```

[Federal Register Volume 76, Number 247 (Friday, December 23, 2011)]
[Rules and Regulations]
[Pages 80554-80595]
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

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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]]

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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.

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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 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 p,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:

MassN2O = 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 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 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
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