a
definition for well testing venting and flaring. This definition says
that well testing venting and flaring means venting and/or flaring of
natural gas at the time the production rate of a well is determined
(i.e., the well testing) through a choke (an orifice restriction).
Based on this revised definition, if well testing is conducted
immediately after well completion or workover then it would be
considered part of a completion or workover.
Emission Factor Tables. We are amending several emission factors in
subpart W in response to comments requesting that the emission factors
be adjusted to reflect a consistent standard temperature and pressure
used for calculation methodologies in 40 CFR 98.233. Specifically, we
are revising all of the entries to 60 degrees Fahrenheit for Tables W-
1A and W-2 through W-6 and revising the entries for ``Low Continuous
Bleed Pneumatic Device Vents'', ``High Continuous Bleed Pneumatic
Device Vents'', and ``Intermittent Bleed Pneumatic Device Vents'' to
whole gas emission factors in Table W-1A. Additionally, we are revising
the entries for ``Leaker Emission Factors--Transmission-Distribution
Transfer Station Components, Gas Service,'' ``Population Emission
Factors--Below Grade Metering-Regulating Station Components, Gas
Service,'' ``Population Emission Factors--Distribution Mains, Gas
Service,'' and ``Population Emission Factors--Distribution Mains, Gas
Service'' to 60 degrees Fahrenheit.
D. Responses to Major Comments Submitted on the Petroleum and Natural
Gas Systems Source Category
This section contains a brief summary of major comments and
responses on the proposed amendments to subpart W published in GHGRP
Corrections Proposal and the GHGRP Revisions Proposal. Responses to
additional comments received on those proposals can be found in the
document, ``Mandatory Reporting of Greenhouse Gases--Technical
Revisions to the Petroleum and Natural Gas Systems Category of the
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments'' see
docket EPA-HQ-OAR-2011-0512.
1. Pressure groupings
Comment: EPA received comments requesting two pressure ranges for
calculating emissions from liquids unloading of gas wells in 40 CFR
98.233(f) as opposed to the September 9,
[[Page 80568]]
2011 proposal, which proposed five pressure ranges, four bounded ranges
between 0-200 psig and one unbounded range above 200 psig, for this
source. Commenters also requested clarification as to whether the
proposed pressure ranges would apply across the sub-basin, including
both conventional and unconventional wells. Finally, commenters were
unclear as to what pressure types were to be used for the pressure
groupings, and requested clarification as to whether the groupings were
based on surface pressure or a different type of pressure.
Response: In response to the commenters first point, EPA has
concluded that the five pressure ranges finalized in this action are
appropriate for methodology 1 of 40 CFR 98.233(f). Greenhouse gas
emissions resulting from well liquids unloading, regardless of what
type of reservoir or gas well is involved, must be reported in the
pressure range based on shut-in pressure as defined in 40 CFR 98.238
Definitions, Pressure Group. To avoid confusion, EPA is discontinuing
the use of the terms ``conventional'' and ``unconventional'' because
these terms have different meanings within the industry. The volume of
gas released during an unloading is directly related to the wellhead
pressure. EPA analyzed different numbers of pressure groupings and
selected the optimal number of pressure groupings that resulted in
minimal error while managing burden. In this action, reporters are to
estimate emissions from one well with a unique tubing diameter grouping
and pressure grouping combination in a sub-basin, and apply that value
to all wells with that tubing diameter grouping and pressure grouping
in that same sub-basin.
Please refer to the Pressure Analysis document in EPA-HQ-OAR-2011-
0512-0016 for background on the analysis. EPA evaluated several
different pressure groupings and their appropriateness to this
emissions source, including the option suggested by the commenter, of
two pressure groupings. Based on EPA's analysis documented in the memo
to the docket, industry's suggestion of using only two pressure
groupings would not provide the sufficient amount of accuracy in
characterizing similar wells in the same sub-basin. Based on the five
pressure groupings, EPA estimates that the minimum error would be about
30 percent from all wells that would report. However, if the number of
ranges were reduced to 2 pressure groupings then the minimum error that
would result from all wells is about 65 percent. These error estimates
are based on theoretical calculations, not accounting for error in
meter reading and human error. Given the large error in the two
pressure grouping scenario, EPA has determined that a 5 pressure
grouping is the optimal for balancing burden to monitor versus the
quality of data required to inform policy.
To address the commenter's question about whether or not the five
pressure groupings would apply to emission sources other than the
liquids unloading emission source, EPA believes that final the
provisions provide sufficient clarification. In particular, EPA has
clarified in 40 CFR 98.233(f) that the five pressure groupings apply to
the liquids unloading emissions source only. Furthermore, EPA has added
a definition for pressure groupings in 40 CFR 98.238 to explicitly
state what those pressure groupings apply to the liquids unloading
emission source. Pressure groupings apply only to gas wells for liquids
unloading as specified in 40 CFR 98.233(f), and do not apply to the oil
sub-basin formation.
Finally, in response to the commenters' request for clarity as to
what types of pressures are used in the pressure grouping, EPA has
finalized a definition for pressure groupings that clarifies that the
well shut-in pressure just before liquids unloading, well casing
pressure just before liquids unloading, or casing to tubing pressure of
one well just before liquids unloading from the same sub-basin can be
used for the pressure groupings.
2. Data Reporting Requirements of 40 CFR 98.236(e)
Comment: EPA received comments on data reporting requirements for
sub-basins in 40 CFR 98.236(e), specifically that API gravity, average
gas to oil ratio and average low pressure separator pressure are not
available or appropriate for applications to each of the sub-basin
categories. The commenters assert for example, that dry gas production
areas, such as coal-bed methane, will not have API gravity or gas to
oil ratios to report for a sub-basin. Commenters further noted that
this reporting requirement is applicable only to an oil production sub-
basin category.
Response: EPA agrees and has amended 40 CFR 98.236(e) to clearly
indicate that only onshore petroleum and natural gas production
reporters must report the average API gravity of their hydrocarbon
liquids produced and the average gas to oil ratio per the oil formation
sub-basin entity as defined in 40 CFR 98.238.
In September 2011, EPA proposed additional data reporting
requirements for onshore petroleum and natural gas production reporters
to report the average API gravity of the hydrocarbon liquids produced,
average gas to oil ratio, and average low pressure separator pressure
per sub-basin entity. With the exception of the low pressure separator
pressure, this information is already known to operators. In order to
pay royalties and taxes, producers routinely conduct analyses on their
produced crude oil to determine the gas to oil ratio and API gravity.
Therefore, EPA has determined that this requirement would impose no
additional burden on the industry.
3. Unique Name or ID Reporting Requirements
Comment: Several commenters representing the transmission
compression industry segment noted that the proposed requirement to
report unique ID's for the transmission storage tank source type would
not provide meaningful information and that the requirement was
inappropriate because it did not apply to the monitored source.
Furthermore, these commenters noted that in some cases, multiple tanks
are linked to a single vent, and having a requirement to report a
unique ID for each tank would not be useful, since the vent, not the
tank, is the monitored source. These commenters stated that this
requirement should be removed from the final rule.
Response: EPA agrees with the commenters, in part, and has revised
the data reporting requirements for the transmission storage tank
emissions source in 40 CFR 98.236 to more appropriately track the
emissions at the vent and not the tank. In this action, 40 CFR
98.236(c)(9)(iii) has been clarified to state that a unique name or ID
shall be assigned to the vent line.
To meet the requirements of the 2010 final rule, which require
reporting for each tank, owners and operators need to have a mechanism
for tracking emissions from each storage tank. Further, to meet the
reporting requirements, and requirements for resubmission of an annual
GHG report in the event that EPA or the facility owner or operator
identifies a substantive error (see 40 CFR 98.3(h)), owners and
operators need to have a mechanism to assign the emissions they
reported from an individual tank to the entry that they include in the
electronic GHG Reporting tool (e-GGRT) for that same tank. For this
reason, EPA has determined that the assignment of a unique ID is not
new, nor does it introduce any new requirement that was not already
required by the 2010 final rule. Rather this addition is providing
clarification of the existing reporting
[[Page 80569]]
requirements. Therefore, in this action, EPA is finalizing the
requirement to report a unique name or ID number for vents in
transmission storage tanks in 40 CFR 98.236(c)(9), as well as glycol
dehydrators in the natural gas processing industry segment in 40 CFR
98.236(c)(4), acid gas removal vents in the natural gas processing
industry segment in 40 CFR 98.236(c)(3), and flare stacks in the
onshore natural gas processing industry segment in 40 CFR
98.236(c)(12). EPA is also finalizing the requirement to report the
unique name or ID for the unique physical volume for blowdowns in 40
CFR 98.236(c)(7) for transmission compression, gas processing, and LNG
import and export industry segments.
To address the commenters comment that the unique name or ID is
unnecessary for the transmission storage tanks emission source, EPA
believes that this information is critical and has finalized this
provision for other emissions sources including the flare emissions
source and for unique blowdown physical volumes. In addition, EPA
believes that these particular emission sources are not mobile and are
generally stationary at a given facility. For example, for a source
such as transmission storage tanks, the unique ID would inform EPA on
where emissions are occurring, and over a time period of several years,
would inform the Agency of the emissions trends associated with that
particular emissions source at the facility.
Comment: EPA received comment specific to the reporting of a unique
name or ID for the gas to liquid separators in the onshore production
industry segment. Commenters noted that the proposed requirements to
report unique ID will have no impact on the current emissions inputs or
data quality, and are contradictory to industry's efforts to work with
EPA to complete an accurate GHG inventory within a manageable reporting
burden and resources. Additionally, the commenter asserted that
creating unique equipment identifiers neither adds to the level of
accuracy of calculated emissions, nor does it provide information that
is not already available through the currently reported individual
equipment counts and reported CO2 and CH4
emissions totals that are already part of the GHGRP. In onshore
production, the commenter contends that the identifier data requested
by EPA will not be usable at the individual equipment level due to the
dynamic nature of the sector and the fact that the identifiers may be
tied to well names or locations and hence be different every year due
to frequent equipment movement, change-outs and replacements that
routinely occur at oil and gas well sites.
Response: EPA agrees that for the onshore production segment, a
unique name or ID number may be difficult to assign for portable
equipment that may move from one location to another.
EPA initially proposed data reporting requirements of unique name
or ID number in the onshore production industry segment for the
following emission sources; acid gas removal units, glycol dehydrators,
wellhead separators or storage tanks, flare stacks, and EOR injection
pumps. However, after evaluating the comments received, EPA believes
that reporting of these particular emission sources in the onshore
production industry segment, which has a definition of facility at the
basin level, would be sufficient without a unique name or ID, although
some information to track emissions from specific pieces of equipment
over time could be lost, because the data will ultimately be reported
at the facility level. EPA agrees with the commenter that tracking of a
particular emission source that may be moved from one site to the next
may pose a problem to certain reporters who would find it difficult to
track an emission source to this level. Onshore producers may often
replace equipment in a process with other equipment either for
maintenance purposes or to size the equipment as the well production
rate varies over time. Given these issues that are unique to onshore
production segment, therefore EPA is not requiring unique name or ID
number in onshore production. EPA recognizes that removing this
requirement for onshore production could potentially result in the loss
of equipment-specific information that could be useful for future
policy analysis and we may continue to evaluate this for future
rulemakings.
4. Transmission-Distribution Transfer Station Reporting
Comment: Commenters generally agreed with the proposed definition
for transmission-distribution transfer station proposed in the GHGRP
Revisions Proposal. However, commenters stated that the proposed
definition for transmission-distribution transfer station would require
many more stations to be included in the leak detection survey
requirement, and that it would be an unreasonable burden. In addition,
commenters noted that the stations that would be surveyed are small and
remote stations and this would lead to an added burden to survey for
leaks. Finally, commenters urged EPA to adopt a threshold to exclude
small stations from monitoring for GHG emissions. One commenter,
specifically noted that one of their member companies completed surveys
of 162 stations in 2011, and out of 32,400 components measured, only 18
leaking components were found. The commenter noted that they surveyed
their members in October 2011 and received responses from 42 larger
member LDCs. Of those 42 LDCs, that the commenter stated that a total
of 20,781 stations would appear to fall within the final definition for
transmission-distribution stations. One commenter specifically
suggested having a percentage of the stations report and using that
percentage to forecast emissions for the other stations. Further,
several other commenters suggested using a threshold to reduce the
number of leak surveys required.
Response: EPA notes that the number of reporters (i.e., LDCs) that
EPA estimated would be reporting under the natural gas distribution
industry segment under subpart W has not changed. Because this industry
segment has a high level of uncertainty in the context of knowing the
exact number of stations that would be covered under the rule, EPA
would like to note that based on the limited information submitted by
the commenter, it could be a possibility that the number of stations
covered under the subpart W rule (75 FR 74458) between the 2010 final
rule and what is being finalized in this action may have increased. It
was not EPA's intent to increase the number of surveys required.
Therefore, after considering the two suggestions by commenters, EPA is
finalizing an option that would allow facilities to conduct a leak
detection survey once in any five consecutive calendar years for each
station. EPA added the five consecutive year leak detection period to
potentially coincide with reporters' existing inspection requirement
under DOT regulations. Therefore, the annual burden to reporters will
not increase as a result of this revision. See Transmission-
Distribution Transfer Station docket memo in docket EPA-HQ-
OAR-2011-0512.
In this action, EPA is amending 40 CFR 98.233(q)(8) by allowing
each above grade transmission-distribution transfer station the option
to conduct a leak detection survey at least once in any five
consecutive calendar years, with a minimum of 20 percent of their total
number of stations being leak surveyed annually. Reporters choosing to
use this option would use a five-year rolling average of their
transmission-distribution transfer station leaking component counts to
calculate emissions. In accordance with the
[[Page 80570]]
calculation requirements, these reporters would also define in their
monitoring plan how the annual leak surveys represent cross sections of
the total number of stations.
Furthermore, EPA evaluated Department of Transportation (DOT)
regulations for comparison in the context of monitoring frequency. As
provided in the November 2010 docket memorandum ``Understanding the
Substance of DOT Regulations and Comparing Them to the Subpart W
Requirements,'' DOT requires leak detection surveys annually for more
populated areas and every five years for less populated locations.
Although the DOT regulations covering various stations are not
duplicative of EPA regulations under the Greenhouse Gas Reporting
Program, providing the option to align the survey frequencies for both
requirements may reduce burden for some reporters. EPA added the five
consecutive year leak detection period to potentially coincide with
reporters' leak inspection requirement under DOT regulations in order
to give reporters the opportunity to fulfill Subpart W requirements
during the regular DOT survey or maintenance visit.
In response to the commenters' assertion that the final definition
for transmission-distribution transfer stations disproportionately
covers stations that are small and remote, and in response to the
commenters' suggestion to implement a threshold by which small stations
would be exempt from being surveyed for leaks, EPA disagrees that the
size of the station should impact whether leaks are surveyed because
small stations in remote locations are potentially large sources of
emissions, for example, due to aging equipment and or potentially
infrequent operator maintenance.
DOT regulations focus on public safety, and as such facilities near
business districts are inspected annually. Conversely, facilities
farther away from business districts may be inspected less frequently
and receive less frequent and less consistent maintenance attention,
increasing the chance that small or remote facilities are large
emitters. Therefore, EPA decided not to exclude remote stations. In
this action, EPA is finalizing an option for transmission-distribution
transfer stations that allows for surveying stations over a five-year
period as opposed to surveying all stations annually. Thus the annual
burden is not increased and the necessary data is collected over a
longer period of time.
5. Associated With a Single Well-Pad
Comment: EPA received several comments requesting clarification on
the intent of the proposed definition of ``associated with single well-
pad'' in 40 CFR 98.238. Commenters submitted several diagrams depicting
various configurations of equipment associated with the onshore
production industry segment and requested EPA's confirmation of their
understanding of which types of equipment would fall under the
definition for ``associated with a well-pad.''
Response: In the proposed rule, the definition stated that onshore
production storage tanks off of a well pad were included in the
equipment that was considered to be associated with a well pad. After
considering the comments received, EPA is amending the proposed
definition of ``associated with a single well-pad'' in 40 CFR 98.238 to
clarify that onshore production reporters do not report emissions from
separators or tanks that receive oil from combined streams from
multiple well-pads that are not on a single well-pad or associated with
a single well-pad. However, under 40 CFR 98.233(j), onshore production
reporters must report emissions from separators or tanks that are on a
single well-pad or associated with a single well-pad.
6. Equipment Threshold for Internal Combustion Engines
Comment: In the GHGRP Revisions Proposal, EPA solicited comments on
whether a 1 MMBtu/hr is sufficient to exclude all temporary and small
(not compressor-drivers) internal combustion equipment. EPA received
comments stating that a similar threshold to that which was in the 2010
final rule for external combustion devices should be applied to all
internal combustion devices. Several commenters representing the
natural gas distribution industry segment agreed with the proposal, but
requested that the 1 mmBtu/hr threshold also be applied to natural gas
engines. Further, commenters representing the onshore production
industry segment noted that lease fuel is reported by the Energy
Information Administration (EIA) which could be used to sufficiently
characterize combustion emissions from devices on well pads and
therefore internal combustion devices below 5 MMBtu/hr should not be
required to be reported.
Response: EPA disagrees that a threshold of 5 MMBtu should be
applied to internal combustion devices, as was done for external
combustion devices in the November 2010 final rule for subpart W. In
this action, EPA is finalizing a threshold of 1 MMBtu/hr threshold in
40 CFR 98.233(z) for internal combustion equipment. EPA has also
clarified in the final provisions for this rule that this 1mmBtu
threshold does not apply to compressor-drivers.
In considering potential equipment thresholds for internal
combustion engines (not compressor-drivers), EPA collected and reviewed
data on the horsepower rating of small, portable internal combustion
engines that may be brought to a wellhead for periodic maintenance and
construction. Such equipment can include electric generators for arc
welding, electric generators powering portable flood-lighting, and
electrical generators or gasoline engines powering air compressors (for
sand blasting or pneumatic tools). For lighting, the industrial
generators were almost exclusively below 12 horsepower (hp), with the
highest found being 13.9 hp. For welding machines, we assumed that
operators would use standard portable generators, since specific
information on these types of machines was scarce. Most portable
industrial generators are rated between 15-40 hp, with the largest one
found being 67 hp. As a result, EPA determined that a 1 mmBtu/hour
threshold, which equates to 393 hp, will exclude these smaller internal
combustion devices. EPA has also determined that a 1 mmBtu/hour
threshold may exclude a significant number of internal combustion
engines on wellhead compressors, and is thus not applying this
threshold to compressor-drivers. The equipment that would be excluded,
if the threshold were raised above 1 mmBtu could include drilling rigs,
workover rigs and hydraulic fracture pump engines, for example. EPA
deems it necessary to collect data on these compressors to inform
future policy because they are potentially large source of emissions
and also there is not sufficient and reliable data available on these
types of emissions sources. In response to the commenters' assertion
that the information is reported by the EIA and therefore is not
necessary to be reported under the greenhouse gas reporting rule, the
EIA data is reported on a voluntary basis and the requirements for
reporting are not standardized. As a result, the data available through
EIA is not sufficiently accurate to exclude combustion devices from
reporting.
Regarding the Commenters' request for the same 5 mmBtu/hour
threshold for internal combustion as applied to external combustion,
EPA is not accepting this change, because it could potentially exclude
virtually all
[[Page 80571]]
wellhead compressors and engines, including those associated from
drilling rigs which are large sources of GHG emissions. Comments on the
subpart W proposed rule (75 FR 18608) included detailed itemization of
heaters on tanks, separators, dehydrators and pipelines, often for
winter freeze protection, with estimated numbers of these external
combustion devices. From this information, EPA developed the 5 mmBtu/
hour threshold to exclude reporting of emissions from these many
sources which are not necessarily operated all year long and for which
detailed records are not maintained on when winter heating is turned on
and off, often by automated temperature controls. Similar data was not
provided for internal combustion engines, and EPA does not have a good
public record of the number of these engines or their typical duty.
7. Reporting 2011 Data Under Amended Rule
Comment: Several commenters requested that EPA resolve certain
areas of uncertainty for calendar year 2011 data collection in the
context of when the proposed revisions and technical corrections would
be finalized for 40 CFR part 98, subpart W. Specifically, API raised
concerns about two emissions sources; gas well venting during
completions and workovers with hydraulic fracturing, and well venting
for liquids unloading. API requested that for these two emission
sources reporters be allowed the option to collect data in 2012 to meet
the 2011 reporting requirements.
Response: EPA agrees that for the emission sources noted by the
commenter; gas well venting from completions and workovers with
hydraulic fracturing, and the well venting for liquids unloading
emission source types, that reporters may use 2012 data collected prior
to September 28, 2012 for reporting for the 2-year period-2011-2012.
Based on the provisions in the final rule for subpart W published
in November 2010, reporters are to collect data every other year for
use in the calculation methodologies outlined in the rule. Because of
the timing in finalizing the technical corrections and technical
revisions to subpart W, EPA believes that it would be appropriate for
reporters to be allowed to use 2012 data collected prior to September
28, 2012 for reporting for the 2-year period 2011-2012. EPA believes
that for this first two years of data collection for these emission
sources that this would fall within the procedures for estimating
missing data in 40 CFR 98.235. In addition, as previously mentioned,
the measurement taken for the 2011-2012 data collection requirement
must be taken in sufficient time to be reported by the September 28,
2011 reporting deadline for facilities reporting for onshore
production. Where applicable, EPA asserts that reporters may use the
procedures available in 40 CFR 98.235 for estimating missing data.
8. Blowdown Vent Stacks: Emergency Blowdown
Comment: Commenters noted ambiguity with the proposed revisions to
account for emergency blowdowns and requested that EPA clarify that
emergency events are excluded from blowdown vent stack emissions
reporting. Commenters further suggested that EPA delete reporting of
emissions from emergency blowdowns.
Response: EPA's intent is not to cover the blowdowns that are
automatically monitored by a computer system which performs numerous
actions for accident protection. EPA's intent is to cover those
blowdown events that require human or manned intervention. To clarify
this intent, Section 98.233(i) has been amended to clarify that
blowdown vent emissions must include blowdowns from depressurizing
equipment to reduce system pressure for planned or emergency shutdowns
resulting from human intervention or to take equipment out of service
for maintenance (excluding depressurizing to a flare, over-pressure
relief, operating pressure control venting, etc.). Any equipment
blowdown initiated by operator intervention (as opposed to automated
controls that function in the absence of operator intervention), allows
the operator to document the necessary data to determine the blowdown
volume. In other words, if any instrument indicates that equipment
needs to be taken out of service for any reason including what an
operator might consider an emergency, and the operator actuates the
automatic controls that isolate that equipment and opens the blowdown
vent, then the operator can reasonably document what unique physical
volume is isolated and depressurized, and what the starting and ending
pressures are.
The blowdown events that are excluded include controls which cause
venting in the absence of any operator presence or interaction.
Examples include over-pressure relief valves, operational pressure
controls, or automated emergency shutdown that includes opening vents
to isolate and depressurize equipment without any human intervention.
9. Addition of Oil Formation Type in the Sub-Basin Category Definition
Comment: In September 2011, EPA proposed a definition for sub-basin
category to replace the November 2010 delineation of wells within a
basin according to fields. Commenters were supportive of the definition
but suggested some modifications to the structure of the definition.
For example, commenters pointed out that there was no formation defined
for oil production. There are emission sources such as storage tanks
that have to report emissions by sub-basin category. However, wells
that produce oil and are not located in one of the four gas formations
(shale gas, tight reservoir rock, coal seam, and conventional gas) were
not represented in the September 2011 definition of the sub-basin
category. Commenters requested that an oil formation type be added to
the sub-basin category definition.
Response: EPA agrees with the commenters and has added oil
formation type to the definition of sub-basin category in 40 CFR
98.238. Any well that produces hydrocarbon liquids and is not located
in one of the four gas formations is now designated as oil formation.
EPA notes that hydrocarbon liquids produced from wells in the gas
formation (i.e. condensate) has to be accounted for in the respective
gas formation and not the oil formation. The emission characteristics
of hydrocarbon liquids produced in gas formations are different from
hydrocarbon liquids produced in oil formations. Furthermore, EPA has
removed the November 2010 definitions of oil wells and gas wells, since
these were in conflict with the definition of sub-basin category. The
November 2010 definitions for oil and gas wells were linked to the
zones or reservoirs from which they were producing. However, the sub-
basin category definition uses formation type. To keep all definitions
interrelated and avoid conflicts EPA now defines a gas well as one
which produces from a gas formation, and an oil well as one which
produces from an oil formation in the sub-basin category definition.
10. Dehydrators Owned and Operated by Third Parties
Comment: EPA has received comments questioning the treatment of
equipment such as a dehydrator located on a well-pad, but owned and
operated by the gas processor, not the producer. One commenter noted
that in the September 2011 proposal under Sec. 98.230(a)(2),
dehydrators are still referenced in the onshore petroleum
[[Page 80572]]
and natural gas production industry segment. This commenter then stated
that dehydrators located on a well-pad and owned and operated by a gas
processor should not report under onshore natural gas production
because the gas processor is not a production owner or operator.
Response: The facility definition for onshore production in 40 CFR
98.238 is defined as all petroleum or natural gas equipment on a single
well-pad or associated with a single well-pad and CO2 EOR
operations that are under common ownership or common control including
leased, rented, or contracted activities by an onshore petroleum and
natural gas production owner or operator and that are located in a
single hydrocarbon basin. Reporters need to evaluate their situation
against that definition to make a determination regarding the
applicability of a dehydrator.
III. 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'' under the
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is
therefore not subject to review under Executive Orders 12866 and 13563
(76 FR 3821, January 21, 2011).
B. Paperwork Reduction Act
This action finalizes amendments to reporting methodologies in
subpart W and amendments to clarify monitoring methodologies and data
reporting requirements. In many cases, the amendments to the reporting
requirements do not increase reporting burden but rather, ensure that
the reporting requirements conform more closely to current industry
practices. Therefore, the amendments to the information collection
requirements have been submitted for approval to the Office of
Management and Budget (OMB) under the Paperwork Reduction Act, 44
U.S.C. 3501 et seq. The Information Collection Request (ICR) document
has been assigned EPA ICR number 2376.05.
The Office of Management and Budget has previously approved the
information collection requirements contained in the existing rules, 40
CFR part 98 subpart W (75 FR 74458), under the provisions of the
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB
control number 2060-0651 and 2060-0650 respectively. The OMB control
numbers for EPA's regulations in 40 CFR are listed in 40 CFR Part 9.
Burden is defined at 5 CFR 1320.3(b).
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.
C. Regulatory Flexibility Act (RFA)
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of this action on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's (SBA) regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
After considering the economic impacts of this action on small
entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. In
determining whether a rule has a significant economic impact on a
substantial number of small entities, the impact of concern is any
significant adverse economic impact on small entities, since the
primary purpose of the regulatory flexibility analyses is to identify
and address regulatory alternatives ``which minimize any significant
economic impact of the rule on small entities'' 5 U.S.C. 603 and 604.
Thus, an agency may certify that a rule will not have a significant
economic impact on a substantial number of small entities if the rule
relieves regulatory burden, or otherwise has a positive economic effect
on all of the small entities subject to the rule.
As part of the process for finalization of the subpart W rule (75
FR 74458), EPA undertook specific steps to evaluate the effect of that
final rule on small entities. Under that final rule for subpart W (75
FR 74458) EPA conducted a screening assessment comparing compliance
costs to onshore petroleum and natural gas industry specific receipts
data for establishments owned by small businesses. The results of that
screening analysis, as detailed in the preamble to the final rule for
subpart W (75 FR 74482), demonstrated that the cost-to-sales ratios
were less than one percent for establishments owned by small businesses
that EPA considered most likely to be covered by the reporting program.
The results of that analysis can be found in the preamble to the final
rule (75 FR 74485).
Based on the final amendments in this action, EPA has increased
flexibility in the selection of methods used for calculating GHG's by
providing alternative methods where appropriate, revised specific
methods in the rule to clarify requirements, clarified specific
provisions related to applicability to clearly state EPA's intent,
corrected technical errors in equations, and revised specific
provisions to further clarify what must be reported and where
measurement must be taken at a facility. These revisions do not add
additional burden on reporters but maintain the data quality of the
information being reported to EPA, and in many cases reduce burden. We
have therefore concluded that this action will relieve regulatory
burden for all affected small entities.
D. Unfunded Mandates Reform Act (UMRA)
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2
U.S.C. 1531-1538, requires Federal agencies, unless otherwise
prohibited by law, to assess the effects of their regulatory actions on
State, local, and Tribal governments and the private sector. Federal
agencies must also develop a plan to provide notice to small
governments that might be significantly or uniquely affected by any
regulatory requirements. The plan must enable officials of affected
small governments to have meaningful and timely input in the
development of EPA regulatory proposals with significant Federal
intergovernmental mandates and must inform, educate, and advise small
governments on compliance with the regulatory requirements.
These final rule amendments do not contain a Federal mandate that
may result in expenditures of $100 million or more for state, local,
and tribal governments, in the aggregate, or the private sector in any
one year. Thus, the final rule amendments are not subject to the
requirements of section 202 and 205 of the UMRA. This action is also
not subject to the requirements of section 203 of UMRA because it
contains no regulatory requirements that might
[[Page 80573]]
significantly or uniquely affect small governments.
E. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132.
Few, if any, State or local government facilities would be affected
by the provisions in this final rule. This regulation also does not
limit the power of States or localities to collect GHG data and/or
regulate GHG emissions. Thus, Executive Order 13132 does not apply to
this action.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). During the
finalization of subpart W in 2010 (75 FR 74458), EPA undertook the
necessary steps to determine the impact of those rules on tribal
entities and provided supporting documentation demonstrating the
results of the Agency's analyses. And in several cases, the amendments
to the reporting requirements would potentially reduce the reporting
burden. Thus, Executive Order 13175 does not apply to this action.
Although Executive Order 13175 does not apply to this action, EPA
consulted with tribal officials during the development of the subpart W
(75 FR 74458). A summary of the concerns raised during that
consultation and EPA's response to those concerns is provided in
Sections VIII.E and VIII.F of the preamble to the 2009 final rule and
Section IV.F of the preamble to the 2010 final rule for subpart W (75
FR 74485).
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997)
as applying only to those regulatory actions that concern health or
safety risks, such that the analysis required under section 5-501 of
the Executive Order has the potential to influence the regulation. This
action is not subject to Executive Order 13045 because it does not
establish an environmental standard intended to mitigate health or
safety risks.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This action is not subject to Executive Order 13211 (66 FR 28355,
May 22, 2001), because it is not a significant regulatory action under
Executive Order 12866.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
This final action does not involve technical standards. Therefore,
EPA did not consider the use of any voluntary consensus standards.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
EPA has determined that this action will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment because it is a rule addressing information collection and
reporting procedures.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA),
generally provides that before a rule may take effect, the agency
promulgating the rule must submit a rule report, which includes a copy
of the rule, to each House of the Congress and to the Comptroller
General of the United States. EPA will submit a report containing this
rule and other required information to the U.S. Senate, the U.S. House
of Representatives, and the Comptroller General of the U.S. A Major
rule cannot take effect until 60 days after it is published in the
Federal Register. This action is not a ``major rule'' as defined by 5
U.S.C. 804(2). This rule will be effective on December 28, 2011.
List of Subjects in 40 CFR Part 98
Environmental protection, Administrative practice and procedure,
Greenhouse gases, Suppliers, Reporting and recordkeeping requirements.
Dated: December 2, 2011.
Lisa P. Jackson,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is amended as follows:
PART 98--[AMENDED]
0
1. The authority citation for part 98 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart A--[Amended]
0
2. Section 98.1 is amended by adding paragraph (c) to read as follows:
Sec. 98.1 Purpose and scope.
* * * * *
(c) For facilities required to report under onshore petroleum and
natural gas production under subpart W of this part, the terms Owner
and Operator used in subpart A have the same definition as Onshore
petroleum and natural gas production owner or operator, as defined in
Sec. 98.238 of this part.
0
3. Section 98.6 is amended by revising the definitions of ``Continuous
bleed'' and ``Intermittent bleed pneumatic devices'' to read as
follows:
Sec. 98.6 Definitions.
* * * * *
Continuous bleed means a continuous flow of pneumatic supply
natural gas to the process control device (e.g., level control,
temperature control, pressure control) where the supply gas pressure is
modulated by the process condition, and then flows to the valve
controller where the signal is compared with the
[[Page 80574]]
process set-point to adjust gas pressure in the valve actuator.
* * * * *
Intermittent bleed pneumatic devices mean automated flow control
devices powered by pressurized natural gas and used for automatically
maintaining a process condition such as liquid level, pressure, delta-
pressure, and temperature. These are snap-acting or throttling devices
that discharge all or a portion of the full volume of the actuator
intermittently when control action is necessary, but do not bleed
continuously.
* * * * *
Subpart W--[Amended]
0
4. Section 98.230 is amended by revising paragraphs (a)(2) through
(a)(4), and (a)(8) to read as follows:
Sec. 98.230 Definition of the source category.
(a) * * *
(2) Onshore petroleum and natural gas production. Onshore petroleum
and natural gas production means all equipment on a single well-pad or
associated with a single well-pad (including but not limited to
compressors, generators, dehydrators, storage vessels, and portable
non-self-propelled equipment which includes well drilling and
completion equipment, workover equipment, gravity separation equipment,
auxiliary non-transportation-related equipment, and leased, rented or
contracted equipment) used in the production, extraction, recovery,
lifting, stabilization, separation or treating of petroleum and/or
natural gas (including condensate). This equipment also includes
associated storage or measurement vessels and all enhanced oil recovery
(EOR) operations using CO2 or natural gas injection, and all
petroleum and natural gas production equipment located on islands,
artificial islands, or structures connected by a causeway to land, an
island, or an artificial island.
(3) Onshore natural gas processing. Natural gas processing means
the separation of natural gas liquids (NGLs) or non-methane gases from
produced natural gas, or the separation of NGLs into one or more
component mixtures. Separation includes one or more of the following:
forced extraction of natural gas liquids, sulfur and carbon dioxide
removal, fractionation of NGLs, or the capture of CO2
separated from natural gas streams. This segment also includes all
residue gas compression equipment owned or operated by the natural gas
processing plant. This industry segment includes processing plants that
fractionate gas liquids, and processing plants that do not fractionate
gas liquids but have an annual average throughput of 25 MMscf per day
or greater.
(4) Onshore natural gas transmission compression. Onshore natural
gas transmission compression means any stationary combination of
compressors that move natural gas from production fields, natural gas
processing plants, or other transmission compressors through
transmission pipelines to natural gas distribution pipelines, LNG
storage facilities, or into underground storage. In addition, a
transmission compressor station includes equipment for liquids
separation, and tanks for the storage of water and hydrocarbon liquids.
Residue (sales) gas compression that is part of onshore natural gas
processing plants are included in the onshore natural gas processing
segment and are excluded from this segment.
* * * * *
(8) Natural gas distribution. Natural gas distribution means the
distribution pipelines and metering and regulating equipment at
metering-regulating stations that are operated by a Local Distribution
Company (LDC) within a single state that is regulated as a separate
operating company by a public utility commission or that is operated as
an independent municipally-owned distribution system. This segment also
excludes customer meters and regulators, infrastructure, and pipelines
(both interstate and intrastate) delivering natural gas directly to
major industrial users and farm taps upstream of the local distribution
company inlet.
* * * * *
0
5. Section 98.232 is amended by:
0
a. Revising paragraph (a).
0
b. Revising paragraph (c) introductory text.
0
c. Revising paragraph (c)(22).
0
d. Revising paragraph (d) introductory text.
0
e. Revising paragraph (e) introductory text.
0
f. Revising paragraph (f) introductory text.
0
g. Revising paragraph (g) introductory text.
0
h. Revising paragraph (h) introductory text.
0
i. Revising paragraph (i).
0
j. Removing and reserving paragraph (j).
0
k. Revising paragraph (k).
The revisions read as follows:
Sec. 98.232 GHGs to report.
(a) You must report CO2, CH4, and
N2O emissions from each industry segment specified in
paragraph (b) through (i) of this section, CO2,
CH4, and N2O emissions from each flare as
specified in paragraph (b) through (i) of this section, and stationary
and portable combustion emissions as applicable as specified in
paragraph (k) of this section.
* * * * *
(c) For an onshore petroleum and natural gas production facility,
report CO2, CH4, and N2O emissions
from only the following source types on a single well-pad or associated
with a single well-pad:
* * * * *
(22) You must use the methods in Sec. 98.233(z) and report under
this subpart the emissions of CO2, CH4, and
N2O from stationary or portable fuel combustion equipment
that cannot move on roadways under its own power and drive train, and
that is located at an onshore petroleum and natural gas production
facility as defined in Sec. 98.238. Stationary or portable equipment
are the following equipment, which are integral to the extraction,
processing, or movement of oil or natural gas: well drilling and
completion equipment, workover equipment, natural gas dehydrators,
natural gas compressors, electrical generators, steam boilers, and
process heaters.
(d) For onshore natural gas processing, report CO2,
CH4, and N2O emissions from the following
sources:
* * * * *
(e) For onshore natural gas transmission compression, report
CO2, CH4, and N2O emissions from the
following sources:
* * * * *
(f) For underground natural gas storage, report CO2,
CH4, and N2O emissions from the following
sources:
* * * * *
(g) For LNG storage, report CO2, CH4, and
N2O emissions from the following sources:
* * * * *
(h) LNG import and export equipment, report CO2,
CH4, and N2O emissions from the following
sources:
* * * * *
(i) For natural gas distribution, report CO2,
CH4, and N2O emissions from the following
sources:
(1) Meters, regulators, and associated equipment at above grade
transmission-distribution transfer stations, including equipment leaks
from connectors, block valves, control valves, pressure relief valves,
orifice meters, regulators, and open ended lines.
(2) Equipment leaks from vaults at below grade transmission-
distribution transfer stations.
[[Page 80575]]
(3) Meters, regulators, and associated equipment at above grade
metering-regulating station.
(4) Equipment leaks from vaults at below grade metering-regulating
stations.
(5) Pipeline main equipment leaks.
(6) Service line equipment leaks.
(7) Report under subpart W of this part the emissions of
CO2, CH4, and N2O emissions from
stationary fuel combustion sources following the methods in Sec.
98.233(z)
(j) [Reserved]
(k) Report under subpart C of this part (General Stationary Fuel
Combustion Sources) the emissions of CO2, CH4,
and N2O from each stationary fuel combustion unit by
following the requirements of subpart C except for facilities under
onshore petroleum and natural gas production and natural gas
distribution. Onshore petroleum and natural gas production facilities
must report stationary and portable combustion emissions as specified
in paragraph (c) of this section. Natural gas distribution facilities
must report stationary combustion emissions as specified in paragraph
(i) of this section.
* * * * *
0
6. Section 98.233 is amended by:
0
a. In paragraph (a), revising Equation W-1 and its definitions.
0
b. Adding paragraph (a)(3).
0
c. In paragraph (c), revising Equation W-2 and its definitions.
0
d. Revising paragraphs (d) introductory text and (d)(1).
0
e. Revising the first sentence of paragraph (d)(2) and the definition
``Vs'' in Equation W-3.
0
f. Revising paragraph (d)(3).
0
g. Revising the first sentence of paragraph (d)(4) introductory text.
0
h. Revising paragraph (e) introductory text, (e)(1) introductory text,
(e)(1)(vii), (e)(1)(xi) introductory text, (e)(1)(xi)(A) through (C),
and (e)(2) introductory text.
0
i. In paragraph (e)(2), revising the definition of ``EFi'',
``Count'', and ``1000'' in Equation W-5.
0
j. Revising the first sentence of paragraph (e)(5) introductory text.
0
k. Revising paragraph (e)(6).
0
l. Revising paragraph (f)(1) introductory text.
0
m. Revising paragraphs (f)(1)(i)(A) through (f)(1)(i)(C).
0
n. Revising paragraph (f)(2).
0
o. In paragraph (f)(3) introductory text, revising Equation W-9 and its
definitions.
0
p. Removing and reserving paragraphs (f)(3)(i) and (f)(3)(ii).
0
q. Revising paragraph (g) introductory text.
0
r. Revising paragraphs (g)(1) introductory text and (g)(1)(i).
0
s. Revising paragraph (g)(1)(ii) introductory text; removing Equation
W-11 and its definitions, adding Equations W-11A, W-11B, W-11C and
their definitions, and revising W-12 and its definitions.
0
t. Redesignating paragraphs (g)(1)(ii)(A) through (g)(1)(ii)(C) as
paragraphs (g)(1)(iii) through (g)(1)(v) and revising newly
redesignated paragraphs (g)(1)(iii) through (g)(1)(v).
0
u. Removing paragraph (g)(1)(ii)(D).
0
v. Revising paragraph (g)(3).
0
w. Removing paragraph (g)(5) and redesignating paragraph (g)(6),
(g)(6)(i), and (g)(6)(ii) as (g)(5), (g)(5)(i), and (g)(5)(ii).
0
x. Revising paragraph (h) introductory text.
0
y. Removing paragraph (h)(1).
0
z. Redesignating paragraphs (h)(2) and (h)(3) introductory text as
paragraphs (h)(1) and (h)(2) introductory text, respectively, and
revising newly redesignated paragraph (h)(1).
0
aa. Revising paragraph (i).
0
bb. Revising the first sentence of paragraph (j)(1) and revising
paragraphs (j)(1)(vii) introductory text, (j)(1)(vii)(B), and
(j)(1)(vii)(C).
0
cc. Revising paragraph (j)(2).
0
dd. Revising paragraph (j)(3) introductory text and paragraph
(j)(3)(i).
0
ee. Revising paragraph (j)(4) introductory text.
0
ff. In paragraph (j)(5), revising Equation W-15, revising the
definitions of ``EFi'' and ``Count'', and adding the
definition of ``1,000''.
0
gg. In paragraph (j)(8), revising Equation W-16, revising the
definition of ``En'', removing the definition of ``Et'', and
adding the definition of ``8,760''.
0
hh. Revising paragraphs (k) introductory text, (k)(1), (k)(2)
introductory text, (k)(2)(i), and (k)(4); and adding new paragraph
(k)(2)(iv).
0
ii. Revising paragraph (l)(1).
0
jj. Revising paragraph (l)(3).
0
kk. Revising paragraph (m)(1) and revising equation W-18 and its
definitions in paragraph (m)(3).
0
ll. Revising paragraph (n)(2)(ii) and (n)(2)(iii), and in paragraph
(n)(4), republishing Equations W-19 and W-20 and revising Equation W-
21.
0
mm. Redesignating paragraph (n)(9) as paragraph (n)(10) and adding new
paragraphs (n)(9) and (n)(11).
0
nn. In paragraph (o)(6), revising the definition of ``MTm''
in Equation W-24.
0
oo. In paragraph (o)(7), revising the definition of ``EFi''
in Equation W-25.
0
pp. In paragraph (p)(7)(i) introductory text, revising the definition
of ``MTm'' in Equation W-28.
0
qq. In paragraph (p)(9), revising the definition of ``EFi''
in Equation W-29.
0
rr. Revising paragraph (q) introductory text.
0
ss. Revising paragraph (q)(8).
0
tt. Revising paragraph (r) introductory text and the definitions in
Equation W-31.
0
uu. Revising paragraphs (r)(2)(i)(A), (r)(6)(i), (r)(6)(ii).
0
vv. Revising introductory texts for paragraphs (t) and (t)(1), and
revising the definitions of ``Ts'' and ``Ps'' in
Equation W-33.
0
ww. Revising paragraph (t)(2) and the parameters ``Ts'' and
``Ps'' in Equation W-34.
0
xx. Adding paragraph (t)(3).
0
yy. Revising paragraph (u) introductory text, paragraph (u)(2).
0
zz. In paragraph (v), revising the only sentence of paragraph (v),
Equation W-36, and the definitions of ``Masss,i'',
``Es,i'', and ``[rho]i'' in Equation W-36.
0
aaa. In paragraph (w)(3), revising Equation W-37 and the definitions of
parameters ``Massc,i'' and ``GHGi''.
0
bbb. In paragraph (x)(2), revising Equation W-38 and the definitions of
parameter ``Masss,CO2''.
0
ccc. Revising paragraph (z) introductory text,
(z)(1),(z)(2)introductory text, (z)(2)(i),(z(2)(ii), (z)(2)(iii), and
(z)(3).
0
ddd. Redesignating paragraphs (z)(4), (z)(5), and (z)(6) as (z)(2)(iv),
(z)(2)(v), and (z)(2)(vi), respectively.
0
eee. In newly redesignated paragraph (z)(2)(vi), revising Equation W-
40, removing the definition for N2O, revising the definition
of ``HHV'', and adding the definitions ``GWP'' and
``Mass,N2O''.
0
fff. Adding paragraph (z)(4).
The revisions read as follows:
Sec. 98.233 Calculating GHG emissions.
(a) * * *
[GRAPHIC] [TIFF OMITTED] TR23DE11.000
Where:
Masst,i = Annual total mass GHG emissions in metric tons
CO2e per year from a natural gas pneumatic device vent of
type ``t'', for GHGi.
[[Page 80576]]
Countt = Total number of natural gas pneumatic devices of
type ``t'' (continuous high bleed, continuous low bleed,
intermittent bleed) as determined in paragraph (a)(1), (a)(2), and
(a)(3) of this section.
EFt = Population emission factors for natural gas
pneumatic device venting listed in Tables W-1A, W-3, and W-4 of this
subpart for onshore petroleum and natural gas production, onshore
natural gas transmission compression, and underground natural gas
storage facilities, respectively.
GHGi = For onshore petroleum and natural gas production
facilities, concentration of GHGi, CH4, or
CO2, in natural gas as defined in paragraph (u)(2)(i) of
this section and 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.
Convi = Conversion from standard cubic feet to metric
tons CO2e; 0.000403 for CH4, and 0.00005262
for CO2.
Tt = Average estimated number of hours in the operating
year the devices, of each type t, were operational. Default is 8760
hours.
* * * * *
(3) For all industry segments, determine the type of pneumatic
device using engineering estimates based on best available information.
* * * * *
(c) * * *
[GRAPHIC] [TIFF OMITTED] TR23DE11.001
Where:
Massi = Annual total mass GHG emissions in metric tons
CO2e per year from all natural gas pneumatic pump
venting, for GHGi.
Count = Total number of natural gas pneumatic pumps.
EF = Population emissions factors for natural gas pneumatic pump
venting listed in Tables W-1A of this subpart for onshore petroleum
and natural gas production.
GHGi = Concentration of GHGi, CH4,
or CO2, in produced natural gas as defined in paragraph
(u)(2)(i) of this section.
Convi = Conversion from standard cubic feet to metric
tons CO2e; 0.000403 for CH4, and 0.00005262
for CO2.
T = Average estimated number of hours in the operating year the
pumps were operational. Default is 8760 hours.
(d) Acid gas removal (AGR) vents. For AGR vent (including processes
such as amine, membrane, molecular sieve or other absorbents and
adsorbents), calculate emissions for CO2 only (not
CH4) vented directly to the atmosphere or through a flare,
engine (e.g., permeate from a membrane or de-adsorbed gas from a
pressure swing adsorber used as fuel supplement), or sulfur recovery
plant using any of the calculation methodologies described in paragraph
(d) of this section, as applicable.
(1) Calculation Methodology 1. If you operate and maintain a CEMS
that has both a CO2 concentration monitor and volumetric
flow rate monitor, you must calculate CO2 emissions under
this subpart by following the Tier 4 Calculation Methodology and all
associated calculation, quality assurance, reporting, and recordkeeping
requirements for Tier 4 in subpart C of this part (General Stationary
Fuel Combustion Sources). Alternatively, you may follow the
manufacturer's instructions or industry standard practice. If a
CO2 concentration monitor and volumetric flow rate monitor
are not available, you may elect to install a CO2
concentration monitor and a volumetric flow rate monitor that comply
with all of the requirements specified for the Tier 4 Calculation
Methodology in subpart C of this part (General Stationary Fuel
Combustion). The calculation and reporting of CH4 and
N2O emissions is not required as part of the Tier 4
requirements for AGRs.
(2) Calculation Methodology 2. If CEMS is not available but a vent
meter is installed, use the CO2 composition and annual
volume of vent gas to calculate emissions using Equation W-3 of this
section.
* * * * *
VS = Total annual volume of vent gas flowing out of the
AGR unit in cubic feet per year at actual conditions as determined
by flow meter using methods set forth in Sec. 98.234(b).
Alternatively, you may follow the manufacturer's instructions or
industry standard practice for calibration of the vent meter.
* * * * *
(3) Calculation Methodology 3. If CEMS or a vent meter is not
installed, you may use the inlet or outlet gas flow rate of the acid
gas removal unit to calculate emissions for CO2 using
Equations W-4A or W-4B of this section. If inlet gas flow rate is
known, use Equation W-4A. If outlet gas flow rate is known, use
Equation W-4B.
[GRAPHIC] [TIFF OMITTED] TR23DE11.002
Where:
Ea, CO2 = Annual volumetric CO2 emissions at
actual conditions, in cubic feet per year.
Vin = Total annual volume of natural gas flow into the
AGR unit in cubic feet per year at actual condition as determined
using methods specified in paragraph (d)(5) of this section.
Vout = Total annual volume of natural gas flow out of the
AGR unit in cubic feet per year at actual condition as determined
using methods specified in paragraph (d)(5) of this section.
VolI = Volume fraction of CO2 content in
natural gas into the AGR unit as determined in paragraph (d)(7) of
this section.
Volo = Volume fraction of CO2 content in
natural gas out of the AGR unit as determined in paragraph (d)(8) of
this section.
(4) Calculation Methodology 4. If CEMS or a vent meter is not
installed, you may calculate emissions using any standard simulation
software packages, such as AspenTech HYSYS[supreg] and API 4679
AMINECalc, that uses the Peng-Robinson equation of state, and speciates
CO2 emissions.* * *
* * * * *
(e) Dehydrator vents. For dehydrator vents, calculate annual
CH4, CO2 and N2O emissions using any
of the
[[Page 80577]]
calculation methodologies described in paragraph (e) of this section.
(1) Calculation Methodology 1. Calculate annual mass emissions from
dehydrator vents with annual average daily throughput greater than or
equal to 0.4 million standard cubic feet per day using a software
program, such as AspenTech HYSYS[supreg] or GRI-GLYCalc, that uses the
Peng-Robinson equation of state to calculate the equilibrium
coefficient, speciates CH4 and CO2 emissions from
dehydrators, and has provisions to include regenerator control devices,
a separator flash tank, stripping gas and a gas injection pump or gas
assist pump. A minimum of the following parameters determined by
engineering estimate based on best available data must be used to
characterize emissions from dehydrators:
* * * * *
(vii) Use of stripping gas.
* * * * *
(xi) Wet natural gas composition. Determine this parameter by
selecting one of the methods described under paragraph (e)(1)(xi) of
this section.
(A) Use the wet natural gas composition as defined in paragraph
(u)(2)(i) or (u)(2)(ii) of this section.
(B) If wet natural gas composition cannot be determined using
paragraph (u)(2)(i) or (u)(2)(ii) of this section, select a
representative analysis.
(C) You may use an appropriate standard method published by a
consensus-based standards organization if such a method exists or you
may use an industry standard practice as specified in Sec. 98.234(b)
to sample and analyze wet natural gas composition.
* * * * *
(2) Calculation Methodology 2. Calculate annual CH4 and
CO2 emissions from glycol dehydrators with annual average
daily throughput less than 0.4 million standard cubic feet per day
using Equation W-5 of this section:
* * * * *
EFi = Population emission factors for glycol dehydrators
in thousand standard cubic feet per dehydrator per year. Use 73.4
for CH4 and 3.21 for CO2 at 60 [deg]F and 14.7
psia.
Count = Total number of glycol dehydrators with throughput less than
0.4 million standard cubic feet per day.
1000 = Conversion of EFi in thousand standard cubic feet
to standard cubic feet.
* * * * *
(5) Dehydrators that use desiccant shall calculate emissions from
the amount of gas vented from the vessel when it is depressurized for
the desiccant refilling process using Equation W-6 of this section. * *
*
* * * * *
(6) For glycol dehydrators, both CH4 and CO2
mass emissions shall be calculated from volumetric GHGi
emissions using calculations in paragraph (v) of this section. For
dehydrators that use desiccant, both CH4 and CO2
volumetric and mass emissions shall be calculated from volumetric
natural gas emissions using calculations in paragraphs (u) and (v) of
this section.
(f) * * *
(1) Calculation Methodology 1. For one well of each unique well
tubing diameter group and pressure group combination in each sub-basin
category (see Sec. 98.238 for the definitions of tubing diameter
group, pressure group, and sub-basin category), where gas wells are
vented to the atmosphere to expel liquids accumulated in the tubing, a
recording flow meter shall be installed on the vent line used to vent
gas from the well (e.g., on the vent line off the wellhead separator or
atmospheric storage tank) according to methods set forth in Sec.
98.234(b). Calculate emissions from well venting for liquids unloading
using Equation W-7 of this section.
[GRAPHIC] [TIFF OMITTED] TR23DE11.003
Where:
Ea,n = Annual natural gas emissions for all wells of the
same tubing diameter group and pressure group combination in a sub-
basin at actual conditions in cubic feet.
h = Total number of wells of the same tubing diameter group and
pressure group combination in a sub-basin.
p = Wells 1 through h of the same tubing diameter group and pressure
group combination in a sub-basin.
Tp = Cumulative amount of time in hours of venting from
the measured well, p, of the same tubing diameter group and pressure
group combination in a sub-basin during the year.
FRp = Average flow rate in cubic feet per hour of a
measured well venting for the duration of the liquids unloading,
under actual conditions as determined in paragraph (f)(1)(i) of this
section.
(i) * * *
(A) The average flow rate per hour of venting is calculated for
each unique tubing diameter group and pressure group combination in
each sub-basin category by dividing the recorded total flow by the
recorded time (in hours) for a single liquid unloading with venting to
the atmosphere.
(B) This average flow rate per hour is applied to all wells in the
same pressure group that have the same tubing diameter group, for the
number of hours of venting these wells.
(C) A new average flow rate is calculated every other calendar year
for each reporting sub-basin category starting the first calendar year
of data collection. For a new producing sub-basin category, an average
flow rate is calculated beginning in the first year of production.
* * * * *
(2) Calculation Methodology 2. Calculate the total emissions for
well venting for liquids unloading using Equation W-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR23DE11.004
Where:
Es,n = Annual natural gas emissions at standard
conditions, in cubic feet/year.
W = Total number of wells with well venting for liquids unloading
for each sub-basin.
0.37x10-3 = {3.14 (pi)/4{time} /{14.7*144{time} (psia
converted to pounds per square feet).
CDp = Casing internal diameter for each well, p, in
inches.
WDp = Well depth from either the top of the well or the
lowest packer to the bottom of the well, for each well, p, in feet.
SPp = Shut-in pressure or surface pressure for wells with
tubing production and no packers or casing pressure for each well,
p, in pounds per square inch absolute (psia) or casing-to-tubing
pressure of one well from the same sub-basin multiplied by the
tubing pressure of each well, p, in the sub-basin, in pounds per
square inch absolute (psia).
Vp = Number of vents per year per well, p.
SFRp = Average flow-line rate of gas for well, p, at
standard conditions in cubic feet per hour. Use Equation W-33 to
calculate the average flow-line rate at standard conditions.
HRp,q = Hours that each well, p, was left open to the
atmosphere during unloading, q.
[[Page 80578]]
1.0 = Hours for average well to blowdown casing volume at shut-in
pressure.
Zp,q = If HRp,q is less than 1.0 then
Zp,q is equal to 0. If HRp,q is greater than
or equal to 1.0 then Zp,q is equal to 1.
(3) * * *
[GRAPHIC] [TIFF OMITTED] TR23DE11.005
Where:
Es,n = Annual natural gas emissions at standard
conditions, in cubic feet/year.
W = Total number of wells with well venting for liquids unloading
for each sub-basin.
0.37x10-3 = {3.14 (pi)/4{time} /{14.7*144{time} (psia
converted to pounds per square feet).
TDp = Tubing internal diameter for each well, p, in
inches.
WDp = Tubing depth to plunger bumper for each well, p, in
feet.
SPp = Flow-line pressure for each well, p, in pounds per
square inch absolute (psia), using engineering estimate based on
best available data.
Vp = Number of vents per year for each well, p.
SFRp = Average flow-line rate of gas for well, p, at
standard conditions in cubic feet per hour. Use Equation W-33 to
calculate the average flow-line rate at standard conditions.
HRp,q = Hours that each well, p, was left open to the
atmosphere during each unloading, q.
0.5 = Hours for average well to blowdown tubing volume at flow-line
pressure.
Zp,q = If HRp,q is less than 0.5 then
Zp,q is equal to 0. If HRp,q is greater than
or equal to 0.5 then Zp,q is equal to 1.
(i) [Reserved]
(ii) [Reserved]
(g) Gas well venting during completions and workovers from
hydraulic fracturing. Calculate CH4, CO2 and
N2O annual emissions from gas well venting during
completions involving hydraulic fracturing in wells and well workovers
using Equation W-10A or Equation W-10B of this section. Equation W-10A
applies to well venting when the backflow rate is measured or
calculated, Equation W-10B applies when the backflow vent or flare
volume is measured. Use Equation W-10A if the flow rate for backflow
during well completions and workovers from hydraulic fracturing is
known for the specified number of wells per paragraph (g)(1) in a sub-
basin and well type (horizontal or vertical) combination. Use Equation
W-10B if the flow volume for backflow during well completions and
workovers from hydraulic fracturing is known for all wells in a sub-
basin and well type (horizontal or vertical) combination. Both
CH4 and CO2 volumetric and mass emissions shall
be calculated from volumetric total gas emissions using calculations in
paragraphs (u) and (v) of this section.
[GRAPHIC] [TIFF OMITTED] TR23DE11.006
Where:
Es,n = Annual volumetric total gas emissions in cubic
feet at standard conditions from gas well venting during completions
or workovers following hydraulic fracturing for each sub-basin and
well type (horizontal vs. vertical) combination.
W = Total number of wells completed or worked over using hydraulic
fracturing in a sub-basin and well type (horizontal vs. vertical)
combination.
Tp = Cumulative amount of time of backflow for the
completion or workover, in hours, for each well, p, in a sub-basin
and well type (horizontal vs. vertical) combination during the
reporting year.
FRM = Ratio of backflow during well completions and workovers from
hydraulic fracturing to 30-day production rate from Equation W-12.
PRp = First 30-day average production flow rate in
standard cubic feet per hour of each well p, under actual
conditions, converted to standard conditions, as required in
paragraph (g)(1) of this section.
EnFp = Volume of CO2 or N2 injected
gas in cubic feet at standard conditions that was injected into the
reservoir during an energized fracture job for each well p. If the
fracture process did not inject gas into the reservoir, then
EnFp is 0. If injected gas is CO2, then
EnFp is 0.
SGp = Volume of natural gas in cubic feet at standard
conditions that was recovered into a flow-line for well p as per
paragraph (g)(3) of this section. This parameter includes any
natural gas that is injected into the well for clean-up. If no gas
was recovered, SGp is 0.
FVp = Flow volume 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 backflow during the completion or
workover according to methods set forth in Sec. 98.234(b).
(1) The average flow rate for backflow during well completions and
workovers from hydraulic fracturing shall be determined using
measurement(s) for calculation methodology 1 or calculation(s) for
calculation methodology 2 described in this paragraph (g)(1) of this
section. If Equation W-10A is used, the number of measurements or
calculations shall be determined per sub-basin and well type
(horizontal or vertical) as follows: one measurement or calculation for
less than or equal to 25 completions or workovers; two measurements or
calculations for 26 to 50 completions or workovers; three measurements
or calculations for 51 to 100 completions or workovers; four
measurements or calculations for 101 to 250 completions or workovers;
and five measurements or calculations for greater than 250 completions
or workovers.
(i) Calculation Methodology 1. When using Equation W-10A, for each
measured well completion(s) in each gas producing sub-basin category
and well type (horizontal or vertical) combination and for each
measured well workover(s) in each gas producing sub-basin category and
well type (horizontal or vertical) combination, a recording flow meter
(digital or analog) shall be installed on the vent line, ahead of a
flare or vent if used, to measure the backflow rate according to
methods set forth in Sec. 98.234(b).
(ii) Calculation Methodology 2. When using Equation W-10A, for each
calculated horizontal well completion
[[Page 80579]]
and each calculated vertical well completion in each gas producing sub-
basin category and for each calculated well horizontal workover and for
each calculated vertical well workover in each gas producing sub-basin
category, record the well flowing pressure upstream (and downstream in
subsonic flow) of a well choke according to methods set forth in Sec.
98.234(b) to calculate the well backflow during well completions and
workovers from hydraulic fracturing. Calculate emissions using Equation
W-11A of this section for subsonic flow or Equation W-11B of this
section for sonic flow. Use best engineering estimate based on best
available data along with Equation W-11C of this section to determine
whether the predominant flow is sonic or subsonic. If the value of R in
Equation W-11C is greater than or equal to 2, then flow is sonic;
otherwise, flow is subsonic:
[GRAPHIC] [TIFF OMITTED] TR23DE11.007
Where:
FR = Average flow rate in cubic feet per hour, under subsonic flow
conditions.
A = Cross sectional area of orifice (m2).
P1 = Upstream pressure (psia).
Tu = Upstream temperature (degrees Kelvin).
P2 = Downstream pressure (psia).
3430 = Constant with units of m 2/(sec 2 * K).
1.27*10 5 = Conversion from m 3/second to ft
3/hour.
[GRAPHIC] [TIFF OMITTED] TR23DE11.008
Where:
FR = Average flow rate in cubic feet per hour, under sonic flow
conditions.
A = Cross sectional area of orifice (m 2).
Tu = Upstream temperature (degrees Kelvin).
187.08 = Constant with units of m 2/(sec 2 *
K).
1.27*10 5 = Conversion from m 3/second to ft
3/hour.
[GRAPHIC] [TIFF OMITTED] TR23DE11.009
Where:
R = Pressure ratio
P1 = Pressure upstream of the restriction orifice in pounds per
square inch absolute.
P2 = Pressure downstream of the restriction orifice in pounds per
square inch absolute.
(iii) For Equation W-10A, the ratio of backflow rate during well
completions and workovers from hydraulic fracturing to 30-day
production rate is calculated using Equation W-12 of this section.
[GRAPHIC] [TIFF OMITTED] TR23DE11.010
Where:
FRM = Ratio of backflow rate during well completions and workovers
from hydraulic fracturing to 30-day production rate.
FRp = Measured backflow rate from Calculation Methodology
1 or calculated flow rate from Calculation Methodology 2 in standard
cubic feet per hour for well(s) p for each sub-basin and well type
(horizontal or vertical) combination. You may not use flow volume as
used in Equation W-10B converted to a flow rate for this parameter.
PRp = First 30-day production rate in standard cubic feet
per hour for each well p that was measured in the sub-basin and well
type combination.
W = Number of wells completed or worked over using hydraulic
fracturing in a sub-basin and well type formation.
(iv) For Equation W-10A, the ratio of backflow rate during well
completions and workovers from hydraulic fracturing to 30-day
production rate for horizontal and vertical wells are applied to all
horizontal and vertical well completions in the gas producing sub-basin
and well type combination and to all horizontal and vertical well
workovers, respectively, in the gas producing sub-basin and well type
combination for the total number of hours of backflow for each of these
wells.
(v) For Equation W-10A, new flow rates for horizontal and vertical
gas well completions and horizontal and vertical gas well workovers in
each sub-basin category shall be calculated once every two years
starting in the first calendar year of data collection.
* * * * *
(3) Determine if the backflow gas from the well completion or
workover from hydraulic fracturing is recovered with purpose designed
equipment that separates natural gas from the backflow, and sends this
natural gas to a flow-line (e.g., reduced emissions completion or
workovers).
(i) Use the factor SGP in Equation W-10A of this
section, to adjust the emissions estimated in paragraphs (g)(1) through
(g)(4) of this section by the magnitude of emissions captured using
purpose designed equipment that separates saleable gas from the
backflow as determined by engineering estimate based on best available
data.
(ii) [Reserved]
(iii) Calculate gas volume at standard conditions using
calculations in paragraph (t) of this section.
* * * * *
(h) Gas well venting during completions and workovers without
hydraulic fracturing. Calculate CH4, CO2 and
N2O emissions from each gas well venting during well
completions and workovers not involving hydraulic fracturing using
Equation W-13 of this section:
[[Page 80580]]
[GRAPHIC] [TIFF OMITTED] TR23DE11.011
Where:
Es,n = Annual natural gas emissions in standard cubic
feet from a gas well venting during well completions and workovers
without hydraulic fracturing.
Nwo = Number of workovers per sub-basin category that
flare gas or vent gas to the atmosphere and do not involve hydraulic
fracturing in the reporting year.
EFwo = Emission Factor for non-hydraulic fracture well
workover venting in standard cubic feet per workover.
EFwo = 3114 standard cubic feet natural gas per well
workover without hydraulic fracturing.
p = Well completions 1 through f in a sub-basin.
f = Total number of well completions without hydraulic fracturing in
a sub-basin category.
Vp = Average daily gas production rate in standard cubic
feet per hour for each well completion without hydraulic fracturing,
p. This is the total annual gas production volume divided by total
number of hours the wells produced to the flow-line. For completed
wells that have not established a production rate, you may use the
average flow rate from the first 30 days of production. In the event
that the well is completed less than 30 days from the end of the
calendar year, the first 30 days of the production straddling the
current and following calendar years shall be used.
Tp = Time each well completion without hydraulic
fracturing, p, was venting in hours during the year.
(1) Volumetric emissions for both CH4 and CO2
shall be calculated from volumetric natural gas emissions using
calculations in paragraph (u) of this section. Mass emissions for both
CH4 and CO2 shall be calculated from volumetric
natural gas emissions using calculations in paragraphs (v) of this
section.
* * * * *
(i) Blowdown vent stacks. Calculate CO2 and
CH4 blowdown vent stack emissions from depressurizing
equipment(s) to reduce system pressure for planned or emergency
shutdowns resulting from human intervention or to take equipment out of
service for maintenance (excluding depressurizing to a flare, over-
pressure relief, operating pressure control venting and blowdown of
non-GHG gases; desiccant dehydrator blowdown venting before reloading
is covered in paragraph (e)(5) of this section) as follows:
(1) Calculate the unique physical volume (including pipelines,
compressor case or cylinders, manifolds, suction bottles, discharge
bottles, and vessels) between isolation valves determined by
engineering estimates based on best available data.
(2) If the unique physical volume between isolation valves is
greater than or equal to 50 cubic feet, retain logs of the number of
blowdowns for each unique physical volume (including but not limited to
compressors, vessels, pipelines, headers, fractionators, and tanks).
Unique physical volumes smaller than 50 cubic feet are exempt from
reporting under paragraph (i) of this section.
(3) Calculate the total annual venting emissions for unique volumes
using either Equation W-14A or W-14B of this section.
[GRAPHIC] [TIFF OMITTED] TR23DE11.012
Where:
ES,N = Annual natural gas venting emissions at standard
conditions from blowdowns in cubic feet.
N = Number of occurrences of blowdowns for each unique physical
volume in calendar year.
V = Unique physical volume (including pipelines, compressors and
vessels) between isolation valves in cubic feet.
C = Purge factor that is 1 if the unique physical volume is not
purged or zero if the unique physical volume is purged using non-GHG
gases.
Ts = Temperature at standard conditions (60[deg]F).
Ta = Temperature at actual conditions in the unique
physical volume ([deg]F).
Ps = Absolute pressure at standard conditions (14.7
psia).
Pa = Absolute pressure at actual conditions in the unique
physical volume (psia).
[GRAPHIC] [TIFF OMITTED] TR23DE11.013
Where:
Es,n = Annual natural gas venting emissions at standard
conditions from blowdowns in cubic feet.
p = Individual occurrence of blowdown for the same unique physical
volume.
N = Number of occurrences of blowdowns for each unique physical
volume in the calendar year.
V = Total physical volume (including pipelines, compressors and
vessels) between isolation valves in cubic feet for each blowdown
``p.''
Ts = Temperature at standard conditions (60[deg]F).
Ta = Temperature at actual conditions in the unique
physical volume ([deg]F) for each blowdown ``p''.
Ps = Absolute pressure at standard conditions (14.7
psia).
Pa,b,p = Absolute pressure at actual conditions in the
unique physical volume (psia) at the beginning of the blowdown
``p''.
Pa,e,p = Absolute pressure at actual conditions in the
unique physical volume (psia) at the end of the blowdown ``p''; 0 if
blowdown volume is purged using non-GHG gases.
(4) Calculate both CH4 and CO2 volumetric and
mass emissions using calculations in paragraph (u) and (v) of this
section.
(j) * * *
(1) Calculation Methodology 1. For separators with annual average
daily throughput of oil greater than or equal to 10 barrels per day. *
* *
* * * * *
(vii) Separator oil composition and Reid vapor pressure. If this
data is not available, determine these parameters by selecting one of
the methods
[[Page 80581]]
described under paragraph (j)(1) (vii) of this section.
* * * * *
(B) If separator oil composition and Reid vapor pressure data are
available through your previous analysis, select the latest available
analysis that is representative of produced crude oil or condensate
from the sub-basin category.
(C) Analyze a representative sample of separator oil in each sub-
basin category for oil composition and Reid vapor pressure using an
appropriate standard method published by a consensus-based standards
organization.
(2) Calculation Methodology 2. Calculate annual CH4 and
CO2 emissions from onshore production storage tanks for
wellhead gas-liquid separators with annual average daily throughput of
oil greater than or equal to 10 barrels per day by assuming that all of
the CH4 and CO2 in solution at separator
temperature and pressure is emitted from oil sent to storage tanks. You
may use an appropriate standard method published by a consensus-based
standards organization if such a method exists or you may use an
industry standard practice as described in Sec. 98.234(b) to sample
and analyze separator oil composition at separator pressure and
temperature.
(3) Calculation Methodology 3. For wells with annual average daily
oil production greater than or equal to 10 barrels per day that flow
directly to atmospheric storage tanks without passing through a
wellhead separator, calculate annual CH4 and CO2
emissions by either of the methods in paragraph (j)(3) of this section:
(i) If well production oil and gas compositions are available
through your previous analysis, select the latest available analysis
that is representative of produced oil and gas from the sub-basin
category and assume all of the CH4 and CO2 in
both oil and gas are emitted from the tank.
* * * * *
(4) Calculation Methodology 4. For wells with annual average daily
oil production greater than or equal to 10 barrels per day that flow to
a separator not at the well pad, calculate annual CH4 and
CO2 emissions by either of the methods in paragraph (j)(4)
of this section:
* * * * *
(5) * * *
[GRAPHIC] [TIFF OMITTED] TR23DE11.014
Where:
* * * * *
EFi = Population emission factor for separators or wells
in thousand standard cubic feet per separator or well 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[emsp14][deg]F and
14.7 psia.
Count = Total number of separators or wells with throughput less
than 10 barrels per day.
1,000 = Conversion to cubic feet
* * * * *
(8) * * *
[GRAPHIC] [TIFF OMITTED] TR23DE11.015
Where:
* * * * *
En = Storage tank emissions as determined in Calculation
Methodologies 1, 2, or 4 in paragraphs (j)(1), (j)(2) and (j)(4) of
this section (with wellhead separators) in standard cubic feet per
year.
* * * * *
8,760 = Conversion to hourly emissions.
* * * * *
(k) Transmission storage tanks. For vent stacks connected to one or
more transmission condensate storage tanks, either water or
hydrocarbon, without vapor recovery, in onshore natural gas
transmission compression, calculate CH4, CO2 and
N2O annual emissions from compressor scrubber dump valve
leakage as follows:
(1) Monitor the tank vapor vent stack annually for emissions using
an optical gas imaging instrument according to methods set forth in
Sec. 98.234(a)(1) or by directly measuring the tank vent using a flow
meter or high volume sampler according to methods in Sec. 98.234(b)
through (d) for a duration of 5 minutes, or a calibrated bag according
to methods in Sec. 98.234(b). Or you may annually monitor leakage
through compressor scrubber dump valve(s) into the tank using an
acoustic leak detection device according to methods set forth in Sec.
98.234(a)(5).
(2) If the tank vapors from the vent stack are continuous for 5
minutes, or the acoustic leak detection device detects a leak, then use
one of the following two methods in paragraph (k)(2) of this section to
quantify annual emissions:
(i) Use a meter, such as a turbine meter, calibrated bag, or high
flow sampler to estimate tank vapor volumes from the vent stack
according to methods set forth in Sec. 98.234(b) through (d). If you
do not have a continuous flow measurement device, you may install a
flow measuring device on the tank vapor vent stack. If the vent is
directly measured for five minutes under paragraph Sec. 98.233(k)(1)
of this section to detect continuous leakage, this serves as the
measurement.
* * * * *
(iv) Calculate GHG volumetric and mass emissions at standard
conditions using calculations in paragraphs (t), (u), and (v) of this
section, as applicable to the monitoring equipment used.
* * * * *
(4) Calculate annual emissions from storage tanks to flares as
follows:
(i) Use the storage tank emissions volume and gas composition as
determined in paragraphs (k)(1) through (k)(3) of this section.
(ii) Use the calculation methodology of flare stacks in paragraph
(n) of this section to determine storage tank emissions sent to a
flare.
(l) * * *
(1) Determine the gas to oil ratio (GOR) of the hydrocarbon
production from oil well(s) tested. Determine the production rate from
gas well(s) tested.
* * * * *
(3) Estimate venting emissions using Equation W-17A or Equation W-
17B of this section.
[[Page 80582]]
[GRAPHIC] [TIFF OMITTED] TR23DE11.016
Where:
Ea,n = Annual volumetric natural gas emissions from
well(s) testing in cubic feet under actual conditions.
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil
here refers to hydrocarbon liquids produced of all API gravities.
FR = Flow rate in barrels of oil per day for the oil well(s) being
tested.
PR = Average annual production rate in cubic feet per day for the
gas well(s) being tested.
D = Number of days during the year, the well(s) is tested.
* * * * *
(m) * * *
(1) Determine the GOR of the hydrocarbon production from each well
whose associated natural gas is vented or flared. If GOR from each well
is not available, the GOR from a cluster of wells in the same sub-basin
category shall be used.
* * * * *
(3) * * *
[GRAPHIC] [TIFF OMITTED] TR23DE11.017
Where:
Ea,n = Annual volumetric natural gas emissions, at the
facility level, from associated gas venting under actual conditions,
in cubic feet.
GORp,q = Gas to oil ratio, for well p in sub-basin q, in
cubic feet of gas per barrel of oil; oil here refers to hydrocarbon
liquids produced of all API gravities.
Vp,q = Volume of oil produced, for well p in sub-basin q,
in barrels in the calendar year during which associated gas was
vented or flared.
x = Total number of wells in sub-basin that vent or flare associated
gas.
y = Total number of sub-basins in a basin that contain wells that
vent or flare associated gas.
* * * * *
(n) * * *
(2) * * *
(ii) For onshore natural gas processing, when the stream going to
flare is natural gas, use the GHG mole percent in feed natural gas for
all streams upstream of the de-methanizer or dew point control, and GHG
mole percent in facility specific residue gas to transmission pipeline
systems for all emissions sources downstream of the de-methanizer
overhead or dew point control for onshore natural gas processing
facilities. For onshore natural gas processing plants that solely
fractionate a liquid stream, use the GHG mole percent in feed natural
gas liquid for all streams.
(iii) For any applicable industry segment, when the stream going to
the flare is a hydrocarbon product stream, such as methane, ethane,
propane, butane, pentane-plus and mixed light hydrocarbons, then you
may use a representative composition from the source for the stream
determined by engineering calculation based on process knowledge and
best available data.
* * * * *
(4) * * *
[GRAPHIC] [TIFF OMITTED] TR23DE11.018
* * * * *
(9) If you operate and maintain a CEMS that has both a
CO2 concentration monitor and volumetric flow rate monitor,
you must calculate only CO2 emissions for the flare. You
must follow the Tier 4 Calculation Methodology and all associated
calculation, quality assurance, reporting, and recordkeeping
requirements for Tier 4 in subpart C of this part (General Stationary
Fuel Combustion Sources). If a CEMS is used to calculate flare stack
emissions, the requirements specified in paragraphs (n)(1) through
(n)(7) are not required. If a CO2 concentration monitor and
volumetric flow rate monitor are not available, you may elect to
install a CO2 concentration monitor and a volumetric flow
rate monitor that comply with all of the requirements specified for the
Tier 4 Calculation Methodology in subpart C of this part (General
Stationary Fuel Combustion).
* * * * *
(11) If source types in Sec. 98.233 use Equations W-19 through W-
21 of this section, use estimate of emissions under actual conditions
for the parameter, Va, in these equations.
(o) * * *
(6) * * *
MTm = Flow Measurements from all centrifugal compressor
vents in each mode in (o)(1)(i) through (o)(1)(iii) of this section
in standard cubic feet per hour.
* * * * *
(7) * * *
EFi = 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\ thousand standard cubic feet per year per
compressor for CO2 at 60[emsp14][deg]F and 14.7 psia.
* * * * *
[[Page 80583]]
(p) * * *
(7) * * *
(i) * * *
MTm = Meter readings from all reciprocating compressor
vents in each and mode, m, in standard cubic feet per hour.
* * * * *
(9) * * *
EFi = 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.
* * * * *
(q) Leak detection and leaker emission factors. You must use the
methods described in Sec. 98.234(a) to conduct leak detection(s) of
equipment leaks from all component types listed in Sec. 98.232(d)(7),
(e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). This paragraph (q) applies
to component types in streams with gas content greater than 10 percent
CH4 plus CO2 by weight. Component types in
streams with gas content less than 10 percent CH4 plus
CO2 by weight do not need to be reported. Tubing systems
equal to or less than one half inch diameter are exempt from the
requirements of this paragraph (q) and do not need to be reported. If
equipment leaks are detected for sources listed in this paragraph (q),
calculate equipment leak emissions per component type per reporting
facility using Equations W-30A or W-30B of this section for each
component type. Use Equation W-30A for industry segments listed in
98.230(a)(3)-(a)(7). Use Equation W-30B for industry segments listed in
98.230(a)(8).
[GRAPHIC] [TIFF OMITTED] TR23DE11.019
Where:
Es,i = Annual total volumetric GHG emissions at standard
conditions from each component type in cubic feet, as specified in
(q)(1) through (q)(8) of this section.
x = Total number of each component type.
EF = Leaker emission factor for specific component types listed in
Table W-2 through Table W-7 of this subpart.
GHGi = For onshore natural gas processing facilities,
concentration of GHGi, CH4 or CO2,
in the total hydrocarbon of the feed natural gas; for onshore
natural gas transmission compression and underground natural gas
storage, GHGi equals 0.975 for CH4 and 1.1
x10-2 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.
Tp = The total time the component, p, was found leaking
and operational, in hours. If one leak detection survey is
conducted, assume the component was leaking for the entire calendar
year. If multiple leak detection surveys are conducted, assume that
the component found to be leaking has been leaking since the
previous survey (if not found leaking in the previous survey) or the
beginning of the calendar year (if it was found leaking in the
previous survey). For the last leak detection survey in the calendar
year, assume that all leaking components continue to leak until the
end of the calendar year.
t = Calendar year of reporting.
n = The number of years over which one complete cycle of leak
detection is conducted over all the T-D transfer stations in a
natural gas distribution facility; 0 < n <= 5. For the first (n-1)
calendar years of reporting the summation in Equation W-30B should
be for years that the data is available.
Tp,q = The total time the component, p, was found leaking
and operational, in hours, in year q. If one leak detection survey
is conducted, assume the component was leaking for the entire period
n. If multiple leak detection surveys are conducted, assume that the
component found to be leaking has been leaking since the previous
survey (if not found to be leaking in the previous survey) or the
beginning of the calendar year (if it was found to be leaking in the
previous survey). For the last leak detection survey in the cycle,
assume that all leaking components continue to leak until the end of
the cycle.
* * * * *
(8) Natural gas distribution facilities for above grade
transmission-distribution transfer stations, shall use the appropriate
default leaker emission factors listed in Table W-7 of this subpart for
equipment leaks detected from connectors, block valves, control valves,
pressure relief valves, orifice meters, regulators, and open ended
lines. Leak detection at natural gas distribution facilities is only
required at above grade stations that qualify as transmission-
distribution transfer stations. Below grade transmission-distribution
transfer stations and all metering-regulating stations that do meet the
definition of transmission-distribution transfer stations are not
required to perform component leak detection under this section.
(i) Natural gas distribution facilities may choose to conduct leak
detection at the T-D transfer stations over multiple years, not
exceeding a five year period to cover all T-D transfer stations. If the
facility chooses to use the multiple year option then the number of T-D
transfer stations that are monitored in each year should be
approximately equal across all years in the cycle without monitoring
the same station twice during the multiple year survey.
(ii) [Reserved]
(r) Population count and emission factors. This paragraph applies
to emissions sources listed in Sec. 98.232 (c)(21), (f)(5), (g)(3),
(h)(4), (i)(2), (i)(3), (i)(4), (i)(5), and (i)(6) on streams with gas
content greater than 10 percent CH4 plus CO2 by
weight. Emissions sources in streams with gas content less than 10
percent CH4 plus CO2 by weight do not need to be
reported. Tubing systems equal 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. Calculate emissions from all sources listed
in this paragraph using Equation W-31 of this section.
* * * * *
Es,i = Annual volumetric GHG emissions at standard
conditions from each component type in cubic feet.
Counts = Total number of this type of emission source at
the facility. For onshore petroleum and natural gas production,
average component counts are provided by major equipment piece in
Tables W-1B and Table W-1C of this subpart. Use average component
counts as appropriate for operations in Eastern and Western U.S.,
according to Table W-1D of this subpart. Underground natural gas
storage shall count the components listed for population emission
factors in Table W-4. LNG Storage shall count the number of vapor
recovery compressors. LNG import and export shall count the number
of vapor recovery compressors. Natural gas distribution shall count
the
[[Page 80584]]
meter/regulator runs as described in paragraph (r)(6) of this
section.
EF = Population emission factor for the specific component type, as
listed in Table W-1A and Tables W-3 through Table W-7 of this
subpart. Use appropriate population emission factor for operations
in Eastern and Western U.S., according to Table W-1D of this
subpart. EF for meter/regulator runs at above grade metering-
regulating stations is determined in Equation W-32 of this section.
GHGi = For onshore petroleum and natural gas production
facilities, concentration of GHGi, CH4 or
CO2, in produced natural gas 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.
Ts = Average estimated time that each component type
associated with the equipment leak emission was operational in the
calendar year, in hours, using engineering estimate based on best
available data.
* * * * *
(2) * * *
(i) * * *
(A) Count all major equipment listed in Table W-1B and Table W-1C
of this subpart. For meters/piping, use one meters/piping per well-pad.
* * * * *
(6) * * *
(i) Below grade metering-regulating stations; distribution mains;
and distribution services, shall use the appropriate default population
emission factors listed in Table W-7 of this subpart. Below grade T-D
transfer stations shall use the emission factor for below grade
metering-regulating stations.
(ii) Emissions from all above grade metering-regulating stations
(including above grade TD transfer stations) shall be calculated by
applying the emission factor calculated in Equation W-32 and the total
count of meter/regulator runs at all above grade metering-regulating
stations (inclusive of TD transfer stations) to Equation W-31. The
facility wide emission factor in Equation W-32 will be calculated by
using the total volumetric GHG emissions at standard conditions for all
equipment leak sources calculated in Equation W-30B in paragraph (q)(8)
of this section and the count of meter/regulator runs located at above
grade transmission-distribution transfer stations that were monitored
over the years that constitute one complete cycle as per (q)(8)(i) of
this section. A meter on a regulator run is considered one meter or
regulator run. Reporters that do not have above grade T-D transfer
stations shall report a count of above grade metering-regulating
stations only and do not have to comply with Sec. 98.236(c)(16)(xix).
[GRAPHIC] [TIFF OMITTED] TR23DE11.020
Where:
EF = Facility emission factor for a meter/regulator run per
component type at above grade metering-regulating for
GHGi in cubic feet per meter/regulator run per hour.
Es,i = Annual volumetric GHG i emissions, CO2
or CH4 at standard condition from each component type at
all above grade TD transfer stations, from Equation W-30B.
Count = Total number of meter/regulator runs at all TD transfer
stations that were monitored over the years that constitute one
complete cycle as per (q)(8)(i) of this section.
8760 = Conversion to hourly emissions
* * * * *
(t) Volumetric emissions. Calculate volumetric emissions at
standard conditions as specified in paragraphs (t)(1) or (2) of this
section, with actual pressure and temperature determined by engineering
estimates based on best available data unless otherwise specified.
(1) Calculate natural gas volumetric emissions at standard
conditions using actual natural gas emission temperature and pressure,
and Equation W-33 of this section.
* * * * *
Ts = Temperature at standard conditions (60 [deg]F).
* * * * *
Ps = Absolute pressure at standard conditions (14.7
psia).
* * * * *
(2) Calculate GHG volumetric emissions at standard conditions using
actual GHG emissions temperature and pressure, and Equation W-34 of
this section.
* * * * *
Ts = Temperature at standard conditions (60 [deg]F).
* * * * *
Ps = Absolute pressure at standard conditions (14.7
psia).
* * * * *
(3) Reporters using 68 [deg]F for standard temperature may use the
ratio 519.67/527.67 to convert volumetric emissions from 68 [deg]F to
60 [deg]F.
(u) GHG volumetric emissions. Calculate GHG volumetric emissions at
standard conditions as specified in paragraphs (u)(1) and (2) of this
section, with mole fraction of GHGs in the natural gas determined by
engineering estimate based on best available data unless otherwise
specified.
* * * * *
(2) For Equation W-35 of this section, the mole fraction,
Mi, shall be the annual average mole fraction for each sub-
basin category or facility, as specified in paragraphs (u)(2)(i)
through (vii) of this section.
(i) GHG mole fraction in produced natural gas for onshore petroleum
and natural gas production facilities. If you have a continuous gas
composition analyzer for produced natural gas, you must use an annual
average of these values for determining the mole fraction. If you do
not have a continuous gas composition analyzer, then you must use an
annual average gas composition based on your most recent available
analysis of the sub-basin category or facility, as applicable to the
emission source.
(ii) GHG mole fraction in feed natural gas for all emissions
sources upstream of the de-methanizer or dew point control and GHG mole
fraction in facility specific residue gas to transmission pipeline
systems for all emissions sources downstream of the de-methanizer
overhead or dew point control for onshore natural gas processing
facilities. For onshore natural gas processing plants that solely
fractionate a liquid stream, use the GHG mole percent in feed natural
gas liquid for all streams. If you have a continuous gas composition
analyzer on feed natural gas, you must use these values for determining
the mole fraction. If you do not have a continuous gas composition
analyzer, then annual samples must be taken according to methods set
forth in Sec. 98.234(b).
(iii) GHG mole fraction in transmission pipeline natural gas that
passes through the facility for the onshore natural gas transmission
compression industry segment. You may use a default 95 percent methane
and 1 percent carbon dioxide fraction for GHG mole fraction in natural
gas.
(iv) GHG mole fraction in natural gas stored in the underground
natural gas storage industry segment. You may use a default 95 percent
methane and 1 percent carbon dioxide fraction for GHG mole fraction in
natural gas.
(v) GHG mole fraction in natural gas stored in the LNG storage
industry segment. You may use a default 95 percent methane and 1
percent carbon dioxide fraction for GHG mole fraction in natural gas.
(vi) GHG mole fraction in natural gas stored in the LNG import and
export industry segment. For export facilities that receive gas from
transmission
[[Page 80585]]
pipelines, you may use a default 95 percent methane and 1 percent
carbon dioxide fraction for GHG mole fraction in natural gas.
(vii) GHG mole fraction in local distribution pipeline natural gas
that passes through the facility for natural gas distribution
facilities. You may use a default 95 percent methane and 1 percent
carbon dioxide fraction for GHG mole fraction in natural gas.
(v) GHG mass emissions. Calculate GHG mass emissions in carbon
dioxide equivalent by converting the GHG volumetric emissions at
standard conditions into mass emissions using Equation W-36 of this
section.
[GRAPHIC] [TIFF OMITTED] TR23DE11.021
Where:
Massi = GHGi (either CH4,
CO2, or N2O) mass emissions in metric tons
CO2e.
Es,i = GHGi (either CH4,
CO2, or N2O) volumetric emissions at standard
conditions, in cubic feet.
[rho]i = Density of GHGi. Use 0.0526 kg/ft\3\ for
CO2 and N2O, and 0.0422 kg/ft\3\ for
CH4 at 60 [deg]F and 14.7 psia.
* * * * *
(w) * * *
(3) * * *
[GRAPHIC] [TIFF OMITTED] TR23DE11.022
Where:
MassCO2 = Annual EOR injection gas venting emissions in
metric tons from blowdowns.
* * * * *
GHGCO2 = Mass fraction of CO2 in critical
phase injection gas.
* * * * *
(x) * * *
(2) * * *
[GRAPHIC] [TIFF OMITTED] TR23DE11.023
Where:
MassCO2 = Annual CO2 emissions from
CO2 retained in hydrocarbon liquids produced through EOR
operations beyond tankage, in metric tons.
* * * * *
(z) Onshore petroleum and natural gas production and natural gas
distribution combustion emissions. Calculate CO2,
CH4, and N2O combustion-related emissions from
stationary or portable equipment, except as specified in paragraph
(z)(3) and (z)(4) of this section, as follows:
(1) If a fuel combusted in the stationary or portable equipment is
listed in Table C-1 of subpart C of this part, or is a blend containing
one or more fuels listed in Table C-1, calculate emissions according to
(z)(1)(i). If the fuel combusted is natural gas and is of pipeline
quality specification and has a minimum high heat value of 950 Btu per
standard cubic foot, use the calculation methodology described in
(z)(1)(i) and you may use the emission factor provided for natural gas
as listed in Table C-1. If the fuel is natural gas, and is not pipeline
quality or has a high heat value of less than 950 Btu per standard
cubic feet, calculate emissions according to (z)(2). If the fuel is
field gas, process vent gas, or a blend containing field gas or process
vent gas, calculate emissions according to (z)(2).
(i) For fuels listed in Table C-1 or a blend containing one or more
fuels listed in Table C-1, calculate CO2, CH4,
and N2O emissions according to any Tier listed in subpart C
of this part. You must follow all applicable calculation requirements
for that tier listed in 98.33, any monitoring or QA/QC requirements
listed for that tier in 98.34, any missing data procedures specified in
98.35, and any recordkeeping requirements specified in 98.37.
(ii) Emissions from fuel combusted in stationary or portable
equipment at onshore natural gas and petroleum production facilities
and at natural gas distribution facilities will be reported according
to the requirements specified in 98.236(c)(19) and not according to the
reporting requirements specified in subpart C of this part.
(2) For fuel combustion units that combust field gas, process vent
gas, a blend containing field gas or process vent gas, or natural gas
that is not of pipeline quality or that has a high heat value of less
than 950 Btu per standard cubic feet, calculate combustion emissions as
follows:
(i) You may use company records to determine the volume of fuel
combusted in the unit during the reporting year.
(ii) If you have a continuous gas composition analyzer on fuel to
the combustion unit, you must use these compositions for determining
the concentration of gas hydrocarbon constituent in the flow of gas to
the unit. If you do not have a continuous gas composition analyzer on
gas to the combustion unit, you must use the appropriate gas
compositions for each stream of hydrocarbons going to the combustion
unit as specified in the applicable paragraph in (u)(2) of this
section.
(iii) Calculate GHG volumetric emissions at actual conditions using
Equations W-39A and W-39B of this section:
[GRAPHIC] [TIFF OMITTED] TR23DE11.024
[[Page 80586]]
Where:
ECO2 = Contribution of annual CO2 emissions
from portable or stationary fuel combustion sources in cubic feet,
under actual conditions.
Va = Volume of gas sent to combustion unit in cubic feet,
during the year.
YCO2 = Concentration of CO2 constituent in gas
sent to combustion unit.
Ea,CH4 = Contribution of annual CH4 emissions
from portable or stationary fuel combustion sources in cubic feet,
under actual conditions.
[eta] = Fraction of gas combusted for portable and stationary
equipment determined using engineering estimation. For internal
combustion devices, a default of 0.995 can be used.
Yj = Concentration of gas hydrocarbon constituents j
(such as methane, ethane, propane, butane, and pentanes plus) in gas
sent to combustion unit.
Rj = Number of carbon atoms in the gas hydrocarbon
constituent j; 1 for methane, 2 for ethane, 3 for propane, 4 for
butane, and 5 for pentanes plus, in gas sent to combustion unit.
YCH4 = Concentration of methane constituent in gas sent
to combustion unit.
* * * * *
(vi) Calculate N2O mass emissions using Equation W-40 of
this section.
[GRAPHIC] [TIFF OMITTED] TR23DE11.025
Where:
MassN 2 O = Annual N2O
emissions from the combustion of a particular type of fuel (metric
tons CO2e).
* * * * *
HHV = For the high heat value for field gas or process vent gas, use
1.235 x 10-3 mmBtu/scf for HHV.
* * * * *
GWP = Global warming potential, as listed in Table A-1 of subpart A
of this part.
(3) External fuel combustion sources with a rated heat capacity
equal to or less than 5 mmBtu/hr do not need to report combustion
emissions or include these emissions for threshold determination in
Sec. 98.231(a). You must report the type and number of each external
fuel combustion unit.
(4) Internal fuel combustion sources, not compressor-drivers, with
a rated heat capacity equal to or less than 1 mmBtu/hr (or the
equivalent of 130 horsepower), do not need to report combustion
emissions or include these emissions for threshold determination in
Sec. 98.231(a). You must report the type and number of each internal
fuel combustion unit.
0
7. Section 98.234 is amended by:
0
a. Revising paragraphs (a)(1), (a)(2), and (a)(5).
0
b. Removing and reserving paragraph (a)(4).
0
c. Revising paragraph (c) introductory text and paragraph (d)(3).
0
d. Revising Equation W-41 of paragraph (e).
0
e. Adding new paragraph (g).
Sec. 98.234 Monitoring and QA/QC requirements.
* * * * *
(a) * * *
(1) Optical gas imaging instrument. Use an optical gas imaging
instrument for equipment leak detection in accordance with 40 CFR part
60, subpart A, Sec. 60.18 of the Alternative work practice for
monitoring equipment leaks, Sec. 60.18(i)(1)(i); Sec. 60.18(i)(2)(i)
except that the monitoring frequency shall be annual using the
detection sensitivity level of 60 grams per hour as stated in 40 CFR
Part 60, subpart A, Table 1: Detection Sensitivity Levels; Sec.
60.18(i)(2)(ii) and (iii) except the gas chosen shall be methane, and
Sec. 60.18(i)(2)(iv) and (v); Sec. 60.18(i)(3); Sec. 60.18(i)(4)(i)
and (v); including the requirements for daily instrument checks and
distances, and excluding requirements for video records. Any emissions
detected by the optical gas imaging instrument is a leak unless
screened with Method 21 (40 CFR part 60, appendix A-7) monitoring, in
which case 10,000 ppm or greater is designated a leak. In addition, you
must operate the optical gas imaging instrument to image the source
types required by this subpart in accordance with the instrument
manufacturer's operating parameters. Unless using methods in paragraph
(a)(2) of this section, an optical gas imaging instrument must be used
for all source types that are inaccessible and cannot be monitored
without elevating the monitoring personnel more than 2 meters above a
support surface.
(2) Method 21. Use the equipment leak detection methods in 40 CFR
part 60, appendix A-7, Method 21. If using Method 21 monitoring, if an
instrument reading of 10,000 ppm or greater is measured, a leak is
detected. Inaccessible emissions sources, as defined in 40 CFR part 60,
are not exempt from this subpart. Owners or operators must use
alternative leak detection devices as described in paragraph (a)(1) or
(a)(2) of this section to monitor inaccessible equipment leaks or
vented emissions.
* * * * *
(5) Acoustic leak detection device. Use the acoustic leak detection
device to detect through-valve leakage. When using the acoustic leak
detection device to quantify the through-valve leakage, you must use
the instrument manufacturer's calculation methods to quantify the
through-valve leak. When using the acoustic leak detection device, if a
leak of 3.1 scf per hour or greater is calculated, a leak is detected.
In addition, you must operate the acoustic leak detection device to
monitor the source valves required by this subpart in accordance with
the instrument manufacturer's operating parameters. Acoustic
stethoscope type devices designed to detect through valve leakage when
put in contact with the valve body and that provide an audible leak
signal but do not calculate a leak rate can be used to identify non-
leakers with subsequent measurement required to calculate the rate if
through-valve leakage is identified. Leaks are reported if a leak rate
of 3.1 scf per hour or greater is measured.
* * * * *
(c) Use calibrated bags (also known as vent bags) only where the
emissions are at near-atmospheric pressures and below the maximum
temperature specified by the vent bag manufacturer such that the bag is
safe to handle. The bag opening must be of sufficient size that the
entire emission can be tightly encompassed for measurement till the bag
is completely filled.
* * * * *
(d) * * *
(3) Estimate natural gas volumetric emissions at standard
conditions using calculations in Sec. 98.233(t). Estimate
CH4 and CO2 volumetric and mass emissions from
volumetric natural gas emissions using the calculations in Sec.
98.233(u) and (v).
* * * * *
(e) * * *
[[Page 80587]]
[GRAPHIC] [TIFF OMITTED] TR23DE11.026
Where:
p = Absolute pressure.
R = Universal gas constant.
T = Absolute temperature.
Vm = Molar volume.
[GRAPHIC] [TIFF OMITTED] TR23DE11.027
Where:
[omega] = Acentric factor of the species.
Tc = Critical temperature.
Pc = Critical pressure.
* * * * *
(g) For the purposes of fulfilling requirements in 40 CFR 98.233(f)
and (g) which require measurements to be taken every other year
beginning in the first year of data collection, reporters have the
option of taking the first measurement in 2012 to satisfy the
requirements for the 2011-2012 data collection cycle.
0
8. Section 98.236 is amended by:
0
a. Revising paragraphs (a) introductory text and (a)(8).
0
b. Revising paragraph (b).
0
c. Revising paragraphs (c) introductory text, (c)(1)(iv), (c)(2)(ii),
and (c)(3)(ii) through (c)(3)(v); and adding paragraphs (c)(3)(vi) and
(vii).
0
d. Revising paragraphs (c)(4)(i)(H) and (C)(4)(i)(J); and adding
paragraphs (c)(4)(i)(K), and (c)(4)(i)(L).
0
e. Revising paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(C); and adding
paragraph (c)(4)(ii)(D).
0
f. Revising paragraph (c)(4)(iii)(B).
0
g. Revising paragraph (c)(5).
0
h. Revising paragraphs (c)(6) introductory text, and (c)(6)(i).
0
i. Revising paragraph (c)(6)(ii)(B), (c)(6)(ii)(D) and adding paragraph
(c)(6)(ii)(E).
0
j. Revising paragraph (c)(7).
0
k. Revising paragraphs (c)(8)(i) introductory text and (c)(8)(i)(J);
and adding paragraphs (c)(8)(i)(K) and (c)(8)(i)(L).
0
l. Revising paragraphs (c)(8)(ii) introductory text, (c)(8)(ii)(D), and
(c)(8)(ii)(G); and adding paragraphs (c)(8)(ii)(H) and (c)(8)(ii)(I).
0
m. Revising paragraphs (c)(8)(iii) introductory text and
(c)(8)(iii)(F); and adding paragraphs (c)(8)(iii)(G) and
(c)(8)(iii)(H).
0
n. Adding paragraph (c)(8)(iv)(B).
0
o. Revising paragraphs (c)(9) introductory text and (c)(9)(i) ; and
adding paragraphs (c)(9)(ii) (c)(9)(iii).
0
p. Revising paragraphs (c)(10) introductory text and (c)(10)(iv); and
adding paragraph (c)(10)(v).
0
q. Revising paragraph (c)(11) introductory text and (c)(11)(iii); and
adding paragraph (c)(11)(iv).
0
r. Revising paragraph (c)(12)(vi) and adding paragraphs (c)(12)(vii)
through (c)(12)(xi).
0
s. Revising paragraphs (c)(15) introductory text, (c)(15)(i)(A),
(c)(15)(i)(B) and (c)(15)(i)(C).
0
t. Revising paragraphs (c)(15)(ii)(A) through (c)(15)(ii)(C).
0
u. Revising paragraph (c)(16).
0
v. Revising paragraph (c)(17)(v).
0
w. Revising paragraphs (c)(18) introductory text and paragraph
(c)(18)(iii).
0
x. Revising paragraphs (c)(19)(iii), (c)(19)(v), (c)(19)(vi), and
(c)(19)(vii).
0
y. Adding paragraph (e).
The revisions read as follows:
Sec. 98.236 Data Reporting Requirements.
* * * * *
(a) Report annual emissions in metric tons of CO2e for
each GHG separately for each of the industry segments listed in
paragraphs (a)(1) through (8) of this section.
* * * * *
(8) Natural gas distribution.
(b) For offshore petroleum and natural gas production, report
emissions of CH4, CO2, and N2O as
applicable to the source type (in metric tons CO2e per year
at standard conditions) individually for all of the emissions source
types listed in the most recent BOEMRE study.
(c) Report the information listed in this paragraph for each
applicable source type in metric tons of CO2e for each GHG.
If a facility operates under more than one industry segment, each piece
of equipment should be reported under the unit's respective majority
use segment. When a source type listed under this paragraph routes gas
to flare, separately report the emissions that were vented directly to
the atmosphere without flaring, and the emissions that resulted from
flaring the gas. Both the vented and flared emissions will be reported
under the respective source type and not under the flare source type.
(1) * * *
(iv) Report annual CO2 and CH4 emissions at
the facility level, expressed in metric tons CO2e for each
gas, for each of the following pieces of equipment: high bleed
pneumatic devices; intermittent bleed pneumatic devices; low bleed
pneumatic devices.
(2) * * *
(ii) Report annual CO2 and CH4 emissions at
the facility level, expressed in metric tons CO2e for each
gas, for all natural gas driven pneumatic pumps combined.
(3) * * *
(ii) For Calculation Methodology 1 and Calculation Methodology 2 of
Sec. 98.233(d), annual average fraction of CO2 content in
the vent from the acid gas removal unit (refer to Sec. 98.233(d)(6)).
[[Page 80588]]
(iii) For Calculation Methodology 3 of Sec. 98.233(d), annual
average volume fraction of CO2 content of natural gas into
and out of the acid gas removal unit (refer to Sec. 98.233(d)(7) and
(d)(8)).
(iv) Report the annual quantity of CO2, expressed in
metric tons CO2e, that was recovered from the AGR unit and
transferred outside the facility, under subpart PP of this part.
(v) Report annual CO2 emissions for the AGR unit,
expressed in metric tons CO2e.
(vi) For the onshore natural gas processing industry segment only,
report a unique name or ID number for the AGR unit.
(vii) An indication of which calculation methodology was used for
the AGR.
(4) * * *
(i) * * *
(H) Concentration of CH4 and CO2 in wet
natural gas.
* * * * *
(J) For each glycol dehydrator, report annual CO2 and
CH4 emissions that resulted from venting gas directly to the
atmosphere, expressed in metric tons CO2e for each gas.
(K) For each glycol dehydrator, report annual CO2,
CH4, and N2O emissions that resulted from flaring
process gas from the dehydrator, expressed in metric tons
CO2e for each gas.
(L) For the onshore natural gas processing industry segment only,
report a unique name or ID number for glycol dehydrator.
(ii) * * *
(B) Which vent gas controls are used (refer to Sec. 98.233(e)(3)
and (e)(4)).
(C) Report annual CO2 and CH4 emissions at
the facility level that resulted from venting gas directly to the
atmosphere, expressed in metric tons CO2e for each gas,
combined for all glycol dehydrators with annual average daily
throughput of less than 0.4 MMscfd.
(D) Report annual CO2, CH4, and
N2O emissions at the facility level that resulted from the
flaring of process gas, expressed in metric tons CO2e for
each gas, combined for all glycol dehydrators with annual average daily
throughput of less than 0.4 MMscfd.
(iii) * * *
(B) Report annual CO2 and CH4 emissions at
the facility level, expressed in metric tons CO2e for each
gas, for all absorbent desiccant dehydrators combined.
(5) For well venting for liquids unloading, report the following:
(i) For Calculation Methodology 1 (refer to Equation W-7 of Sec.
98.233), report the following for each tubing diameter group and
pressure group combination within each sub-basin category:
(A) Count of wells vented to the atmosphere for liquids unloading.
(B) Count of plunger lifts. Whether the selected well from the
tubing diameter and pressure group combination had a plunger lift (yes/
no).
(C) Cumulative number of unloadings vented to the atmosphere.
(D) Average flow rate of the measured well venting in cubic feet
per hour (refer to Sec. 98.233(f)(1)(i)(A)).
(E) Internal casing diameter or internal tubing diameter in inches,
where applicable, and well depth of each well, in feet, selected to
represent emissions in that tubing size and pressure combination.
(F) Casing pressure, in psia, of each well selected to represent
emissions in that tubing size group and pressure group combination that
does not have a plunger lift.
(G) Tubing pressure, in psia, of each well selected to represent
emissions in a tubing size group and pressure group combination that
has a plunger lift.
(H) Report annual CO2 and CH4 emissions,
expressed in metric tons CO2e for each gas.
(ii) For Calculation Methodologies 2 and 3 (refer to Equation W-8
and W-9 of Sec. 98.233), report the following for each sub-basin
category:
(A) Count of wells vented to the atmosphere for liquids unloading.
(B) Count of plunger lifts.
(C) Cumulative number of unloadings vented to the atmosphere.
(D) Average internal casing diameter, in inches, of each well,
where applicable.
(E) Report annual CO2 and CH4 emissions,
expressed in metric tons CO2e for each GHG gas.
(6) For well completions and workovers, report the following for
each sub-basin category:
(i) For gas well completions and workovers with hydraulic
fracturing by sub-basin and well type (horizontal or vertical)
combination (refer to Equation W-10A and W-10B of Sec. 98.233), report
the following:
(A) Total count of completions in calendar year.
(B) When using Equation W-10A, measured flow rate of backflow
during well completion in standard cubic feet per hour.
(C) Total count of workovers in calendar year that flare gas or
vent gas to the atmosphere.
(D) When using Equation W-10A, measured flow rate of backflow
during well workover in standard cubic feet per hour.
(E) When using Equation W-10A, total number of days of backflow
from all wells during completions.
(F) When using Equation W-10A, total number of days of backflow
from all wells during workovers.
(G) Report number of completions employing purposely designed
equipment that separates natural gas from the backflow and the amount
of natural gas, in standard cubic feet, recovered using engineering
estimate based on best available.
(H) Report number of workovers employing purposely designed
equipment that separates natural gas from the backflow and the amount
of natural gas, in standard cubic feet, recovered using engineering
estimate based on best available data.
(I) Annual CO2 and CH4 emissions that
resulted from venting gas directly to the atmosphere, expressed in
metric tons CO2e for each gas.
(J) Annual CO2, CH4, and N2O
emissions that resulted from flares, expressed in metric tons
CO2e for each gas.
(ii) * * *
(B) Total count of workovers in calendar year that flare gas or
vent gas to the atmosphere.
* * * * *
(D) Annual CO2 and CH4 emissions that
resulted from venting gas directly to the atmosphere, expressed in
metric tons CO2e for each gas.
(E) Annual CO2, CH4, and N2O
emissions that resulted from flares, expressed in metric tons
CO2e for each gas.
(7) For blowdown vent stack emission source, (refer to Equation W-
14A and Equation W-14B of Sec. 98.233), report the following:
(i) For each unique physical volume that is blown down more than
once during the calendar year, report the following:
(A) Total number of blowdowns for each unique physical volume in
the calendar year.
(B) Annual CO2 and CH4 emissions, for each
unique physical blowdown volume, expressed in metric tons
CO2e for each gas.
(C) A unique name or ID number for the unique physical volume.
(ii) For all unique volumes that are blown down once during the
calendar year, report the following:
(A) Total number of blowdowns for all unique physical volumes in
the calendar year.
(B) Annual CO2 and CH4 emissions from all
unique physical volumes as an aggregate per facility, expressed in
metric tons CO2e for each gas.
[[Page 80589]]
(8) * * *
(i) For wellhead gas-liquid separator with oil throughput greater
than or equal to 10 barrels per day, using Calculation Methodology 1
and 2 of Sec. 98.233(j), report the following by sub-basin category,
unless otherwise specified:
* * * * *
(J) Annual CO2 and CH4 emissions that
resulted from venting gas to the atmosphere, expressed in metric tons
CO2e for each gas, for all wellhead gas-liquid separators or
storage tanks using Calculation Methodology 1, and for all wellhead
gas-liquid separators or storage tanks using Calculation Methodology 2
of Sec. 98.233(j).
(K) Annual CO2 and CH4 gas quantities that
were recovered, expressed in metric tons CO2e for each gas,
for all wellhead gas-liquid separators or storage tanks using
Calculation Methodology 1, and for all wellhead gas-liquid separators
or storage tanks using Calculation Methodology 2 of Sec. 98.233(j).
(L) Annual CO2, CH4, and N2O
emissions that resulted from flaring gas, expressed in metric tons
CO2e for each gas, for all wellhead gas-liquid separators or
storage tanks using Calculation Methodology 1, and for all wellhead
gas-liquid separators or storage tanks using Calculation Methodology 2
of Sec. 98.233(j).
(ii) For wells with oil production greater than or equal to 10
barrels per day, using Calculation Methodology 3 and 4 of Sec.
98.233(j), report the following by sub-basin category:
* * * * *
(D) Sales oil API gravity range for wells in (c)(8)(ii)(B) and
(c)(8)(ii)(C) of this section, in degrees.
* * * * *
(G) Annual CO2 and CH4 emissions that
resulted from venting gas to the atmosphere, expressed in metric tons
CO2e for each gas, at the sub-basin level for Calculation
Methodology 3 or 4 of Sec. 98.233(j).
(H) Annual CO2 and CH4 gas quantities that
were recovered, expressed in metric tons CO2e for each gas,
at the sub-basin level for Calculation Methodology 3 or 4 of Sec.
98.233(j).
(I) Annual CO2, CH4, and N2O
emissions that resulted from flaring gas, expressed in metric tons
CO2e for each gas, at the sub-basin level for Calculation
Methodology 3 and 4 of Sec. 98.233(j).
(iii) For wellhead gas-liquid separators and wells with throughput
less than 10 barrels per day, using Calculation Methodology 5 of Sec.
98.233(j) Equation W-15 of Sec. 98.233, report the following:
* * * * *
(F) Annual CO2 and CH4 emissions that
resulted from venting gas to the atmosphere, expressed in metric tons
CO2e for each gas, at the sub-basin level for Calculation
Methodology 5 of Sec. 98.233(j).
(G) Annual CO2 and CH4 gas quantities that
were recovered, expressed in metric tons CO2e for each gas,
at the sub-basin level for Calculation Methodology 5 of Sec.
98.233(j).
(H) Annual CO2, CH4, and N2O
emissions that resulted from flaring gas, expressed in metric tons
CO2e for each gas, at the sub-basin level for Calculation
Methodology 5 of Sec. 98.233(j).
(iv) * * *
(B) Annual CO2 and CH4 emissions that
resulted from venting gas to the atmosphere, expressed in metric tons
CO2e for each gas, at the sub-basin level for improperly
functioning dump valves.
(9) For transmission tank emissions identified using optical gas
imaging instrument per Sec. 98.234(a) (refer to Sec. 98.233(k)), or
acoustic leak detection of scrubber dump valves, report the following:
(i) For each vent stack, report annual CO2 and
CH4 emissions that resulted from venting gas directly to the
atmosphere, expressed in metric tons CO2e for each gas.
(ii) For each transmission storage tank, report annual
CO2, CH4, and N2O emissions that
resulted from flaring process gas from the transmission storage tank,
expressed in metric tons CO2e for each gas.
(iii) A unique name or ID number for the vent stack monitored
according to 40 CFR 98.233(k).
(10) For well testing venting and flaring (refer to Equation W-17A
or W-17B of Sec. 98.233), report the following:
* * * * *
(iv) Report annual CO2 and CH4 emissions at
the facility level, expressed in metric tons CO2e for each
gas, emissions from well testing venting.
(v) Report annual CO2, CH4, and
N2O emissions at the facility level, expressed in metric
tons CO2e for each gas, emissions from well testing flaring.
(11) For associated natural gas venting and flaring (refer to
Equation W-18 of Sec. 98.233), report the following for each basin:
* * * * *
(iii) Report annual CO2 and CH4 emissions at
the facility level, expressed in metric tons CO2e for each
gas, emissions from associated natural gas venting.
(iv) Report annual CO2, CH4, and
N2O emissions at the facility level, expressed in metric
tons CO2e for each gas, emissions from associated natural
gas flaring.
(12) * * *
(vi) Report uncombusted CH4 emissions, in metric tons
CO2e (refer to Equation W-19 of Sec. 98.233).
(vii) Report uncombusted CO2 emissions, in metric tons
CO2e (refer to Equation W-20 of Sec. 98.233).
(viii) Report combusted CO2 emissions, in metric tons
CO2e (refer to Equation W-21 of Sec. 98.233).
(ix) Report N2O emissions, in metric tons
CO2e.
(x) For the natural gas processing industry segment, a unique name
or ID number for the flare stack.
(xi) In the case that a CEMS is used to measure CO2
emissions for the flare stack, indicate that a CEMS was used in the
annual report and report the combusted CO2 and uncombusted
CO2 as a combined number.
* * * * *
(15) For each component type (major equipment type for onshore
production) that uses emission factors for estimating emissions (refer
to Sec. 98.233(q) and (r))
(i) * * *
(A) Total count of leaks found in each complete survey listed by
date of survey and each component type for which there is a leaker
emission factor in Tables W-2, W-3, W-4, W-5, W-6, and W-7 of this
subpart.
(B) For onshore natural gas processing, range of concentrations of
CH4 and CO2 (refer to Equation W-30 of Sec.
98.233).
(C) Annual CO2 and CH4 emissions, in metric
tons CO2e for each gas (refer to parameter GHGi
in Equation W-30 of Sec. 98.233), by component type.
(ii) * * *
(A) For source categories Sec. 98.230(a)(4), (a)(5), (a)(6),
(a)(7), and (a)(8), total count for each component type in Tables W-2,
W-3, W-4, W-5, and W-6 of this subpart for which there is a population
emission factor, listed by major heading and component type.
(B) For onshore production (refer to Sec. 98.230 paragraph
(a)(2)), total count for each type of major equipment in Table W-1B and
Table W-1C of this subpart, by facility.
(C) Annual CO2 and CH4 emissions, in metric
tons CO2e for each gas (refer to Equation W-31 of Sec.
98.233), by component type.
(16) For local distribution companies, report the following:
(i) Total number of above grade T-D transfer stations in the
facility.
[[Page 80590]]
(ii) Number of years over which all T-D transfer stations will be
monitored at least once.
(iii) Number of T-D stations monitored in calendar year.
(iv) Total number of below grade T-D transfer stations in the
facility.
(v) Total number of above grade metering-regulating stations (this
count will include above grade T-D transfer stations) in the facility.
(vi) Total number of below grade metering-regulating stations (this
count will include below grade T-D transfer stations) in the facility.
(vii) [Reserved]
(viii) Leak factor for meter/regulator run developed in Equation W-
32 of Sec. 98.233.
(ix) Number of miles of unprotected steel distribution mains.
(x) Number of miles of protected steel distribution mains.
(xi) Number of miles of plastic distribution mains.
(xii) Number of miles of cast iron distribution mains.
(xiii) Number of unprotected steel distribution services.
(xiv) Number of protected steel distribution services.
(xv) Number of plastic distribution services.
(xvi) Number of copper distribution services.
(xvii) Annual CO2 and CH4 emissions, in
metric tons CO2e for each gas, from all above grade T-D
transfer stations combined.
(xviii) Annual CO2 and CH4 emissions, in
metric tons CO2e for each gas, from all below grade T-D
transfer stations combined.
(xix) Annual CO2 and CH4 emissions, in metric
tons CO2e for each gas, from all above grade metering-
regulating stations (including T-D transfer stations) combined.
(xx) Annual CO2 and CH4 emissions, in metric
tons CO2e for each gas, from all below grade metering-
regulating stations (including T-D transfer stations) combined.
(xxi) Annual CO2 and CH4 emissions, in metric
tons CO2e for each gas, from all distribution mains
combined.
(xxii) Annual CO2 and CH4 emissions, in
metric tons CO2e for each gas, from all distribution
services combined.
(17) * * *
(v) For each EOR pump, report annual CO2 and
CH4 emissions, expressed in metric tons CO2e for
each gas.
(18) For EOR hydrocarbon liquids dissolved CO2 for each
sub-basin category (refer to Equation W-38 of Sec. 98.233), report the
following:
* * * * *
(iii) Report annual CO2 emissions at the sub-basin
level, expressed in metric tons CO2e.
(19) * * *
(iii) Report annual CO2, CH4, and
N2O emissions from external fuel combustion units with a
rated heat capacity larger than 5 mmBtu/hr, expressed in metric tons
CO2e for each gas, by type of unit.
* * * * *
(v) Cumulative number of internal fuel combustion units, not
compressor-drivers, with a rated heat capacity equal to or less than 1
mmBtu/hr or 130 horsepower, by type of unit.
(vi) Report annual CO2, CH4, and
N2O emissions from internal combustion units greater than
1mmBtu/hr, expressed in metric tons CO2e for each gas, by
type of unit.
(vii) Cumulative volume of fuel combusted in internal combustion
units with a rated heat capacity larger than 1 mmBtu/hr or 130
horsepower, by fuel type.
* * * * *
(e) For onshore petroleum and natural gas production, report the
best available estimate of API gravity, best available estimate of gas
to oil ratio, and best available estimate of average low pressure
separator pressure for each oil sub-basin category.
0
9. Section 98.237 is amended by adding paragraph (e) to read as
follows:
Sec. 98.237 Records that must be retained.
* * * * *
(e) The records required under Sec. 98.3(g)(2)(i) shall include an
explanation of how company records, engineering estimation, or best
available information are used to calculate each applicable parameter
under this subpart.
0
10. Section 98.238 is amended by:
0
a. Revising the definitions of ``Facility with respect to natural gas
distribution for purposes of this subpart and subpart A'', ``Facility
with respect to onshore petroleum and natural gas production for
purposes of this subpart and for subpart A'', ``Farm Taps'', and
``Transmission pipeline''.
0
b. Adding definitions of ``Associated with a single well-pad'',
``Distribution pipeline'', ``Flare'', ``Forced extraction'',
``Horizontal well'', ``Meter/regulator run'', ``Metering-regulating
station'', ''Natural gas'', ``Pressure groups'', ``Sub-basin
category'', ``Transmission-distribution transfer station'', ``Tubing
diameter groups'', ``Tubing systems'', ``Vertical well'', and ``Well
testing venting and flaring''.
0
c. Removing the definitions of ``Gas well'' and ``Oil well''.
The revisions read as follows:
Sec. 98.238 Definitions.
* * * * *
Associated with a single well-pad means associated with the
hydrocarbon stream as produced from one or more wells located on that
single well-pad. The association ends where the stream from a single
well-pad is combined with streams from one or more additional single
well-pads, where the point of combination is located off that single
well-pad. Onshore production storage tanks on or associated with a
single well-pad are considered a part of the onshore production
facility.
* * * * *
Distribution pipeline means a pipeline that is designated as such
by the Pipeline and Hazardous Material Safety Administration (PHMSA) 49
CFR 192.3.
* * * * *
Facility with respect to natural gas distribution for purposes of
reporting under this subpart and for the corresponding subpart A
requirements means the collection of all distribution pipelines and
metering-regulating stations that are operated by a Local Distribution
Company (LDC) within a single state that is regulated as a separate
operating company by a public utility commission or that are operated
as an independent municipally-owned distribution system.
Facility with respect to onshore petroleum and natural gas
production for purposes of reporting under this subpart and for the
corresponding subpart A requirements means all petroleum or natural gas
equipment on a single well-pad or associated with a single well-pad and
CO2 EOR operations that are under common ownership or common
control including leased, rented, or contracted activities by an
onshore petroleum and natural gas production owner or operator and that
are located in a single hydrocarbon basin as defined in Sec. 98.238.
Where a person or entity owns or operates more than one well in a
basin, then all onshore petroleum and natural gas production equipment
associated with all wells that the person or entity owns or operates in
the basin would be considered one facility.
Farm Taps are pressure regulation stations that deliver gas
directly from transmission pipelines to generally rural customers. In
some cases a nearby LDC may handle the billing of the gas to the
customer(s).
* * * * *
Flare, for the purposes of subpart W, means a combustion device,
whether at ground level or elevated, that uses an
[[Page 80591]]
open or closed flame to combust waste gases without energy recovery.
* * * * *
Forced extraction of natural gas liquids means removal of ethane or
higher carbon number hydrocarbons existing in the vapor phase in
natural gas, by removing ethane or heavier hydrocarbons derived from
natural gas into natural gas liquids by means of a forced extraction
process. Forced extraction processes include but are not limited to
refrigeration, absorption (lean oil), cryogenic expander, and
combinations of these processes. Forced extraction does not include in
and of itself; natural gas dehydration, or the collection or gravity
separation of water or hydrocarbon liquids from natural gas at ambient
temperature or heated above ambient temperatures, or the condensation
of water or hydrocarbon liquids through passive reduction in pressure
or temperature, or portable dewpoint suppression skids.
Horizontal well means a well bore that has a planned deviation from
primarily vertical to a primarily horizontal inclination or declination
tracking in parallel with and through the target formation.
* * * * *
Meter/regulator run means a series of components used in regulating
pressure or metering natural gas flow or both.
Metering-regulating station means a station that meters the
flowrate, regulates the pressure, or both, of natural gas in a natural
gas distribution facility. This does not include customer meters,
customer regulators, or farm taps.
Natural gas means a naturally occurring mixture or process
derivative of hydrocarbon and non-hydrocarbon gases found in geologic
formations beneath the earth's surface, of which its constituents
include, but are not limited to, methane, heavier hydrocarbons and
carbon dioxide. Natural gas may be field quality, pipeline quality, or
process gas.
* * * * *
Pressure groups as applicable to each sub-basin are defined as
follows: Less than or equal to 25 psig; greater than 25 psig and less
than or equal to 60 psig; greater than 60 psig and less than or equal
to 110 psig; greater than 110 psig and less than or equal to 200 psig;
and greater than 200 psig. The pressure in the context of pressure
groups is either the well shut-in pressure; well casing pressure; or
you may use the casing-to-tubing pressure of one well from the same
sub-basin multiplied by the tubing pressure for each well in the sub-
basin.
* * * * *
Sub-basin category, for onshore natural gas production, means a
subdivision of a basin into the unique combination of wells with the
surface coordinates within the boundaries of an individual county and
subsurface completion in one or more of each of the following five
formation types: Oil, high permeability gas, shale gas, coal seam, or
other tight reservoir rock. The distinction between high permeability
gas and tight gas reservoirs shall be designated as follows: High
permeability gas reservoirs with >0.1 millidarcy permeability, and
tight gas reservoirs with <=0.1 millidarcy permeability. Permeability
for a reservoir type shall be determined by engineering estimate. Wells
that produce from high permeability gas, shale gas, coal seam, or other
tight reservoir rock are considered gas wells; gas wells producing from
more than one of these formation types shall be classified into only
one type based on the formation with the most contribution to
production as determined by engineering knowledge. All wells that
produce hydrocarbon liquids and do not meet the definition of a gas
well in this sub-basin category definition are considered to be in the
oil formation. All emission sources that handle condensate from gas
wells in high permeability gas, shale gas, or tight reservoir rock
formations are considered to be in the formation that the gas well
belongs to and not in the oil formation.
Transmission-distribution (T-D) transfer station means a metering-
regulating station where a local distribution company takes part or all
of the natural gas from a transmission pipeline and puts it into a
distribution pipeline.
Transmission pipeline means a Federal Energy Regulatory Commission
rate-regulated Interstate pipeline, a state rate-regulated Intrastate
pipeline, or a pipeline that falls under the ``Hinshaw Exemption'' as
referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717
(w)(1994).
Tubing diameter groups are defined as follows: Outer diameter less
than or equal to 1 inch; outer diameter greater than 1 inch and less
than 2.375 inch; and outer diameter greater than or equal to 2.375
inch.
Tubing systems means piping equal to or less than one half inch
diameter as per nominal pipe size.
* * * * *
Vertical well means a well bore that is primarily vertical but has
some unintentional deviation or one or more intentional deviations to
enter one or more subsurface targets that are off-set horizontally from
the surface location, intercepting the targets either vertically or at
an angle.
Well testing venting and flaring means venting and/or flaring of
natural gas at the time the production rate of a well is determined for
regulatory, commercial, or technical purposes. If well testing is
conducted immediately after well completion or workover, then it is
considered part of well completion or workover.
0
11. Table W-1A to Subpart W of Part 98 is revised to read as follows:
Table A-1A of Subpart W--Default Whole Gas Emission Factors for Onshore
Petroleum and Natural Gas Production
------------------------------------------------------------------------
Emission factor
Onshore petroleum and natural gas production (scf/hour/
component)
------------------------------------------------------------------------
Eastern U.S.
Population Emission Factors--All Components, Gas Service 1
------------------------------------------------------------------------
Valve............................................ 0.640
Connector........................................ 0.083
Open-ended Line.................................. 1.46
Pressure Relief Valve............................ 0.97
Low Continuous Bleed Pneumatic Device Vents \2\.. 1.39
High Continuous Bleed Pneumatic Device Vents \2\. 37.3
Intermittent Bleed Pneumatic Device Vents \2\.... 13.5
Pneumatic Pumps \3\.............................. 10.3
------------------------------------------------------------------------
[[Page 80592]]
Population Emission Factors--All Components, Light Crude Service 4
------------------------------------------------------------------------
Valve............................................ 0.04
Flange........................................... 0.002
Connector........................................ 0.005
Open-ended Line.................................. 0.04
Pump............................................. 0.01
Other \5\........................................ 0.23
------------------------------------------------------------------------
Population Emission Factors--All Components, Heavy Crude Service 6
------------------------------------------------------------------------
Valve............................................ 0.0004
Flange........................................... 0.0007
Connector (other)................................ 0.0002
Open-ended Line.................................. 0.004
Other \5\........................................ 0.002
------------------------------------------------------------------------
Western U.S.
Population Emission Factors--All Components, Gas Service 1
------------------------------------------------------------------------
Valve............................................ 2.903
Connector........................................ 0.396
Open-ended Line.................................. 0.748
Pressure Relief Valve............................ 4.631
Low Continuous Bleed Pneumatic Device Vents \2\.. 1.77
High Continuous Bleed Pneumatic Device Vents \2\. 47.4
Intermittent Bleed Pneumatic Device Vents \2\.... 17.1
Pneumatic Pumps \3\.............................. 10.3
------------------------------------------------------------------------
Population Emission Factors--All Components, Light Crude Service 4
------------------------------------------------------------------------
Valve............................................ 0.04
Flange........................................... 0.002
Connector........................................ 0.005
Open-ended Line.................................. 0.04
Pump............................................. 0.01
Other \5\........................................ 0.23
------------------------------------------------------------------------
Population Emission Factors--All Components, Heavy Crude Service \6\
------------------------------------------------------------------------
Valve............................................ 0.0004
Flange........................................... 0.0007
Connector (other)................................ 0.0002
Open-ended Line.................................. 0.004
Other \5\........................................ 0.002
------------------------------------------------------------------------
\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.''
0
12. Table W-2 of Subpart W of Part 98 is revised to read as follows:
Table W-2 of Subpart W--Default Total Hydrocarbon Emission Factors for
Onshore Natural Gas Processing
------------------------------------------------------------------------
Emission factor
Onshore natural gas processing plants (scf/hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--Compressor Components, Gas Service
------------------------------------------------------------------------
Valve \1\........................................ 14.84
Connector........................................ 5.59
Open-Ended Line.................................. 17.27
[[Page 80593]]
Pressure Relief Valve............................ 39.66
Meter............................................ 19.33
------------------------------------------------------------------------
Leaker Emission Factors--Non-Compressor Components, Gas Service
------------------------------------------------------------------------
Valve \1\........................................ 6.42
Connector........................................ 5.71
Open-Ended Line.................................. 11.27
Pressure Relief Valve............................ 2.01
Meter............................................ 2.93
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
0
13. Table W-3 to Subpart W of Part 98 is revised to read as follows:
Table W-3 of Subpart W--Default Total Hydrocarbon Emission Factors for
Onshore Natural Gas Transmission Compression
------------------------------------------------------------------------
Emission factor
Onshore natural gas transmission compression (scf/hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--Compressor Components, Gas Service
------------------------------------------------------------------------
Valve \1\........................................ 14.84
Connector........................................ 5.59
Open-Ended Line.................................. 17.27
Pressure Relief Valve............................ 39.66
Meter............................................ 19.33
------------------------------------------------------------------------
Leaker Emission Factors--Non-Compressor Components, Gas Service
------------------------------------------------------------------------
Valve \1\........................................ 6.42
Connector........................................ 5.71
Open-Ended Line.................................. 11.27
Pressure Relief Valve............................ 2.01
Meter............................................ 2.93
------------------------------------------------------------------------
Population Emission Factors--Gas Service
------------------------------------------------------------------------
Low Continuous Bleed Pneumatic Device Vents \2\.. 1.37
High Continuous Bleed Pneumatic Device Vents \2\. 18.20
Intermittent Bleed Pneumatic Device Vents \2\.... 2.35
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Emission Factor is in units of ``scf/hour/device.''
0
14. Table W-4 to Subpart W of Part 98 is revised to read as follows:
Table W-4 of Subpart W--Default Total Hydrocarbon Emission Factors for
Underground Natural Gas Storage
------------------------------------------------------------------------
Emission factor
Underground natural gas storage (scf/hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--Storage Station, Gas Service
------------------------------------------------------------------------
Valve \1\....................................... 14.84
Connector....................................... 5.59
Open-Ended Line................................. 17.27
Pressure Relief Valve........................... 39.66
Meter........................................... 19.33
------------------------------------------------------------------------
[[Page 80594]]
Population Emission Factors--Storage Wellheads, Gas Service
------------------------------------------------------------------------
Connector....................................... 0.01
Valve........................................... 0.1
Pressure Relief Valve........................... 0.17
Open Ended Line................................. 0.03
------------------------------------------------------------------------
Population Emission Factors--Other Components, Gas Service
------------------------------------------------------------------------
Low Continuous Bleed Pneumatic Device Vents \2\. 1.37
High Continuous Bleed Pneumatic Device Vents \2\ 18.20
Intermittent Bleed Pneumatic Device Vents \2\... 2.35
------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Emission Factor is in units of ``scf/hour/device.''
0
15. Table W-5 to Subpart W of Part 98 is revised to read as follows:
Table W-5 of Subpart W--Default Methane Emission Factors for Liquefied
Natural Gas (LNG) Storage
------------------------------------------------------------------------
Emission factor
LNG storage (scf/hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--LNG Storage Components, LNG Service
------------------------------------------------------------------------
Valve............................................ 1.19
Pump Seal........................................ 4.00
Connector........................................ 0.34
Other \1\........................................ 1.77
------------------------------------------------------------------------
Population Emission Factors--LNG Storage Compressor, Gas Service
------------------------------------------------------------------------
Vapor Recovery Compressor........................ 4.17
------------------------------------------------------------------------
\1\ ``Other'' equipment type should be applied for any equipment type
other than connectors, pumps, or valves.
\2\ Emission Factor is in units of ``scf/hour/device.''
0
16. Table W-6 to Subpart W of Part 98 is revised to read as follows:
Table W-6 of Subpart W--Default Methane Emission Factors for LNG Import
and Export Equipment
------------------------------------------------------------------------
Emission factor
LNG import and export equipment (scf/hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--LNG Terminals Components, LNG Service
------------------------------------------------------------------------
Valve............................................ 1.19
Pump Seal........................................ 4.00
Connector........................................ 0.34
Other \1\........................................ 1.77
------------------------------------------------------------------------
Population Emission Factors--LNG Terminals Compressor, Gas Service
------------------------------------------------------------------------
Vapor Recovery Compressor \2\.................... 4.17
------------------------------------------------------------------------
\1\ ``Other'' equipment type should be applied for any equipment type
other than connectors, pumps, or valves.
\2\ Emission Factors is in units of ``scf/hour/compressor.''
0
17. Table W-7 to subpart W of Part 98 is revised to read as follows:
[[Page 80595]]
Table W-7 of Subpart W--Default Methane Emission Factors for Natural Gas
Distribution
------------------------------------------------------------------------
Emission factor
Natural gas distribution (scf/hour/
component)
------------------------------------------------------------------------
Leaker Emission Factors--Transmission-Distribution Transfer Station 1
Components, Gas Service
------------------------------------------------------------------------
Connector....................................... 1.69
Block Valve..................................... 0.557
Control Valve................................... 9.34
Pressure Relief Valve........................... 0.27
Orifice Meter................................... 0.212
Regulator....................................... 0.772
Open-ended Line................................. 26.131
------------------------------------------------------------------------
Population Emission Factors--Below Grade Metering-Regulating station 1
Components, Gas Service 2
------------------------------------------------------------------------
Below Grade M&R Station, Inlet Pressure > 300 1.30
psig...........................................
Below Grade M&R Station, Inlet Pressure 100 to 0.20
300 psig.......................................
Below Grade M&R Station, Inlet Pressure < 100 0.10
psig...........................................
------------------------------------------------------------------------
Population Emission Factors--Distribution Mains, Gas Service 3
------------------------------------------------------------------------
Unprotected Steel............................... 12.58
Protected Steel................................. 0.35
Plastic......................................... 1.13
Cast Iron....................................... 27.25
------------------------------------------------------------------------
Population Emission Factors--Distribution Services, Gas Service 4
------------------------------------------------------------------------
Unprotected Steel............................... 0.19
Protected Steel................................. 0.02
Plastic......................................... 0.001
Copper.......................................... 0.03
------------------------------------------------------------------------
\1\ Excluding customer meters.
\2\ Emission Factor is in units of ``scf/hour/station.''
\3\ Emission Factor is in units of ``scf/hour/mile.''
\4\ Emission Factor is in units of ``scf/hour/number of services.''
[FR Doc. 2011-31532 Filed 12-22-11; 8:45 am]
BILLING CODE 6560-50-P