distribution segment of subpart W, and the sources for which leak
detection and measurement are required and those sources for which an
emission factor can be used.  Based on feedback received from industry,
there may be concerns that the emission factors developed at the
transmission-distribution transfer stations are not representative of
emissions at other above ground metering-regulating stations.  Although
we are not proposing changes to the approach for applying emission
factors to above ground metering-regulating stations in this action, we
are seeking comment on alternative approaches, or data that may be used,
for determining emissions factors for above ground metering-regulating
stations.  Based on comments received, EPA may consider future
amendments to the rule.

In a separate action, (76 FR 37300)  EPA is proposing to expand the
final BAMM provisions to cover all facilities subject to subpart W, and
allow reporters the option to use best available monitoring methods
(BAMM) for all of 2011 without being required to submit a request for
approval to the Administrator.  For natural gas distribution facilities
at transmission-distribution transfer stations, this would allow
facilities to estimate the number of equipment leaks and the equipment
sources themselves using BAMM as provided in the rule, along with the
total time the component was found leaking and operational, as outlined
in Equation W—30.  This emission factor could then be used for other
above ground metering-regulating stations within the facility boundary.

EPA is proposing to clarify the summation operator in W-30 to make it
mathematically correct.  This clarification includes amending x to be
the total number of each equipment leak source and adding Tp, which is
the total time the component p was found leaking and operational.  We
are proposing to revise the parameter GHGi.  For industry segments
listed in 98.230 (a)(4) and (a)(5), GHGi has been revised to 0.974 for
CH4 and 1.0 × 10-2 for CO2.  For industry segments listed in (a)(6) and
(a)(7), GHGi equals 1 for CH4 and 0 for CO2.  For industry segments
listed in (a)(8), GHGi equals 1 for CH4 and 1.1×10-2 CO2 (See Technical
Support Document Memo (TSD)in Docket ID EPA-HQ-OAR-2011-0512 for further
details).

Next we are proposing two amendments in 40 CFR 98.236(c)(15).  We are
proposing to amend the reporting requirements in 40 CFR
98.236(c)(15)(i)(C) to clarify that owners or operators must report CH4
emissions collectively by equipment type and CO2 emissions collectively
by equipment type.  The calculation methodologies in 40 CFR 98.233(q),
as finalized in the rule, require reporters to calculate CH4 emissions
and CO2 emissions separately per source with equipment leaks.  We are
proposing this amendment to clarify that applicable reporters must
report the CH4 emissions collectively by equipment type and CO2
emissions collectively by equipment type.  We are also proposing to
correct the reporting requirement in 40 CFR 98.236(c)(15)(ii)(A) to not
include onshore natural gas processing.  This source category is not
required to use population emission factors.  This amendment is
associated with the amendment to Equation W-31 in 40 CFR 98.233(r)
discussed in Calculating Greenhouse Gas Emissions.

Population Count and Emission Factors.  We are proposing several
amendments in 40 CFR 98.233(r).  First we are proposing to amend the
population emission factor definition in equation W-31 by replacing the
term “non-custody transfer city-gate” with above grade
“metering-regulating station” for the reason stated above in this
preamble.  We are also clarifying that the count in equation W-31
applies to the number of “meter/regulator runs” at all
“metering-regulating stations” combined.

We are also proposing to amend the term “count” in W-31 as follows
to elaborate and clarify how each industry segment should count the
total number of equipment/components.  In that same equation, we are
also proposing to revise the definition for GHGi by referring to 40 CFR
98.233(u) and deleting the composition specified for each industry
segment.

Next, EPA is proposing to amend 40 CFR 98.233(r)(2)(i) to  explicitly
state how meters and piping are to be counted.  Table 1-B of the 2010
final rule was developed using activity data from the 1996 EPA/Gas
Research Institute Study (1996 EPA/GRI Study), Methane Emissions from
the U.S. Natural Gas Industry.  For all major equipment that are not
specifically listed, the 1996 EPA/GRI Study categorized all components
at a well-pad under the meters/piping category.  Therefore, owners or
operators should use one count of meters/piping per well-pad.

Further, consistent with proposed amendments described above, EPA is
proposing to amend 40 CFR 98.233(r)(6)(ii) by referring to
“metering-regulating stations” in place of “city gate” and to
clarify that the emission factor for meter/regulator runs at all
metering-regulating stations in equation W-32 is based on leak detection
performed at “transmission-distribution transfer stations”.  EPA is
also amending 40 CFR 98.233(r)(6)(i) to clarify that below grade meters
and regulators apply to below grade “metering-regulation stations”.

Lastly, we are proposing revisions to equation W-32 that include
revisions to the definitions for EF, Es,i, and “Count” again to
clarify the terminology change away from “custody transfer” to above
ground “metering-regulating” stations.  We are also proposing the
inclusion of a conversion factor to convert to hourly emissions.
Consequently, we are proposing to amend the conversion in Equation W-32
in 40 CFR 98.233(r) so that the equation yields an EF in cubic feet per
meter per hour to be used in Equation W-31 for above ground
metering-regulating stations.  Finally, the summation operator has been
removed in Equation W-32 because Es,i represents annual volumetric GHGi
emissions at all T-D transfer stations, making the summation operator
redundant.

In addition to the proposed calculation amendments described above, we
are also proposing to replace the term “field” with “sub-basin
category” in the reporting for onshore production, consistent with the
proposed change to sub-basin calculation and reporting.

Volumetric Emissions.  We are proposing to amend 40 CFR 98.233(t) to
clarify that reporters should use actual temperature and pressure and
adjust to standard conditions.  The phrase “by converting actual
temperature and pressure of natural gas emissions to standard
temperature and pressure of natural gas” was deleted because it is
redundant.

GHG Volumetric Emissions.  We are proposing to amend 40 CFR 98.233(u) to
include 95 percent methane/1 percent CO2 default gas composition for the
natural gas transmissions industry segment, along with the LNG storage
and underground storage industry segments.  Again, as described above,
EPA agrees that a default composition of  95 percent methane and 1
percent CO2 is appropriate because the composition of natural gas is
monitored consistently and regulated by FERC.

We are also proposing to strike the reference to the term “field” in
40 CFR 98.233(u) and replace with “sub-basin category” for the
reasons outlined in Section II.C.  of this preamble (Sub-Basin Category
Reporting for Onshore Petroleum and Natural Gas Production).

We are also proposing to clarify that the GHG mole fraction that is
determined without using a continuous gas analyzer may be determined
using an annual average instead of the most recent gas composition based
on available analysis in a sub-basin entity.

GHG Mass Emissions.  We are proposing to clarify in the definitions to
the equation W-36 that the equation applies to N2O emissions as well.
N2O emissions are calculated from stationary combustion and flares, and
the proposed edit is necessary to convert the mass emissions of N2O to
carbon dioxide equivalents of gas.  EOR injection pump blowdown.  We are
proposing to clarify in the equation that only CO2 emissions are
calculated.  The variables Massc,i has been changed to Massc,CO2, and
GHGi has been changed to GHGCO2.

Onshore Production and Distribution Combustion Emissions.  In a previous
action, EPA proposed several revisions to 40 CFR 98.233(z) including
corrections to Equations W-39 and 40.  In this action, we are proposing
additional amendments to clarify when owners or operators of onshore
production and distribution facilities must use the methods in 40 CFR
subpart C to calculate combustion-related emissions and when they must
use the methods in 40 CFR 98.233(z) to calculate combustion-related
emissions.  We are proposing to clarify that facilities using subpart C
to calculate emissions are not limited to the use of tier 1, but rather
may use any tier.  Regardless of the tier used, the facility must follow
the corresponding calculation, monitoring and reporting requirements of
that tier.

We are also proposing to amend the requirements for units combusting
field gas or process vent gas.  The 2010 final rule required the use of
a continuous flow meter, if present.  Use of a continuous flow meter
would have necessitated calibration requirements per 40 CFR 98.3(i).
These calibration requirements were disproportionately burdensome for
these relatively small disperse units, particularly given that
facilities that currently do not have a flow meter in place could use
company records.  In this action, we are proposing to amend the
requirements to allow the use of company records for this equipment.

Onshore Production and Distribution Equipment Threshold for Internal
Combustion Equipment.  In letters dating January 31, 2011 and March 5,
2011 from API and AGA, respectively EPA received petitions to reconsider
an exemption for internal combustion engines similar to that which was
in the final subpart W rule (75 FR 74458, November 30, 2010) for
external combustion engines.  These requests from the onshore petroleum
and natural gas production and natural gas distribution reporters were
to provide respite for reporting of emissions from internal combustion
equipment that are brought in temporarily for maintenance and
construction.  Some reporters have requested complete exemption such
that combustion equipment that fall below a specific threshold would be
exempt from reporting.

EPA considered, but decided not to propose an exemption for reporting
for internal combustion engines.  EPA decided not to propose amendments
because data currently are not available to sufficiently characterize
these upstream emissions.  For example, the volume of fuel consumed,
especially at wellhead natural gas compressors, is not being monitored
and only limited data, voluntarily reported, are available through the
Energy Information Administration.

Although EPA has decided not to propose a threshold due to lack of
availability of a comprehensive data source from which to develop
policy, we acknowledge that there is potentially small internal
combustion equipment outside of compressors.  In considering a potential
equipment threshold for non-compressor internal combustion engines, EPA
collected and reviewed data on the size ranges of small, portable
internal combustion engines that may be brought to a wellhead for
periodic maintenance and construction.  Such equipment would include,
for example, electric generators for arc welding, electric generators
powering portable flood-lighting, and electrical generators or gasoline
engines powering air compressors (for sand blasting or pneumatic tools).
 For lighting, the industrial generators were almost exclusively below
12 horsepower (hp), with the highest found being 13.9 hp.  For welding
machines, we assumed that they would use standard portable generators,
since specific information on these types of machines was scarce.  Most
portable industrial generators are rated between 15-40 hp, with the
largest one found being 67 hp. EPA determined that 130 horsepower
(double the largest size found) would exclude virtually all small
portable or stationary internal combustion engines, but is much smaller
than the 5 mmBtu/hour exclusion for external combustion sources and
equates to about 1 mmBtu/hour.  EPA is seeking comments on whether a 1
mmBtu/ hour equipment threshold for internal combustion engines that are
not driven by natural gas is reasonable.  We also seek comment on
EPA’s position that combustion-related emissions at compressors should
not be excluded from reporting, regardless of size and where EPA can
find reliable estimates of natural gas consumption.

EPA is proposing to clarify the summation operator in Equation W-39 to
make it mathematically correct.  In addition, EPA is proposing to
clarify in Equation W-40 that N2O mass emissions are calculated by
changing the parameter N2O to Masss,N2O.

 In specific, EPA is soliciting comments  as to why emissions from
specific internal combustion related equipment should not be reported
including the size of the equipment that should be excluded along with
supporting data.

Monitoring and QA/QC Requirements.  We are proposing several amendments
to the monitoring and QA/QC requirements in 40 CFR 98.234.

First, we are proposing to amend the language in 40 CFR 98.234(a)(1) by
first removing and reserving the text in 40 CFR 98.234(a)(4) and
combining it with 40 CFR 98.234(a)(1),   thus resulting in one
consolidated paragraph.  We are also proposing to state explicitly that
video recordings are not required under subpart W.  As noted in the
Response to Comments to the 2010 final rule, EPA did not intend to
require retention of a video recording of the leak detection using
optical gas imaging instruments for reporting to EPA under subpart W of
the greenhouse gas reporting rule.  However, some of the references to
the Alternate Work Practice suggested that EPA intended that facilities
retain these records onsite.

Next, we are proposing to amend the language in 40 CFR 98.234(a)(2) to
state that Method 21 compliant instruments may be used to monitor
inaccessible emissions sources.  This amendment increases flexibility in
monitoring requirements and reduces the burden on the industry, without
compromising data quality.

Further, based on questions raised by industry, we are proposing to
amend 40 CFR 98.234(a)(5) by revising the acoustic leak detection device
provisions to use a different model of acoustic detector, one that does
not have a through-valve leakage correlation, thereby allowing leakage
to be measured by other methods if a leak is found.

However, EPA is proposing to clarify that not all types of acoustic
detectors are allowed.  In particular the “gun” type instrument that
is aimed at the equipment from a distance to detect the acoustic signal
of leakage is not an allowable instrument.  This type cannot distinguish
between external leakage to the atmosphere from internal, through-valve
leakage, which is the objective for specifying this device.  EPA is
proposing to further specify that the “stethoscope” type acoustic
detector that senses through valve leakage when put in contact with the
valve body, but does not have the leakage estimating correlations, may
be used.

We are also proposing editorial revisions in 40 CFR 98.234(c) for
calibrated bagging to specify that those using the calibrated bag for
sampling, must ensure that the emissions must be at a temperature below
that which the bag manufacturer specifies for safe handling.

Data Reporting Requirements.  We are proposing several amendments and
clarifications throughout 40 CFR 98.236 in order to address questions
received about how data should be reported.  Many of the data reporting
requirements were lacking clarity with respect to the level of
reporting.  Based on the questions received, as well as EPA’s
experience gained in developing the electronic GHG reporting tool
(e-GGRT), which provided EPA a better understanding of the clarity
necessary in the data reporting requirements, EPA is proposing the
following changes.

In cases where technical amendments were already proposed for individual
emissions sources above, EPA has described the corresponding proposed
amendments to the reporting requirements along with the technical
amendments.  This section outlines any remaining proposed amendments to
the data reporting requirements not already described above.

First we are proposing to clarify the data reporting requirements for
offshore petroleum and natural gas production facilities in 40 CFR
98.236(b).  Specifically, the 2010 final rule was not clear in terms of
which gases were required to be reported and the data elements for
reporting.  Consistent with the calculation requirements, we are
proposing to clarify that facilities containing the offshore petroleum
and natural gas production segment would be required to 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 the emissions
source types listed in the most recent BOEMRE study.

Next, in the introductory paragraph for 40 CFR 98.236(c) we are
proposing to clarify that vented emissions should be reported separately
from flared emissions.  We have specified which source types require
separate calculation of flared emissions, but EPA is taking comment on
whether any source types that have process gas routed to flares were
excluded from having specific reporting requirements established for
flares.

We are proposing to make changes to the data reporting requirements for
local distribution companies, consistent with the proposed amendments to
40 CFR 98.230(a)(8).  Specifically, we are proposing to replace
“custody transfer” with “transmission-distribution transfer”
station and replace “non-custody transfer” with “above ground
metering-regulating station.”  In addition, we are proposing to
require the reporting of counts and emissions of both above grade and
below grade stations for each of metering-regulating stations and
“transmission-distribution transfer stations”.

Finally, EPA seeks some basic information on average API gravity of the
hydrocarbon liquids produced, gas to oil ratio, and low pressure
separator pressure per sub-basin entity.  It is EPA’s understanding
that his information is already known to reporters.  EPA will use these
facility sub-basin characteristics to characterize other emissions
sources across different sub-basins.”

Records that must be retained.  EPA is proposing to add the following
recordkeeping requirement: “The records required under §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.”  While EPA believes this
requirement is already included in 40 CFR 98.3(g)(2)(i) where the
records for “The GHG emissions calculations and methods used”
requirement is made, EPA believes that adding this statement to the
recordkeeping requirements in subpart W will provide facilities with
further clarity on the records they are required to keep.  This
clarification is intended to make clear that stating company records,
engineering estimation, or best available information were used is not
enough to satisfy the requirement in 40 CFR 98.3(g)(2)(i).  This
requirement is intended to parallel a similar requirement for subpart C
specified in 40 CFR 98.34(f) and referenced in 40 CFR 98.37.

Definitions.  We are proposing to amend, and in some cases, add
definitions to 40 CFR 98.238 to further clarify rule requirements.

Associated With a Single Well-Pad.  We are proposing to add a definition
for “associated with a single well-pad” to clearly demarcate the
boundary of onshore production.  EPA proposes that the association be
defined by the hydrocarbon stream from a single well-pad.  The
association with a single well-pad ends where the stream from a single
well-pad is combined with streams from one or more additional single
well-pads, where the point of combination is located off that single
well-pad.  In addition, we are stating that this definition does not
include storage and condensate tanks that are located downstream of the
point of combination.  For gas contained in crude oil or condensate
flowing under pressure off a single well-pad to a gas-liquid separator
or tank, or comingled with flow from other well-pads, 40 CFR 98.233(j)
requires reporting of the gas content that may be released from the oil
or condensate in an atmospheric pressure fixed roof storage tank.  We
have determined that the conditions of the pressurized oil or condensate
(i.e. gravity, pressure, temperature, flow rate) are commonly known by
the well owner/operator, and the amount of gas that may be released from
the oil or condensate with a pressure reduction can be determined most
appropriately by the well owner/operator.

Distribution Pipeline.  EPA is proposing to include a definition for
distribution pipelines to add clarity on its intent on coverage for the
natural gas distribution industry segment.  We are proposing to use a
widely accepted definition for distribution pipelines, specifically,
those designated as such by the Pipeline and Hazardous Material Safety
Administration (PHMSA).

Facility With Respect to Natural Gas Distribution.  EPA is proposing to
revise the definition for natural gas distribution by replacing the term
“metering stations, and regulating” with the term
“metering-regulating”.  EPA is proposing to include a definition for
the term above ground “metering-regulating station” to clarify where
leak detection and monitoring is required in the 2010 final rule.

Farm Taps.  EPA is proposing to revise the definition for farm taps in
40 CFR 98.238 by striking the unnecessary phrase “The gas may or may
not be metered, but always does not pass through a city gate station.”

Flare.  We are proposing to add a definition of flare specific for
subpart W to address questions received during implementation about what
constitutes a flare.  The proposed definition clarifies that a flare may
be either at ground level or elevated and uses an open or enclosed flame
to combust waste gases without energy recovery.  This definition for
subpart W is intended to be inclusive of devices that combust waste
gases without energy recovery.  This broad, all-inclusive definition for
Subpart W is necessitated by the wide variety of waste gas combustion
devices that are or may be used in the different segments of Subpart W,
all for the same purpose and having the same effect of combustion
emissions of hydrocarbon gases.

Forced Extraction of Natural Gas Liquids.  We are proposing to add a
definition for forced extraction to restrict it to specific processes.
EPA determined that it was necessary to develop this more precise
definition because many industry questions pointed to the confusion
between processing plants, gas gathering stations and wellheads, where
similar equipment and processes are conducted as at some, but not all,
processing plants that EPA determined should be subject to this rule.
Those similar processes.  These processes in and of themselves do not
make a facility a “processing plant.” Furthermore, the Oil & Gas
Journal annual survey of gas processing plants is primarily focused on
those that fractionate, leaving out known, large gas plants that
separate NGLs or condition gas, but do not fractionate, and are clearly
not gathering booster stations.  The key principle that EPA is
attempting to clarify through this definition is the separation of
heavier hydrocarbons in the vapor phase of natural gas delivered to a
plant, excluding the simple gravity separation of liquids entrained in
the gas.  This principle is “forced extraction”, as defined here.

Horizontal Well.  With the change from field level reporting to
sub-basin category, EPA is proposing to add a distinction for
calculating emissions from horizontal wells and vertical wells.  We are
proposing to define horizontal well to mean 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.

ith >0.1 millidarcy permeability, and unconventional with ≤0.1
millidarcy permeability shale, coal seam, and other tight reservoir
rock, all of which are unconventional with ≤0.1 millidarcy
permeability . Unconventional wells producing from formations
categorized in two or more types are considered shale for a combination
of “shale and coal”, “shale and other tight”, or “shale, coal
and other tight”; and are considered as coal for combinations of
“coal and other tight".

Transmission-Distribution (TD) transfer station.  EPA is proposing to
add a definition for Transmission Distribution (TD) transfer station to
define what was previously termed “custody transfer” in the final
rule.  It was not EPA’s intent for the term “custody transfer” to
be defined in the context of ownership of gas transfer.  EPA believes
the new definition may be universally applied to designate which
“metering-regulating stations” are classified as
“transmission-distribution transfer stations”.  All covered stations
in the distribution segment will be collectively referred to as
“metering-regulation stations” but the subset that require leak
detection are “transmission-distribution transfer stations.” EPA was
notified of concerns from industry that defining a transmission
distribution transfer station without a threshold would include numerous
small TD transfer stations that would otherwise not have been required
to perform leak surveys.  EPA has not included any thresholds in the
proposal but we are taking comment on what an appropriate threshold
would be to exclude these smaller transfer stations.  Such a threshold
should exempt stations with low throughputs or low emissions.  Any
threshold should be readily verifiable and be readily applied to all
stations.  Potential options for a threshold include using the inlet
pressure, the design or actual flow rate of the station, or other
parameters directly related to the emissions from the station.  Any
suggested changes should include a discussion of how many stations would
be exempted from leak detection and how many would still require leak
detection.  Such an exemption would not preclude a station from
reporting, it would only mean that leak detection is not required at
that station.  The stations that fall below the select threshold would
still be included for evaluation against the 25,000mtCO2e threshold
through the application of an emissions factor.  Natural gas
distribution facilities that do not have any TD transfer stations above
the threshold, would use a factor to determine their emissions and
compare those emissions against the 25,000 mtCO2e threshold.

Transmission Pipeline.  We are proposing to add a definition for
transmission pipeline.  Transmission pipelines are clearly designated as
such by the Federal Energy Regulatory Commission for interstate
transmission pipelines, individual States for intrastate transmission
pipelines, and the Hinshaw exemption under the Natural Gas Act for
Hinshaw transmission pipelines.  We propose to use this existing
mechanism to clearly demarcate transmission pipelines from distribution
and gathering pipelines.  Finally, we believe that equipment located on
designated transmission pipelines that are subject to monitoring under
subpart W are easily identifiable by facility owners or operators.

Tubing Systems.  Based on a question received in the early phases of
implementation, we are proposing to clarify that the exclusion for
piping equal to or less than one half inch diameter applies to the
nominal pipe size (NPS).

Vertical Well.  With the change from field level reporting to sub-basin
category, EPA is proposing to add a distinction for calculating
emissions from horizontal wells and vertical wells.  EPA proposes that a
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.  We are proposing to clarify that well
testing venting and flaring means venting and/or  flaring of natural gas
at the time the production rate of a well is determined (i.e., the well
testing) through a choke (an orifice restriction).  If well testing is
conducted immediately after well completion or workover we are proposing
to clarify that it is considered part of the well completion or
workover.

III.  Statutory and Executive Order Review

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 proposes to simplify the existing reporting methodologies in
subpart W and clarify monitoring methodologies and data reporting
requirements.  In many cases, the proposed amendments to the reporting
requirements could potentially reduce the reporting burden by making the
reporting requirements conform more closely to current industry
practices.  In addition, while the proposed modification to one of the
monitoring methodologies is not expected to increase compliance cost, it
would require the reporting of information not contained in the
information collection requirements to 40 CFR 98 subpart W.  Therefore,
the proposed 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 2376.03.

The proposed amendments to subpart I would carry out the Agency’s
intent to require reporting of emissions of all fluorocarbons used as
heat transfer fluids in the electronics manufacturing industry.  This
was the intent of the subpart I reporting requirements for HTFs
finalized in December 2010 (75 FR 74774), and this intent was reflected
in the Information Collection Request (ICR) prepared during that
rulemaking.  Thus, the proposed amendments will not increase EPA or
industry burden beyond that estimated in the ICR.

The Office of Management and Budget (OMB) has previously approved the
information collection requirements contained in the existing
regulations, 40 CFR 98 subpart W (75 FR 74458), and 40 CFR part 98
subpart I (75 FR 74774),  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.

C.  Regulatory Flexibility Act

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 proposed rule 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 today’s proposed rule 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 USC 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.

This action includes proposed amendments to provisions in those rules
that could result in reduced burden on reporters.  In some cases, EPA is
proposing to increase flexibility in the selection of methods use for
calculating GHG’s, and is also proposing to revise certain methods
that may result in greater conformance to current industry practices.
In addition,  in this action, EPA is proposing to revise specific
provisions to provide clarity on what is to be reported.  Further, in
this action, EPA is also proposing amendments to clarify the Agency’s
intent.  These proposed revisions could overall reduce burden on
reporters while maintaining the data quality of the information being
reported to EPA.  As part of the process of finalization of the subpart
W and subpart I rules, EPA undertook specific steps to evaluate the
effect of those final rules on small entities. Based on the proposed
amendments to the subpart W and subpart I provisions, burden will stay
the same or decrease, therefore EPA’s determination finding of no
significant economic impact on a substantial number of small entities
has not changed.

D.  Unfunded Mandates Reform Act

The proposed 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 proposed rule amendments are not subject to the
requirements of section 202 and 205 of the UMRA.  This rule is also not
subject to the requirements of section 203 of UMRA because it contains
no regulatory requirements that might significantly or uniquely affect
small governments.

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.  Further, the
proposed amendments will not impose any new requirements that are not
currently required for 40 CFR part 98, and the rule amendments would not
unfairly apply to 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 proposed 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.

In the spirit of Executive Order 13132, and consistent with EPA policy
to promote communications between EPA and State and local governments,
EPA specifically solicits comment on this proposed action from State and
local officials.

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 and subpart I, 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.  The
proposed rule amendments in this action do not impose any significant
changes to the current reporting requirements contained in 40 CFR part
98 subpart W and 40 CFR part 98 subpart I.  And in several cases, the
proposed 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 tribal officials during the development of the original
actions.  A summary of the concerns raised during the 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). EPA
specifically solicits additional comment on this proposed action from
tribal officials.

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 No. 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 proposed rulemaking does not involve technical standards.
Therefore, EPA is not considering 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 proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not affect
the level of protection provided to human health or the environment
because it is a rule addressing information collection and reporting
procedures.

List of Subjects in 40 CFR Part 98

Environmental protection, Administrative practice and procedure,
Greenhouse gases, Incorporation by reference, Suppliers, Reporting and
recordkeeping requirements.

Dated:

Lisa P. Jackson,

Administrator.

For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is proposed to be amended as follows:

PART 98—[AMENDED]

1.  The authority citation for part 98 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart A-[Amended]

2.  Section 98.1 is amended by adding paragraph (c) to read as follows:

§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 §98.238 of
this part.

3.  Section 98.6 is amended by revising the definitions for
“Continuous bleed” and “Intermittent bleed pneumatic devices” to
read as follows:

§98.6  Definitions.

*	*	*	*	*

Continuous bleed means a continuous flow of pneumatic supply 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.

*	*	*	*	*

4.  Section 98.7 is amended by removing paragraph (q).

Subpart I—[Amended]

5.  Section 98.90 is amended by revising paragraph (a)(5) to read as
follows:

§98.90 Definition of the source category.

(a)	*	*	*

(5)  Any electronics manufacturing production process in which
fluorinated heat transfer fluids are used to cool process equipment, to
control temperature during device testing, to clean substrate surfaces
and other parts, and for soldering (e.g., vapor phase reflow).

6.  Section 98.92 is amended by revising paragraph (a) introductory text
and paragraph (a)(5) to read as follows:

§98.92 GHGs to report.

(a)  You must report emissions of fluorinated GHGs (as defined in
§98.6), N2O, and fluorinated heat transfer fluids (as defined in
§98.98).  The fluorinated GHGs and fluorinated heat transfer fluids
that are emitted from electronics manufacturing production processes
include, but are not limited to, those listed in Table I–2 to this
subpart.  You must individually report, as appropriate:

*	*	*	*	*

(5)  Emissions of fluorinated heat transfer fluids.

*	*	*	*	*

7.  Section 98.93 is amended by revising paragraph (h) introductory text
and the definition of “EHi” in Equation I-16 to read as follows.

§98.93 Calculating GHG Emissions.

*	*	*	*	*

(h)  If you use fluorinated heat transfer fluids, you must report the
annual emissions of fluorinated heat transfer fluids using the mass
balance approach described in Equation I-16 of this subpart.

*	*	*	*	*

EHi	=	Emissions of fluorinated heat transfer fluids i, (metric
tons/year).

*	*	*	*	*

8.  Section 98.94 is amended by revising paragraph (h) introductory text
to read as follows:

§98.94 Monitoring and QA/QC requirements.

*	*	*	*	*

(h)  You must adhere to the QA/QC procedures of this paragraph (h) when
calculating annual gas consumption for each fluorinated GHG and N2O used
at your facility and emissions from the use of fluorinated heat transfer
fluids.

*	*	*	*	*

9.  Section 98.96 is amended by revising paragraph (r) to read as
follows:

§98.96 Data Reporting requirements

*	*	*	*	*

(r)  For heat transfer fluid emissions, inputs to the heat transfer
fluid mass balance equation, Equation I–16 of this subpart, for each
fluorinated heat transfer fluid used.

*	*	*	*	*

10.  Section 98.98 is amended by removing the definition of “Heat
transfer fluids” and adding the definition of “Fluorinated heat
transfer fluids” in alphabetical order to read as follows:

§98.98 Definitions.

*	*	*	*	*

Fluorinated heat transfer fluids means fluorinated GHGs used for
temperature control, device testing, cleaning substrate surfaces and
other parts, and soldering in certain types of electronics manufacturing
production processes.  For fluorinated heat transfer fluids under this
subpart I, the lower vapor pressure limit of 1 mm of Hg in absolute at
25 degrees C in the definition of Fluorinated greenhouse gas in 40 CFR
98.6 shall not apply.  Fluorinated heat transfer fluids used in the
electronics manufacturing sector include, but are not limited to,
perfluoropolyethers, perfluoroalkanes, perfluoroethers, tertiary
perfluoroamines, and perfluorocyclic ethers.

*	*	*	*	*

11.  Table I–2 to Subpart I is amended by revising the title and the
second column heading to read as follows:

Table I-2 to Subpart I of Part 98—Examples of Fluorinated GHGs and
Fluorinated Heat Transfer Fluids Used by the Electronics Industry

Product Type	Fluorinated GHGs and Fluorinated Heat Transfer Fluids Used
During Manufacture

Electronics	CF4, C2F6, C3F8, c-C4F8, c-C4F8O, C4F6, C5F8, CHF3, CH2F2,
NF3, SF6, and HTFs(CF3-(O-CF(CF3)-CF2)n-(O-CF2)m-O-CF3, CnF2n+2,
CnF2n+1(O)CmF2m+1, CnF2nO, (CnF2n+1)3N)

Subpart W—[Amended]

12.  Section 98.230 is amended by revising paragraphs (a)(2), (a)(3),
(a)(4), and (a)(8) to read as follows:

§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.

*	*	*	*	*

13.  Section 98.232 is amended by:

a.  Revising paragraph (c) introductory text and paragraph (c)(22).

b.  Revising paragraph (e) introductory text.

c.  Revising paragraph (f) introductory text.

d.  Revising paragraph (g) introductory text.

e.  Revising paragraph (h) introductory text.

f.  Revising paragraph (i) introductory text and paragraph (i)(1).

g.  Redesignating paragraphs (i)(2) through (i)(6) as paragraphs (i)(3)
through (i)(7), respectively.

h.  Revising newly designated paragraphs (i)(3) and (i)(4).

i.  Adding new paragraph (i)(2).

j.  Removing and reserving paragraph (j).

k.  Revising paragraph (k).

The revisions read as follows:

§98.232  GHGs to report.

*	*	*	*	*

(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 §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 §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.

*	*	*	*	*

(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.

*	*	*	*	*

(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.

14.  Section 98.233 is amended by:

In paragraph (a), revising Equation W-1 and the definitions of
“Count” and “GHGi” in Equation W-1; and adding the definition of
“T” in Equation W-1.

Adding paragraph (a)(3).

In paragraph (c), revising Equation W-2 and the definition of
“GHGi”; and adding the definition of “T” in Equation W-2.

Revising paragraphs (d) introductory text and (d)(1).

oving the definition of “α” in Equation W-4.

Revising paragraph (e)(1)(vii).

Revising the definition of “1000” in Equation W-5 of paragraph
(e)(2).

Revising paragraph (e)(6).

Revising paragraphs (f) introductory text, (f)(1) introductory text, and
the definitions of Equation W-7 in paragraph (f)(1).

Revising paragraphs (f)(1)(i)(A) through (f)(1)(i)(C).

In paragraph (f)(2), revising Equation W-8 and the definitions of
Equation W-8.

Removing paragraphs (f)(2)(i) and (f)(2)(ii).

In paragraph (f)(3), revising Equation W-9 and the definitions of
Equation W-9.

Removing paragraphs (f)(3)(i) and (f)(3)(ii).

In paragraph (g), revising Equation W-10 and the definitions of Equation
W-10.

Revising paragraphs (g)(1) introductory text and (g)(1)(i) introductory
text.

Removing paragraphs (g)(1)(i)(A) through (g)(1)(i)(D).

In paragraph (g)(1)(ii), revising the paragraph (g)(1)(ii) introductory
text; redesignating Equation W-11 as Equation W-11A and redesignating
Equation W-12 as Equation W-11B; and adding Equation W-11C.

Redesignating paragraphs (g)(1)(ii)(A) through (g)(1)(ii)(B) as
paragraphs (g)(1)(iii) through (g)(1)(v) and revising new paragraphs
(g)(1)(iii) through (g)(1)(v).

Removing paragraph (g)(1)(ii)(D).

Revising paragraph (g)(3) introductory text and paragraph (g)(5)
introductory text.

In paragraph (h), revising the paragraph (h) introductory text and the
revising the definitions of “Nwo”, “f”, “Vp” and “Tp” in
Equation W-13.

Revising paragraph (i) introductory text and paragraphs (i)(1) and
(i)(2).

In paragraph (i)(3), revising the paragraph (i)(3) introductory text;
redesignating Equation W-14 as Equation W-14A; revising the definition
of “N” in newly redesignated Equation W-14A; and adding Equation
W-14B.

Revising paragraph (i)(5).

Revising paragraph (j)(1)(vii)(B), (j)(1)(vii)(C), and (j)(3)(i).

Revising paragraphs (k)(1) and (k)(2)(i).

Revising paragraph (m)(1).

Revising paragraph (n)(2)(ii) and (n)(2)(iii), and in paragraph (n)(4),
revising equation W-21 and the definition for “Yj”.

Redesignating paragraph (n)(9) as paragraph (n)(10) and adding new
paragraphs (n)(9) and (n)(11).

In paragraph (o)(6), revising the definition of “MTm” in Equation
W-24.

In paragraph (p)(7)(i), revising the definition of “MTm” in Equation
W-28.

In paragraph (q), revising equation W-30 and the definitions for
“x”, “EF”, “GHGi”, “Tp”, and revising paragraph (q)(8).

In paragraph (r), revising the definitions of “Counts”, “EFs”,
and “GHGi” in Equation W-31.

Revising paragraphs (r)(2)(i)(A), (r)(6)(i), (r)(6)(ii) introductory
text, Equation W-32, and the definitions of Equation W-32.

Revising paragraphs (t) introductory text, (t)(1) introductory text, and
(t)(2) introductory text.

Revising paragraph (u) introductory text and paragraph (u)(2).

In paragraph (v), revising the paragraph (v) introductory text and the
definitions of “Masss,i”, “Es,i”, and “(i” in Equation W-36.

Revising paragraphs (z) introductory text, (z)(1) introductory text,
(z)(2) introductory text, (z)(2)(i), and (z)(2)(ii).

Adding paragraphs (z)(1)(i) and (z)(1)(ii).

The revisions read as follows:

§98.233 Calculating GHG emissions.

(a) *	*	*

 	(Eq. W-1)

*	*	*	*	*

Count	= 	Total number of continuous high bleed, continuous low bleed, or
intermittent bleed natural gas pneumatic devices of each type as
determined in paragraph (a)(1) and (a)(2) of this section.

*	*	*	*	*

GHGi 	= 	For onshore petroleum and natural gas production facilities,
onshore natural gas transmission compression, and underground natural
gas storage, concentration of GHGi, CH4, or CO2, in natural gas as
defined in paragraph (u)(2)(i) of this section.

*	*	*	*	*

T	=	Total number of hours in the operating year the devices were
operational.

*	*	*	*	*

(3)  For all industry segments, determine the type of pneumatic device
using engineering estimates based on best available information.

*	*	*	*	*

(c) *	*	*

 	(Eq. W-2)

*	*	*	*	*

GHGi 	= 	Concentration of GHGi, CH4, or CO2, in produced natural gas as
defined in paragraph (u)(2)(i) of this section.

*	*	*	*	*

T 	= 	Total number of hours in the operating year the pumps were
operational.

*	*	*	*	*

(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).  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.

*	*	*	*	*

(3)  *	*	*

 	(Eq. W-4)

*	*	*	*	*

(e)  *	*	*

(1)  *	*	*

(vii)  Use of stripping gas.

*	*	*	*	*

(2)

*	*	*	*	*

1000 	= 	Conversion of EFi in thousand standard cubic feet to cubic
feet.

*	*	*	*	*

(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)  Well venting for liquids unloadings.  Calculate CO2 and CH4
emissions from  well venting for liquids unloading using one of the
calculation methodologies described in paragraphs (f)(1), (f)(2), or
(f)(3) of this section.

(1)  Calculation Methodology 1.  For one well of each unique well tubing
diameter grouping and pressure grouping in each sub-basin category (see
§98.238 for the definitions of tubing diameter grouping, pressure
grouping, 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 §98.234(b).  Calculate
emissions from well venting for liquids unloading using Equation W-7 of
this section.

*	*	*	*	*

Ea,n	=	Annual natural gas emissions for wells of the same tubing
diameter grouping and pressure grouping at actual conditions in cubic
feet.

Th,t	=	Cumulative amount of time in hours of venting from all wells of
the same tubing diameter grouping p and pressure grouping q during the
year.

FRh,t 	= 	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.

h	=	Total number of different tubing diameter groupings.

p	=	Tubing diameter grouping 1 through h.

t	=	Total number of pressure groupings.

q	=	Pressure grouping 1 through t.

*	*	*	*	*

(i)  *	*	*

(A)  The average flow rate per hour of venting is calculated for each
unique tubing diameter grouping and pressure grouping 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 grouping that have the same tubing diameter grouping, 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)  *	*	*

 	(Eq. W-8)

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 at the
facility.

0.37×10-3	=	{3.14 (pi)/4}/{14.7*144} (psia converted to pounds per
square feet).

CDP	=	Casing diameter for each well, p, in inches.

WDP	=	Well depth from the lowest packer to the bottom of the well, in
feet.

SPP	=	Shut-in pressure for each well, p, in pounds per square inch
atmosphere (psia).

VP	=	Number of vents per year per well, p.

SFRP 	=	Average sales flow rate of gas well, p, at standard conditions
in cubic feet per hour.  Use Equation W-33 to calculate the sales flow
rate at standard conditions.

HRQ,PW 	=	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.

ZQ,P	=	If HRQ,P is less than 1.0 then ZQ,P is equal to 0.  If HRQ,P is
greater than or equal to 1.0 then ZQ,P is equal to 1.

(3)  *	*	*

 	(Eq. W-9)

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 at the
facility.

0.37×10-3	=	{3.14 (pi)/4}/{14.7*144} (psia converted to pounds per
square feet).

TDP	=	Tubing diameter for each well, p,in inches.

WDP	=	Tubing depth to plunger bumper for each well, p,  in feet.

SPP	=	Sales line pressure for each well, p, in pounds per square inch
atmospheric (psia).

VP	=	Number of vents per year for each well, p.

SFRP 	= 	Average sales flow rate of each gas well, p, at standard
conditions in cubic feet per hour.  Use Equation W-33 to calculate the
sales flow rate at standard conditions.

HRQ,P 	=	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 sales line
pressure.

ZQ,P	=	If HRQ,P is less than 0.5 then ZQ,P is equal to 0.  If HRQ,P is
greater than or equal to 0.5 then ZQ,P is equal to 1.

*	*	*	*	*

(g)  *	*	*

  (Eq. W-10)

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
combination.

Tp 	= 	Cumulative amount of time in hours of each well (p) completion or
workover venting in a sub-basin and well type combination during the
reporting year.

FRM	=	Venting to 30-day production ratio 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 EnF is 0.  If injected gas is CO2, then EnF
is 0.

SGp	=	Volume of natural gas in cubic feet at standard conditions that
was recovered into a sales pipeline for well p as per paragraph (g)(3)
of this section.  If no gas was recovered for sales, SG is 0.

W	= 	Total number of wells completed or worked over using hydraulic
fracturing in a sub-basin and well type combination.

(1)  The average flow rate for gas well venting to the atmosphere or to
a flare during well completions and workovers from hydraulic fracturing
shall be determined using measurement(s) from either of the calculation
methodologies described in this paragraph (g)(1) of this section.  The
number of measurements shall be determined as follows:  One measurement
for less than or equal to 25 completions/workovers; two measurements for
26 to 50 completions/workovers; three measurements for 51 to 100
completions/workovers; four measurements for 101 to 250
completions/workovers; and five measurements for greater than 250
completions/workovers.

(i)  Calculation Methodology 1.  For well completion(s) in each gas
producing sub-basin category and well type (horizontal or vertical)
combination and for one 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 if used, to measure the backflow venting according to
methods set forth in §98.234(b).

(ii)  Calculation Methodology 2.  For one horizontal well completion and
one vertical well completion in each gas producing sub-basin category
and for one well horizontal workover and one 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 §98.234(b) to calculate the intermittent well flow
rate of gas during venting to the atmosphere or a flare.  Calculate
emissions using Equation W-11A of this section for subsonic flow or
Equation W-11B of this section for sonic flow.  Use Equation W-11C of
this section to determine whether 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:

 	(Eq. W-11A)

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 m2/(sec2 * K).

1.27*105	=	Conversion from m3/second to ft3/hour.

 	(Eq. W-11B)

Where:

FR	=	Average flow rate in cubic feet per hour, under sonic flow
conditions.

A	=	Cross sectional area of orifice (m2).

Tu	=	Upstream temperature (degrees Kelvin).

187.08	=	Constant with units of m2/(sec2 * K).

1.27*105	=	Conversion from m3/second to ft3/hour.

 	(Eq. W-11C)

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)  The emissions to 30-day production ratio is calculated using
Equation W-12 of this section.

 	(Eq. W-12)

Where:

FRM	=	Emissions to 30-day production ratio.

FRp	=	Measured flow rate from Calculation Methodology 1 or estimated
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.

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)  The flow rates 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 venting of each of
these wells.

(v)  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.

(2)  The volume of CO2 or N2 injected into the well reservoir during
energized hydraulic fractures will be measured using an appropriate
meter as described in §98.234(b) or using receipts of gas purchases
that are used for the energized fracture job.

(i)  Calculate gas volume at standard conditions using calculations in
paragraph (t) of this section.

(ii)  [Reserved]

(3)  The volume of recovered completion or workover gas sent to a sales
line will be measured using existing company records.  If data does not
exist on sales gas, then an appropriate meter as described in
§98.234(b) may be used.

*	*	*	*	*

(5)  Determine if the well completion or workover from hydraulic
fracturing recovered gas with purpose designed equipment that separates
saleable gas from the backflow, and sent this gas to a sales line (e.g.,
reduced emissions completions or workovers).

*	*	*	*	*

(h)  Gas well venting during completions and workovers without hydraulic
fracturing.  Calculate CH4, CO2 and N2O (when flared) emissions from
each gas well venting during well completions and workovers not
involving hydraulic fracturing using Equation W-13 of this section:

*	*	*	*	*

Nwo	=	Number of workovers per sub-basin not involving hydraulic
fracturing in the reporting year.

f	=	Total number of well completions without hydraulic fracturing in a
sub-basin category.

Vp	= 	Average daily gas production rate in 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 sales line.  For completed wells that have not
established a production rate, you may use the average flow rate from
the first 30 days of production. In the event that the well is completed
less than 30 days from the end of the calendar year, the first 30 days
of the production straddling the current and following calendar years
shall be used.

Tp	= 	Time each well completion without hydraulic fracturing, p, was
venting in hours during the year.*	*	*	*	*

(i)  Blowdown vent stacks.  Calculate CO2 and CH4 blowdown vent stack
emissions from depressurizing equipment to reduce system pressure for
planned or emergency shutdowns 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 total 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 total 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 type (including but not limited to
compressors, vessels, pipelines, headers, fractionators, and tanks).
Physical volumes smaller than 50 standard cubic feet are exempt from
reporting under paragraph (i) of this section.

(3)  Calculate the total annual venting emissions for each equipment
type using either Equation W-14A or W-14B of this section.

 	(Eq. W-14A)

Where:

*	*	*	*	*

Vv	=	Total volume of blowdown equipment chambers (including pipelines,
compressors and vessels) between isolation valves in cubic feet.

*	*	*	*	*

 		(Eq. W-14B)

Where:

Es,n 	= 	Annual natural gas venting emissions at standard conditions
from blowdowns in cubic feet.

N	= 	Number of repetitive blowdowns for each unique volume in calendar
year.

Vv	=	Total volume of blowdown equipment chamber (including pipelines,
compressors and vessels) between isolation valves in cubic feet for each
blowdown “i.”

C	=	Purge factor that is 1 if the equipment is not purged or zero if the
equipment is purged using non-GHG gases.

Ts  	=	Temperature at standard conditions (oF).

Ta  	=	Temperature at actual conditions in the blowdown equipment
chamber (oF) for each blowdown “i”.

Ps  	=	Absolute pressure at standard conditions (psia).

Pa,s,p  =	Absolute pressure at actual conditions in the blowdown
equipment chamber (psia) at the start of the blowdown “p”.

Pa,e,p  =	Absolute pressure at actual conditions in the blowdown
equipment chamber (psia) at the end of the blowdown “p”; 0 if
blowdown volume is purged using non-GHG gases.

*	*	*	*	*

(5)  Calculate total annual venting emissions for all blowdown vent
stacks by adding all standard volumetric and mass emissions determined
using Equations W-14A or W-14B and paragraph (i)(4) of this section.

(j)  *	*	*

(1)  *	*	*

(vii)  *	*	*

(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.

*	*	*	*	*

(3)  *	*	*

(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.

*	*	*	*	*

(k)  *	*	*

(1)  Monitor the tank vapor vent stack annually for emissions using an
optical gas imaging instrument according to methods set forth in
§98.234(a)(1) or by directly measuring the tank vent using a flow
meter, calibrated bag, or high volume sampler according to methods in
§98.234(b) through (d) for a duration of 5 minutes.  Or you may
annually monitor leakage through compressor scrubber dump valve(s) into
the tank using an acoustic leak detection device according to methods
set forth in §98.234(a)(5).

(2)  *	*	*

(i)  Use a meter, such as a turbine meter, calibrated bag, or high flow
sampler to estimate tank vapor volumes according to methods set forth in
§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 §98.233(k)(1) of this section to detect continuous
leakage, this serves as the measurement.

(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.

*	*	*	*	*

(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.

*	*	*	*	*

(n)  *	*	*

            (Eq. W-21)

*	*	*	*	*

Yj	=	Mole fraction of gas hydrocarbon constituents j (such as methane,
ethane, propane, butane, and pentanes-plus)

*	*	*	*	*

(9)  If you operate and maintain a CEMS that has both a CO2
concentration monitor and volumetric flow rate monitor, you must
calculate CO2 emissions for the flare 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).  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).

(10)  The flare emissions determined under paragraph (n) of this section
must be corrected for flare emissions calculated and reported under
other paragraphs of this section to avoid double counting of these
emissions.

(11)  If source types in §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.

*	*	*	*	*

(p)  *	*	*

(7)  *	*	*

(i)  *	*	*

*	*	*	*	*

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

*	*	*	*	*

(q)  *	*	*

*	*	*	*	*

 				(Eq. W-30)

*	*	*	*	*

x	=	Total number of each equipment leak source.

*	*	*	*	*

GHGi	=	For onshore natural gas processing facilities, concentration of
GHGi, CH4 or CO2, in the total hydrocarbon of the feed natural gas;
98.230(a)(4) and (a)(5),GHGi equals 0.974 for CH4 and 1.0 × 10-2 for
CO2; for facilities listed in §98.230(a)(6) and (a)(7), GHGi equals 1
for CH4 and 0 for CO2; and for facilities listed in §98.230(a)(8), GHGi
equals 1 for CH4 and 1.1×10-2 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 or the beginning of
the calendar year.  For the last leak detection survey in the calendar
year, assume that all leaking components continue to leak until the end
of the calendar year.

*	*	*	*	*

(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 leak 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 metering-regulating
stations that do not meet the definition of transmission-distribution
transfer stations are not required to perform component leak detection
under this section.

(r)  *	*	*

*	*	*	*	*

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 respective component for each emission
factor as described in paragraph (r)(6) of this section.

EFs	=	Population emission factor for the specific source, 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; for other
facilities listed in §98.230(a)(4) and (a)(5),GHGi equals 0.952 for CH4
and 1.0 × 10-2 for CO2; for facilities listed in §98.230(a)(6) and
(a)(7), GHGi equals 1 for CH4 and 0 for CO2; and for facilities listed
in §98.230(a)(8), GHGi equals 1 for CH4 and 1.1×10-2 CO2.

*	*	*	*	*

(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 (including below grade T-D
transfer stations); distribution mains; and distribution services, shall
use the appropriate default population emission factors listed in Table
W-7 of this subpart.

(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 paragraph (q)(8) of this section
and the count of meter/regulator runs located at above grade
transmission-distribution transfer stations.

 	(Eq. W-32)

Where:

EFi	=	Facility emission factor for a meter/regulator run 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 all equipment leak sources at all above grade TD transfer
stations, from paragraph (q) of this section.

Count	=	Total number of meter/regulator runs at all TD transfer
stations.

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.

*	*	*	*	*

(2)  Calculate GHG volumetric emissions at standard conditions using
actual GHG emissions temperature and pressure, and Equation W-34 of this
section.

*	*	*	*	*

(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 available analyses in each of
the sub-basin categories.

(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
§98.234(b).

(iii)  GHG mole fraction in transmission pipeline natural gas that
passes through the facility for onshore natural gas transmission
compression facilities.  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 underground natural gas
storage facilities.  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 LNG storage facilities.
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 LNG import and export
facilities.  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 at standard conditions by converting the GHG volumetric
emissions at standard conditions into mass emissions using Equation W-36
of this section.

*	*	*	*	*

Masss,i	=	GHG i (either CH4 , CO2, or N2O) mass emissions at standard
conditions in metric tons CO2e.

Es,i	=	GHG i (either CH4, CO2, or N2O) volumetric emissions at standard
conditions, in cubic feet.

	=	Density of GHG i. Use 0.0520 kg/ft3 for CO2 and N2O, and 0.0190
kg/ft3 for CH4 at 68°F and 14.7 psia or 0.0530 kg/ft3 for CO2 and N2O,
and 0.0193 kg/ft3 for CH4 at 60°F and 14.7 psia .

*	*	*	*	*

(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) 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 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 But 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 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
paragraph (u)(2)(i) of this section.

15.  Section 98.234 is amended by:

a.  Revising paragraphs (a)(1), (a)(2), and (a)(5).

b.  Removing and reserving paragraph (a)(4).

c.  Revising paragraph (c) introductory text and paragraph (d)(3).

§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, §60.18 of the Alternative work practice for monitoring
equipment leaks, §60.18(i)(1)(i); §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; §60.18(i)(2)(ii) and (iii) except the
gas chosen shall be methane, and §60.18(i)(2)(iv) and (v);
§60.18(i)(3); §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.
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 must be of sufficient size that the entire
emissions volume can be encompassed for measurement.

*	*	*	*	*

(d)  *	*	*

(3)  Estimate natural gas volumetric emissions at standard conditions
using calculations in §98.233(t).  Estimate CH4 and CO2 volumetric and
mass emissions from volumetric natural gas emissions using the
calculations in §98.233(u) and (v).

16.  Section 98.236 is amended by:

Revising paragraphs (a) introductory text and (a)(8).

Revising paragraph (b).

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).

Revising paragraphs (c)(4)(i)(H) and (C)(4)(i)(J); and adding paragraphs
(c)(4)(i)(K) and (c)(4)(i)(L).

Revising paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(C); and adding
paragraph (c)(4)(ii)(D).

Revising paragraph (c)(4)(iii)(B).

Revising paragraphs (c)(5) introductory text, (c)(5)(iii), and
(c)(5)(vi); and adding paragraph (c)(5)(vii).

Revising paragraphs (c)(6) introductory text, (c)(6)(i) introductory
text, (c)(6)(i)(B), (c)(6)(i)(D), (c)(6)(i)(G), and (c)(6)(i)(H); and
adding paragraph (c)(6)(ii)(I).

Revising paragraphs (c)(6)(ii)(B) and (c)(6)(ii)(D); and adding
paragraph (c)(6)(ii)(E).

Revising paragraphs (c)(7)(i) and (c)(7)(ii); and adding paragraphs
(c)(7)(iii).

Revising paragraphs (c)(8)(i) introductory text and (c)(8)(i)(J); and
adding paragraphs (c)(8)(i)(K) through (c)(8)(i)(M).

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).

Revising paragraphs (c)(8)(iii) introductory text and (c)(8)(iii)(F);
and adding paragraphs (c)(8)(iii)(G) and (c)(8)(iii)(H).

Adding paragraph (c)(8)(iv)(B).

Revising paragraphs (c)(9)(i) and (c)(9)(ii); and adding paragraph
(c)(9)(iii).

Revising paragraphs (c)(10) introductory text and (c)(10)(iv); and
adding paragraph (c)(10)(v).

Revising paragraph (c)(11) introductory text and (c)(11)(iii); and
adding paragraph (c)(11)(iv).

Revising paragraph (c)(12)(vi) and adding paragraphs (c)(12)(vii)
through (c)(12)(xi).

Revising paragraphs (c)(15)(i)(B) and (c)(15)(i)(C).

Revising paragraphs (c)(15)(ii)(A) through (c)(15)(ii)(C).

Revising paragraphs (c)(16)(i) through (c)(16)(iv), (c)(16)(vi), and
(c)(16)(xv).

Removing and reserving paragraph (c)(16)(v).

Adding paragraphs (c)(16)(xvi) through (c)(16)(xx).

Revising paragraph (c)(17)(v) and adding paragraph (c)(17)(vi).

Revising paragraph (c)(18) introductory text and paragraph (c)(18)(iii).

Revising paragraph (c)(19)(iii) and (c)(19)(vi).

Adding paragraph (e).

The revisions read as follows:

§98.236   Data Reporting Requirements .

*	*	*	*	*

(a)  Report annual emissions 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 the emissions
source types listed in the most recent BOEMRE study.

(c)  Report the information listed in this paragraph for each applicable
source type.  If a facility operates under more than one industry
segment, each piece of equipment should be reported under its 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
§98.233(d), annual average fraction of CO2 content in the vent from the
acid gas removal unit (refer to §98.233(d)(6)).

(iii)  For Calculation Methodology 3 of §98.233(d), annual average
volume fraction of CO2 content of natural gas into and out of the acid
gas removal unit (refer to §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.

(v)  Report annual CO2 emissions for the AGR unit, expressed in metric
tons CO2e.

(vi)  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)  A unique name or ID number for the glycol dehydrator.

(ii)  *	*	*

(B)  Which vent gas controls are used (refer to §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
a 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 a 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 (refer to Equations W-7, W-8
and W-9 of §98.233), report the following by each well tubing diameter
grouping and pressure grouping within each sub-basin category:

*	*	*	*	*

(iii)  Cumulative number of unloadings vented to the atmosphere.

*	*	*	*	*

(vi)  Report annual CO2 and CH4 emissions, expressed in metric tons CO2e
for each gas, for each tubing diameter and pressure grouping within each
sub-basin category.

(vii)  When using Calculation Methodology 1, casing diameter, depth and
pressure of each well selected to represent emissions in that tubing
size and pressure combination (refer to Equation W-7 of §98.233).

(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-10 of §98.233):

*	*	*	*	*

(B)  Average flow rate of the measured well completion venting in cubic
feet per hour (refer to Equation W-12 of §98.233).

*	*	*	*	*

(D)  Average flow rate of the measured well workover venting in cubic
feet per hour (refer to Equation W-12 of §98.233).

*	*	*	*	*

(G)  Report number of completions and number of workovers employing
reduced emissions completions and engineering estimate based on best
available data of the amount of gas recovered to sales.

(H)  Annual CO2 and CH4 emissions that resulted from venting gas
directly to the atmosphere, expressed in metric tons CO2e for each gas.

(I)  Annual CO2, CH4, and N2O emissions that resulted from flares,
expressed in metric tons CO2e for each gas.

*	*	*	*	*

(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)  *	*	*

(i)  Total number of blowdowns per unique volume type in calendar year.

(ii)  Annual CO2 and CH4 emissions, expressed in metric tons CO2e for
each gas, for each unique volume type, at each blowdown stack.

(iii)  A unique name or ID number for the blowdown vent stack.

(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
§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 each
wellhead gas-liquid separator or storage tank using Calculation
Methodology 1 or 2 of §98.233(j).

(K)  Annual CO2 and CH4 gas quantities that were recovered, expressed in
metric tons CO2e for each gas, for each wellhead gas-liquid separator or
storage tank using Calculation Methodology 1 or 2 of §98.233(j).

(L)  Annual CO2, CH4, and N2O emissions that resulted from flaring gas,
expressed in metric tons CO2e for each gas, for each wellhead gas-liquid
separator or storage tank using  Calculation Methodology 1 or 2 of
§98.233(j).

(M)  A unique name or ID number for each wellhead gas liquid separator
or storage tank.

(ii)  For wells with oil production greater than or equal to 10 barrels
per day, using Calculation Methodology 3 and 4 of §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 §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 §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 §98.233(j).

(iii)  For wellhead gas-liquid separators and wells with throughput less
than 10 barrels per day, using Calculation Methodology 5 of §98.233(j)
Equation W-15 of §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 §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 §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 §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)  *	*	*

(i)  For each transmission storage tank, 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 transmission storage tank.

(10)  For well testing venting and flaring (refer to Equation W-17 of
§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 §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 §98.233).

(vii)  Report uncombusted CO2 emissions, in metric tons CO2e (refer to
Equation W-20 of §98.233).

(viii)  Report combusted CO2 emissions, in metric tons CO2e (refer to
Equation W-21 of §98.233).

(ix)  Report N2O emissions, in metric tons CO2e.

(x)  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)  *	*	*

(i)  *	*	*

(B)  For onshore natural gas processing, range of concentrations of CH4
and CO2 (refer to Equation W-30 of §98.233).

(C)	Annual CO2 and CH4 emissions, in metric tons CO2e for each gas
(refer to Equation W-30 of §98.233), by equipment type.

(ii)  *	*	*

(A)  For source categories §98.230(a)(4), (a)(5), (a)(6), (a)(7), and
(a)(8), total count for each type of leak source in Tables W-2, W-3,
W-4, W-5, and W-6 of this subpart for which there is a population
emission factor, listed by major heading and component type.

(B)  For onshore production (refer to §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 sub-basin category.

(C)  Annual CO2 and CH4 emissions, in metric tons CO2e for each gas
(refer to Equation W-31 of §98.233), by equipment type.

(16)  *	*	*

(i)  Number of above grade T-D transfer stations.

(ii)  Number of below grade T-D transfer stations.

(iii)  Number of above grade metering-regulating stations (this count
will include above grade T-D transfer stations).

(iv)  Number of below grade metering-regulating stations (this count
will include below grade T-D transfer stations).

(v)  [Reserved]

(vi)  Above grade metering-regulating station leak factor (refer to
Equation W-32 of §98.233).

*	*	*	*	*

(xv)  Annual CO2 and CH4 emissions, in metric tons CO2e for each gas,
from all above grade T-D transfer stations combined.

(xvi)  Annual CO2 and CH4 emissions, in metric tons CO2e for each gas,
from all below grade T-D transfer stations combined.

(xvii)  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.

(xviii)  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.

(xix)  Annual CO2 and CH4 emissions, in metric tons CO2e for each gas,
from all distribution mains combined.

(xx)  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.

(vi)  A unique name or ID for the EOR pump.

(18)  For EOR hydrocarbon liquids dissolved CO2 for each sub-basin
category (refer to Equation W-38 of §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 at 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.

*	*	*	*	*

(vi)  Report annual CO2, CH4, and N2O emissions from internal combustion
units, expressed in metric tons CO2e for each gas, by type of unit.

*	*	*	*	*

(e)	For onshore petroleum and natural gas production, report the average
API gravity, average gas to oil ratio, and average low pressure
separator pressure for each sub-basin category.

17.  Section 98.237 is amended by adding paragraph (e) to read as
follows:

§98.237  Records that must be retained.

*	*	*	*	*

	(e) The records required under §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.

18.  Section 98.238 is amended by:

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”.

b.  Adding definitions of “Associated with a single well-pad”,
“Distribution pipeline”, “Flare”, “Forced extraction”,
“Horizontal well”, ”Natural gas”, “Metering-regulating
station”, “Pressure groupings”, “Sub-basin category”,
“Transmission-distribution transfer station”, “Tubing diameter
groupings”, “Tubing systems”, “Vertical well”, and “Well
testing venting and flaring”.

c.  Removing the definition of “Field”.

The revisions read as follows:

§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.
This does not include storage and condensate tanks that are located
downstream of the point of combination.

*	*	*	*	*

Distribution pipeline means a pipeline that is designated as such by the
Pipeline and Hazardous Material Safety Administration (PHMSA) 49 C.F.R.
§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
well-pad or associated with a well-pad and CO2 EOR operations that are
under common ownership or common control including leased, rented, or
contracted activities by an onshore petroleum and natural gas production
owner or operator and that are located in a single hydrocarbon basin as
defined in §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.

*	*	*	*	*

	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.

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.

*	*	*	*	*

Pressure groupings 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.

*	*	*	*	*

ermeability, and unconventional with ≤0.1 millidarcy permeability.
Unconventional formation types are either shale, coal seam, or other
tight reservoir rock.  Wells producing from more than one unconventional
formation type shall be classified into only one type based on the
formation with the most contribution to production as determined by
engineering knowledge.  Unconventional wells producing in two or more
formation types  of “shale and coal seam”, “shale and other
tight”, or “shale, coal seam, and other tight”; are considered
shale.  In addition, unconventional wells producing in “coal seam and
other tight" formations are considered coal.

Transmission-distribution (TD) transfer station means a meter-regulating
station where a local distribution company takes part or all of the
natural gas from a transmission pipeline and puts it into a distribution
pipeline.

Transmission pipeline 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 groupings are defined as follows:  less than or equal to
1 inch; greater than 1 inch and less than 2 inch; and greater than or
equal to 2 inch.

Tubing systems 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
(i.e., the well testing) through a choke (an orifice restriction).  If
well testing is conducted immediately after well completion or workover,
then it is considered part of well completion or workover.

19.  Table W-7 to subpart W is amended by:

a.  Revising the entries for “Leaker Emission Factors—Above Grade
M&R at City Gate1 Stations Components, Gas Service,” “Population
Emission Factors - Below Grade M&R2 Components, Gas Service3,”
“Population Emission Factors - Distribution Mains, Gas Service4,”
and “Population Emission Factors - Distribution Services, Gas
Service5.”

b.  Removing Footnote 1.

c.  Redesignating Footnotes 2, 3, 4, and 5 as Footnotes 1, 2, 3, and 4.

The revisions read as follows:

*	*	*	*	*	*	*

Leaker Emission Factors – Transmission-distribution Transfer Station1

Components, Gas Service

*	*	*	*	*	*	*

Population Emission Factors - Below Grade Metering-Regulating station1
Components, Gas Service2

*	*	*	*	*	*	*

Population Emission Factors - Distribution Mains, Gas Service3

*	*	*	*	*	*	*

Population Emission Factors - Distribution Services, Gas Service4

*	*	*	*	*	*	*

1 Excluding customer meters.

2 Emission Factor is in units of "scf/hour/station."

3 Emission Factor is in units of "scf/hour/mile."

4 Emission Factor is in units of “scf/hour/number of services.”

 74 FR 16448 (April 10, 2009) and 74 FR 56260 (October 30, 2009).

 EPA has proposed to extend the 2012 reporting deadline for source
categories first required to begin data collection in 2011 from March
31, 2012 to September 28, 2012.  Please see the technical corrections
rule previously referenced.

 For more information on comments and responses, please see the preamble
to the final rule Mandatory Reporting of Greenhouse Gases (74 FFR
56348), and the Response to Public Comment on Subpart OO (“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart OO: Suppliers of Industrial GHGs” available in docket,
EPA-HQ-OAR- 2008-0508.)

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 are selected for particular applications based on their viscosities
within operating temperature ranges and/or their boiling points.  For
example, for liquid phase applications (e.g., some cooling applications)
HTFs are selected that have boiling points above the operating
temperature range and low viscosities at the lower operating
temperatures.  As temperature decreases, viscosity increases.  Low
viscosities are more desirable because they will provide good heat
transfer and will be easily pumped.  For higher temperature
applications, such as vapor phase soldering, HTFs with low vapor
pressures—at room temperature (high boiling points) are generally
selected.  (See, e.g., “Fluorochemicals in Heat Transfer Applications:
Frequently Asked Questions,” 3M, available in the docket for this
rulemaking.)

 Response to Comments Document: Subpart W – Petroleum and Natural Gas
Systems, Part 2, page 28.  Comment Number: EPA-HQ-OAR-2009-0923-1039-23.

  PAGE  42  of   NUMPAGES  42

Mandatory Reporting of Greenhouse Gases: Technical Revisions to Subpart
I: Electronics Manufacturing and Subpart W: Petroleum and Natural Gas
Systems of the Greenhouse Gas Reporting Rule

   PAGE  137  of   NUMPAGES  210

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