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

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

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

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.

    (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.

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

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.

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

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:

[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

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.

[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.
* * * * *

    (p) * * *
    (7) * * *
    (i) * * *

MTm = Meter readings from all reciprocating compressor
vents in each and mode, m, in standard cubic feet per hour.
* * * * *
    (9) * * *

EFi = Emission factor for GHGi. Use 9.48 x
10\3\ standard cubic feet per year per compressor for CH4
and 5.27 x 10\2\ standard cubic feet per year per compressor for
CO2 at 60 [deg]F and 14.7 psia.
* * * * *
    (q) Leak detection and leaker emission factors. You must use the
methods described in Sec.  98.234(a) to conduct leak detection(s) of
equipment leaks from all component types listed in Sec.  98.232(d)(7),
(e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). This paragraph (q) applies
to component types in streams with gas content greater than 10 percent
CH4 plus CO2 by weight. Component types in
streams with gas content less than 10 percent CH4 plus
CO2 by weight do not need to be reported. Tubing systems
equal to or less than one half inch diameter are exempt from the
requirements of this paragraph (q) and do not need to be reported. If
equipment leaks are detected for sources listed in this paragraph (q),
calculate equipment leak emissions per component type per reporting
facility using Equations W-30A or W-30B of this section for each
component type. Use Equation W-30A for industry segments listed in
98.230(a)(3)-(a)(7). Use Equation W-30B for industry segments listed in
98.230(a)(8).
[GRAPHIC] [TIFF OMITTED] TR23DE11.019

Where:

Es,i = Annual total volumetric GHG emissions at standard
conditions from each component type in cubic feet, as specified in
(q)(1) through (q)(8) of this section.
x = Total number of each component type.
EF = Leaker emission factor for specific component types listed in
Table W-2 through Table W-7 of this subpart.
GHGi = For onshore natural gas processing facilities,
concentration of GHGi, CH4 or CO2,
in the total hydrocarbon of the feed natural gas; for onshore
natural gas transmission compression and underground natural gas
storage, GHGi equals 0.975 for CH4 and 1.1
x10-2 for CO2; for LNG storage and LNG import
and export equipment, GHGi equals 1 for CH4
and 0 for CO2; and for natural gas distribution,
GHGi equals 1 for CH4 and 1.1 x
10-2 CO2.
Tp = The total time the component, p, was found leaking
and operational, in hours. If one leak detection survey is
conducted, assume the component was leaking for the entire calendar
year. If multiple leak detection surveys are conducted, assume that
the component found to be leaking has been leaking since the
previous survey (if not found leaking in the previous survey) or the
beginning of the calendar year (if it was found leaking in the
previous survey). For the last leak detection survey in the calendar
year, assume that all leaking components continue to leak until the
end of the calendar year.
t = Calendar year of reporting.
n = The number of years over which one complete cycle of leak
detection is conducted over all the T-D transfer stations in a
natural gas distribution facility; 0 < n <= 5. For the first (n-1)
calendar years of reporting the summation in Equation W-30B should
be for years that the data is available.
Tp,q = The total time the component, p, was found leaking
and operational, in hours, in year q. If one leak detection survey
is conducted, assume the component was leaking for the entire period
n. If multiple leak detection surveys are conducted, assume that the
component found to be leaking has been leaking since the previous
survey (if not found to be leaking in the previous survey) or the
beginning of the calendar year (if it was found to be leaking in the
previous survey). For the last leak detection survey in the cycle,
assume that all leaking components continue to leak until the end of
the cycle.
* * * * *
    (8) Natural gas distribution facilities for above grade
transmission-distribution transfer stations, shall use the appropriate
default leaker emission factors listed in Table W-7 of this subpart for
equipment leaks detected from connectors, block valves, control valves,
pressure relief valves, orifice meters, regulators, and open ended
lines. Leak detection at natural gas distribution facilities is only
required at above grade stations that qualify as transmission-
distribution transfer stations. Below grade transmission-distribution
transfer stations and all metering-regulating stations that do meet the
definition of transmission-distribution transfer stations are not
required to perform component leak detection under this section.
    (i) Natural gas distribution facilities may choose to conduct leak
detection at the T-D transfer stations over multiple years, not
exceeding a five year period to cover all T-D transfer stations. If the
facility chooses to use the multiple year option then the number of T-D
transfer stations that are monitored in each year should be
approximately equal across all years in the cycle without monitoring
the same station twice during the multiple year survey.
    (ii) [Reserved]
    (r) Population count and emission factors. This paragraph applies
to emissions sources listed in Sec.  98.232 (c)(21), (f)(5), (g)(3),
(h)(4), (i)(2), (i)(3), (i)(4), (i)(5), and (i)(6) on streams with gas
content greater than 10 percent CH4 plus CO2 by
weight. Emissions sources in streams with gas content less than 10
percent CH4 plus CO2 by weight do not need to be
reported. Tubing systems equal to or less than one half inch diameter
are exempt from the requirements of paragraph (r) of this section and
do not need to be reported. Calculate emissions from all sources listed
in this paragraph using Equation W-31 of this section.
* * * * *
Es,i = Annual volumetric GHG emissions at standard
conditions from each component type in cubic feet.
Counts = Total number of this type of emission source at
the facility. For onshore petroleum and natural gas production,
average component counts are provided by major equipment piece in
Tables W-1B and Table W-1C of this subpart. Use average component
counts as appropriate for operations in Eastern and Western U.S.,
according to Table W-1D of this subpart. Underground natural gas
storage shall count the components listed for population emission
factors in Table W-4. LNG Storage shall count the number of vapor
recovery compressors. LNG import and export shall count the number
of vapor recovery compressors. Natural gas distribution shall count
the

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

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

Where:

ECO2 = Contribution of annual CO2 emissions
from portable or stationary fuel combustion sources in cubic feet,
under actual conditions.
Va = Volume of gas sent to combustion unit in cubic feet,
during the year.
YCO2 = Concentration of CO2 constituent in gas
sent to combustion unit.
Ea,CH4 = Contribution of annual CH4 emissions
from portable or stationary fuel combustion sources in cubic feet,
under actual conditions.
[eta] = Fraction of gas combusted for portable and stationary
equipment determined using engineering estimation. For internal
combustion devices, a default of 0.995 can be used.
Yj = Concentration of gas hydrocarbon constituents j
(such as methane, ethane, propane, butane, and pentanes plus) in gas
sent to combustion unit.
Rj = Number of carbon atoms in the gas hydrocarbon
constituent j; 1 for methane, 2 for ethane, 3 for propane, 4 for
butane, and 5 for pentanes plus, in gas sent to combustion unit.
YCH4 = Concentration of methane constituent in gas sent
to combustion unit.
* * * * *
    (vi) Calculate N2O mass emissions using Equation W-40 of
this section.
[GRAPHIC] [TIFF OMITTED] TR23DE11.025

Where:

MassN 2 O = Annual N2O
emissions from the combustion of a particular type of fuel (metric
tons CO2e).
* * * * *
HHV = For the high heat value for field gas or process vent gas, use
1.235 x 10-3 mmBtu/scf for HHV.
* * * * *
GWP = Global warming potential, as listed in Table A-1 of subpart A
of this part.

    (3) External fuel combustion sources with a rated heat capacity
equal to or less than 5 mmBtu/hr do not need to report combustion
emissions or include these emissions for threshold determination in
Sec.  98.231(a). You must report the type and number of each external
fuel combustion unit.
    (4) Internal fuel combustion sources, not compressor-drivers, with
a rated heat capacity equal to or less than 1 mmBtu/hr (or the
equivalent of 130 horsepower), do not need to report combustion
emissions or include these emissions for threshold determination in
Sec.  98.231(a). You must report the type and number of each internal
fuel combustion unit.

0
7. Section 98.234 is amended by:
0
a. Revising paragraphs (a)(1), (a)(2), and (a)(5).
0
b. Removing and reserving paragraph (a)(4).
0
c. Revising paragraph (c) introductory text and paragraph (d)(3).
0
d. Revising Equation W-41 of paragraph (e).
0
e. Adding new paragraph (g).

Sec.  98.234  Monitoring and QA/QC requirements.

* * * * *
    (a) * * *
    (1) Optical gas imaging instrument. Use an optical gas imaging
instrument for equipment leak detection in accordance with 40 CFR part
60, subpart A, Sec.  60.18 of the Alternative work practice for
monitoring equipment leaks, Sec.  60.18(i)(1)(i); Sec.  60.18(i)(2)(i)
except that the monitoring frequency shall be annual using the
detection sensitivity level of 60 grams per hour as stated in 40 CFR
Part 60, subpart A, Table 1: Detection Sensitivity Levels; Sec.
60.18(i)(2)(ii) and (iii) except the gas chosen shall be methane, and
Sec.  60.18(i)(2)(iv) and (v); Sec.  60.18(i)(3); Sec.  60.18(i)(4)(i)
and (v); including the requirements for daily instrument checks and
distances, and excluding requirements for video records. Any emissions
detected by the optical gas imaging instrument is a leak unless
screened with Method 21 (40 CFR part 60, appendix A-7) monitoring, in
which case 10,000 ppm or greater is designated a leak. In addition, you
must operate the optical gas imaging instrument to image the source
types required by this subpart in accordance with the instrument
manufacturer's operating parameters. Unless using methods in paragraph
(a)(2) of this section, an optical gas imaging instrument must be used
for all source types that are inaccessible and cannot be monitored
without elevating the monitoring personnel more than 2 meters above a
support surface.
    (2) Method 21. Use the equipment leak detection methods in 40 CFR
part 60, appendix A-7, Method 21. If using Method 21 monitoring, if an
instrument reading of 10,000 ppm or greater is measured, a leak is
detected. Inaccessible emissions sources, as defined in 40 CFR part 60,
are not exempt from this subpart. Owners or operators must use
alternative leak detection devices as described in paragraph (a)(1) or
(a)(2) of this section to monitor inaccessible equipment leaks or
vented emissions.
* * * * *
    (5) Acoustic leak detection device. Use the acoustic leak detection
device to detect through-valve leakage. When using the acoustic leak
detection device to quantify the through-valve leakage, you must use
the instrument manufacturer's calculation methods to quantify the
through-valve leak. When using the acoustic leak detection device, if a
leak of 3.1 scf per hour or greater is calculated, a leak is detected.
In addition, you must operate the acoustic leak detection device to
monitor the source valves required by this subpart in accordance with
the instrument manufacturer's operating parameters. Acoustic
stethoscope type devices designed to detect through valve leakage when
put in contact with the valve body and that provide an audible leak
signal but do not calculate a leak rate can be used to identify non-
leakers with subsequent measurement required to calculate the rate if
through-valve leakage is identified. Leaks are reported if a leak rate
of 3.1 scf per hour or greater is measured.
* * * * *
    (c) Use calibrated bags (also known as vent bags) only where the
emissions are at near-atmospheric pressures and below the maximum
temperature specified by the vent bag manufacturer such that the bag is
safe to handle. The bag opening must be of sufficient size that the
entire emission can be tightly encompassed for measurement till the bag
is completely filled.
* * * * *
    (d) * * *
    (3) Estimate natural gas volumetric emissions at standard
conditions using calculations in Sec.  98.233(t). Estimate
CH4 and CO2 volumetric and mass emissions from
volumetric natural gas emissions using the calculations in Sec.
98.233(u) and (v).
* * * * *
    (e) * * *

[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)).

    (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.

    (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.

    (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

open or closed flame to combust waste gases without energy recovery.
* * * * *
    Forced extraction of natural gas liquids means removal of ethane or
higher carbon number hydrocarbons existing in the vapor phase in
natural gas, by removing ethane or heavier hydrocarbons derived from
natural gas into natural gas liquids by means of a forced extraction
process. Forced extraction processes include but are not limited to
refrigeration, absorption (lean oil), cryogenic expander, and
combinations of these processes. Forced extraction does not include in
and of itself; natural gas dehydration, or the collection or gravity
separation of water or hydrocarbon liquids from natural gas at ambient
temperature or heated above ambient temperatures, or the condensation
of water or hydrocarbon liquids through passive reduction in pressure
or temperature, or portable dewpoint suppression skids.
    Horizontal well means a well bore that has a planned deviation from
primarily vertical to a primarily horizontal inclination or declination
tracking in parallel with and through the target formation.
* * * * *
    Meter/regulator run means a series of components used in regulating
pressure or metering natural gas flow or both.
    Metering-regulating station means a station that meters the
flowrate, regulates the pressure, or both, of natural gas in a natural
gas distribution facility. This does not include customer meters,
customer regulators, or farm taps.
    Natural gas means a naturally occurring mixture or process
derivative of hydrocarbon and non-hydrocarbon gases found in geologic
formations beneath the earth's surface, of which its constituents
include, but are not limited to, methane, heavier hydrocarbons and
carbon dioxide. Natural gas may be field quality, pipeline quality, or
process gas.
* * * * *
    Pressure groups as applicable to each sub-basin are defined as
follows: Less than or equal to 25 psig; greater than 25 psig and less
than or equal to 60 psig; greater than 60 psig and less than or equal
to 110 psig; greater than 110 psig and less than or equal to 200 psig;
and greater than 200 psig. The pressure in the context of pressure
groups is either the well shut-in pressure; well casing pressure; or
you may use the casing-to-tubing pressure of one well from the same
sub-basin multiplied by the tubing pressure for each well in the sub-
basin.
* * * * *
    Sub-basin category, for onshore natural gas production, means a
subdivision of a basin into the unique combination of wells with the
surface coordinates within the boundaries of an individual county and
subsurface completion in one or more of each of the following five
formation types: Oil, high permeability gas, shale gas, coal seam, or
other tight reservoir rock. The distinction between high permeability
gas and tight gas reservoirs shall be designated as follows: High
permeability gas reservoirs with >0.1 millidarcy permeability, and
tight gas reservoirs with <=0.1 millidarcy permeability. Permeability
for a reservoir type shall be determined by engineering estimate. Wells
that produce from high permeability gas, shale gas, coal seam, or other
tight reservoir rock are considered gas wells; gas wells producing from
more than one of these formation types shall be classified into only
one type based on the formation with the most contribution to
production as determined by engineering knowledge. All wells that
produce hydrocarbon liquids and do not meet the definition of a gas
well in this sub-basin category definition are considered to be in the
oil formation. All emission sources that handle condensate from gas
wells in high permeability gas, shale gas, or tight reservoir rock
formations are considered to be in the formation that the gas well
belongs to and not in the oil formation.
    Transmission-distribution (T-D) transfer station means a metering-
regulating station where a local distribution company takes part or all
of the natural gas from a transmission pipeline and puts it into a
distribution pipeline.
    Transmission pipeline means a Federal Energy Regulatory Commission
rate-regulated Interstate pipeline, a state rate-regulated Intrastate
pipeline, or a pipeline that falls under the ``Hinshaw Exemption'' as
referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717
(w)(1994).
    Tubing diameter groups are defined as follows: Outer diameter less
than or equal to 1 inch; outer diameter greater than 1 inch and less
than 2.375 inch; and outer diameter greater than or equal to 2.375
inch.
    Tubing systems means piping equal to or less than one half inch
diameter as per nominal pipe size.
* * * * *
    Vertical well means a well bore that is primarily vertical but has
some unintentional deviation or one or more intentional deviations to
enter one or more subsurface targets that are off-set horizontally from
the surface location, intercepting the targets either vertically or at
an angle.
    Well testing venting and flaring means venting and/or flaring of
natural gas at the time the production rate of a well is determined for
regulatory, commercial, or technical purposes. If well testing is
conducted immediately after well completion or workover, then it is
considered part of well completion or workover.

0
11. Table W-1A to Subpart W of Part 98 is revised to read as follows:

 Table A-1A of Subpart W--Default Whole Gas Emission Factors for Onshore
                  Petroleum and Natural Gas Production
------------------------------------------------------------------------
                                                        Emission factor
     Onshore petroleum and natural gas production          (scf/hour/
                                                           component)
------------------------------------------------------------------------
Eastern U.S.
Population Emission Factors--All Components, Gas Service 1
------------------------------------------------------------------------
    Valve............................................              0.640
    Connector........................................              0.083
    Open-ended Line..................................               1.46
    Pressure Relief Valve............................               0.97
    Low Continuous Bleed Pneumatic Device Vents \2\..               1.39
    High Continuous Bleed Pneumatic Device Vents \2\.               37.3
    Intermittent Bleed Pneumatic Device Vents \2\....               13.5
    Pneumatic Pumps \3\..............................               10.3
------------------------------------------------------------------------

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