measurement where there is a larger number of wells in the sub-basin
category.
    Source Category Definitions. In general, we are proposing several
amendments to the source category definitions to clarify the boundaries
between the different industry segments. The proposed amendments below
seek merely to clarify coverage in the rule and were not intended to
change who is required to report within and across the industry
segments.
    Onshore Petroleum and Natural Gas Production. We are proposing
several amendments to the definition for the onshore petroleum and
natural gas production (also referred to as onshore production)
industry segment in 40 CFR 98.230(a)(2). EPA received feedback from
reporters on the finalized definition for the onshore production
industry segment on November 30, 2010 (see 75 FR 74489) requesting
clarification on the term ``associated with a well-pad.'' Specifically,
reporters requested clarification on what the term ``associated with a
well-pad'' meant in the context of the boundaries of the onshore
production industry segment. Reporters stated that there is unclear
demarcation between equipment that are considered part of the onshore
production industry segment and equipment that are considered part of
the onshore natural gas processing industry segment.
    To address concerns on the meaning of ''associated with a well-
pad'', EPA is first proposing to revise the term itself to state that
the onshore production

industry segment includes that equipment that is ``on a single well-pad
or associated with a single well-pad.'' EPA has determined that
equipment located on a single well-pad is considered part of the
onshore production industry segment irrespective of the hydrocarbon
streams that it is handling. For example, a separator located on a
well-pad that handles hydrocarbon streams from multiple well-pads would
be considered to be part of the onshore production industry segment,
i.e. equipment that is not located on a well-pad would be considered to
be associated with a well-pad. Also, hydrocarbon streams from multiple
wellheads located on a single well-pad is considered to be a single
hydrocarbon stream from that well-pad.
    In addition, EPA is proposing to clarify in the onshore production
industry segment definition that dehydrators that are on a single well-
pad or associated with a single well-pad are included as types of
equipment that is considered part of this segment. Following
promulgation of subpart W in November 2010, EPA received several
questions from the reporting community requesting clarification on
whether or not dehydrators associated with a single well-pad would be a
part of the industry segment. It was EPA's intent that these
dehydrators that are on a well-pad or associated with a single well-pad
be considered part of the onshore production industry segment. EPA also
received similar requests for clarification on whether or not storage
vessels, not necessarily the entire storage facility, were also
considered part of the onshore production industry segment. To address
these concerns, EPA is proposing to clarify in the definition that both
dehydrators and storage vessels are included in the equipment list that
are considered part of the onshore production industry segment.
Finally, EPA proposes to clarify that Enhanced Oil Recovery (EOR) that
use either CO2 or natural gas are a part of the source category. The
equipment located on a well-pad is part of the onshore production
industry segment irrespective of the hydrocarbon streams located on a
well-pad.
    Onshore Natural Gas Processing. EPA is proposing several
clarifications to the onshore natural gas processing industry segment
definition in 40 CFR 98.230(a)(3). By letter dated January 31, 2011,
the Gas Processors Association (GPA), CEC/AXPC, and API, all expressed
concerns with overlap between the onshore production, onshore natural
gas processing, and onshore natural gas transmission industry segments.
API stated that ``The definitions of the industry categories `onshore
oil and gas production' and `natural gas processing' do not provide a
clear line between onshore oil and gas production, gas gathering/
collection and booster stations, and natural gas processing
facilities.'' The letter stated ``API is particularly concerned that
the final rule could be interpreted to include gathering and boosting
stations in the processing sector, despite EPA's stated intent to
exclude gathering and boosting stations from coverage at this time.''
Industry raised concerns that boosting stations would be covered under
the finalized natural gas processing industry segment definition
because they typically have processes that require removal of liquids
for operation of specific equipment that boost gas pressure. For
example, scrubbers are used upstream of compressors to take out any
liquids for optimal operation of the compression equipment. However,
the presence of scrubbers in and of itself should not result in the
facility being defined as a processing facility.
    To address the concerns with boundaries between industry segments,
we are proposing several revisions to clarify our intent. First we are
proposing to strike the term ``and recovers'' from the first sentence
in order to more clearly characterize the unique activities performed
at the processing plant. Processing plants extract heavy hydrocarbons
and non hydrocarbon gases from the gaseous phase of an inlet feed to
the plant. By inclusion of the term ``recovers'' in the industry
segment definition, the natural gas processing plant definition may
have been incorrectly interpreted to bring in other types of processes
that were not intended to be covered.
    We are also proposing to clarify that this industry segment
includes one or a combination of the following three processes:
Separation of natural gas liquids (NGLs) from natural gas, separation
of non-methane gases from produced natural gas, or separation of NGLs
into one or more component mixtures. This proposed revision would
clarify that the natural gas processing industry segment differs from
what typically happens at boosting stations in that natural gas
processing plants typically perform one or more of these processes,
whereas boosting stations do not.
    We are also proposing a clarification on what separation means by
stating that separation means one or more of the following processes:
Forced extraction of natural gas liquids, sulfur and carbon dioxide
removal, fractionation of NGLs, or the capture of CO2 separated from
natural gas streams.
    We are proposing to strike the term ``this industry segment does
not include reporting of emissions from gathering lines and boosting
stations'' because the edits proposed above clarify what ``onshore
natural gas processing'' means, and therefore it is unnecessary to
discuss that which is excluded. Further, if we had decided to maintain
the ``gathering lines and boosting'' stations in the rule, EPA would
have to propose and finalize a definition of the term ``gathering line
and boosting'' station, which EPA has previously noted we intend to
consider in a future rulemaking (75 FR 74468).
    Finally we are proposing to strike the term ``facility'' and
replace it with the term ``plant'' as ``facility'' has a specific
definition in 40 CFR 98.6 that was not intended here. A natural gas
processing plant may be located at a facility that also contains other
source categories covered by 40 CFR part 98.
    Onshore Natural Gas Transmission Compression. EPA is proposing
several clarifications to the onshore natural gas transmission
compression industry segment definition in 40 CFR 98.230(a)(4). As
noted earlier, by letter dated January 31, 2011, API, CEC/AXPC, and GPA
raised their concerns that the boundaries between the onshore
production, onshore natural gas processing, and onshore natural gas
transmission compression industry segment boundaries were unclear based
on the provisions in the November 30, 2010 final rule.
    First, we are proposing to strike the term ``at elevated pressure''
because it was not clear what ``elevated pressure'' meant. For example,
elevated with respect to what baseline? Based on questions received on
the definition for transmission compressor stations, we have proposed
to clearly define transmission pipelines using a widely accepted
designation for what is a transmission pipeline, avoiding the need to
retain the language of ``elevated pressure.'' We are proposing to
define in 40 CFR 98.238 that a transmission pipeline means a Federal
Energy Regulatory Commission (FERC) rate-regulated interstate pipeline,
a state rate-regulated intrastate pipeline, or a pipeline that falls
under the ``Hinshaw Exemption'' as referenced in the Natural Gas Act.
    Next, we are proposing to clarify the end points between which a
natural gas transmission compression facility would move natural gas.
Specifically, we are proposing to explicitly state that natural gas
transmission compression facilities not only move natural gas from

production fields or gas processing plants, but also move natural gas
coming from other transmission compressors. In addition, we are
proposing to explicitly state that natural gas transmission compression
facilities may move natural gas into not only distribution pipelines,
but also into liquefied natural gas storage or into underground
storage.
    We are also proposing to strike the term ``natural gas
dehydration'' from the industry segment definition because this term
does not represent a unique characteristic to facilities with natural
gas transmission compression. We believe that deleting this term from
the definition of the natural gas transmission compression industry
segment, will result in this industry segment definition being more
representative and accurate. Finally, as described above under onshore
natural gas processing, we are proposing to strike the reference to
``gathering lines and boosting stations'' and ``facility.''
    Natural Gas Distribution. EPA is proposing several amendments to
the natural gas distribution industry segment definition to further
clarify its intent. First, we are proposing in 40 CFR 98.230(a)(8) to
eliminate the term ``city gate station'' and add the term ``meter-
regulating station.'' The term ``city gate,'' was used in the 2010
final rule because it was believed to be widely used throughout the
natural gas distribution industry. However, since publication, we have
learned that the term can have several meanings and the interpretation
of what is a ``city gate'' station may vary among potential reporters.
By letter dated March 2, 2011 from the American Gas Association, it was
stated that ``[t]he term `city gate' is widely used in the industry,
but unfortunately it means different things to different companies. It
can mean the place where an LDC takes custody of natural gas from the
upstream supplier (either directly from a producer or from an
interstate pipeline company). The term `city gate' is also used by some
to refer to the place where natural gas is conveyed into a lower
pressure distribution system for a town or city--either directly from
the upstream supplier (producer or interstate pipeline) or from the
LDC's own intrastate high pressure transmission pipelines. Some
companies do not use the term `city gate' to refer to the situation
where natural gas goes from the company's own transmission pipes to one
of its distribution systems. Instead, these companies may use other
terms such as `district regulator' or `metering and regulating
stations,' or `M&R' equipment, and these terms also can have varying
meanings.''
    Further, subpart A provides a definition for ``city gate,'' which
was intended to apply to subpart NN and is based on financial custody
transfer. Whereas the connotation of the term city gate as defined in
subpart A works sufficiently for subpart NN, it has created confusion
for subpart W and does not clearly identify the types of facilities EPA
intended to cover. The amendments that EPA is proposing are designed to
more clearly portray EPA's intent using language readily understandable
to industry.
    First, we are proposing to strike the parenthetical term ``(not
interstate transmission pipelines or intrastate transmission
pipelines).'' The parenthetical was deemed unnecessary because EPA is
proposing to add a definition for ``distribution pipeline'' in 40 CFR
98.238 that clarifies that ``distribution pipelines'' are only those
designated as such by the Pipeline and Hazardous Material Safety
Administration (PHMSA). Next, we are proposing to replace the term
``city gate'' with ``meter-regulating'' station. Because of the wide
range of views in industry on the meaning of the term ``city gate'' EPA
is proposing to remove the term ``city gate'' from subpart W and
replace it with a term that reflects the types of activities occurring
at the stations of interest. Specifically, we are proposing to add a
definition for the term ``meter-regulating station'' in 40 CFR 98.238
to mean, ``An above ground station that meters the flow rate, regulates
the pressure, or both, of natural gas in a natural gas distribution
facility. This does not include customer meters, customer regulators,
or farm taps.'' With this change, EPA intends to clarify a key concept
in the natural gas distribution segment definition, but does not intend
to change who is actually covered by the rule's requirements.
    EPA is proposing to strike the terms ``excluding customer meters''
and ``physically deliver natural gas to end users'' because the
proposed definition for ``meter-regulator'' stations already addresses
this exclusion.
    Finally, we are proposing to clarify in the industry segment
definition that we are only seeking for LDCs that are within a single
state, consistent with the definition for LDCs in subpart NN.
    Greenhouse Gases to Report. We are proposing several amendments to
the subpart W provisions on the greenhouse gases that must be reported.
    We are proposing to amend 40 CFR 98.232(c) to clarify that the
equipment listed in 98.232(c)(1) thru (22) are for equipment on a
single well-pad or associated with a single well-pad in order to make
the language consistent with the proposed changes to the onshore
production industry segment definition in 40 CFR 98.230(a)(2) described
above.
    We are proposing to amend 40 CFR 98.232(i) by replacing the term
``custody transfer city gate station'' with the term ``transmission-
distribution transfer station'' and replacing the term ``non-custody
transfer station'' with the term ``metering-regulating station.'' EPA
is proposing this amendment to clarify that the sources covered be
consistent with the proposed terms for the natural gas distribution
industry segment in 40 CFR 98.230(a)(8). We are also proposing to amend
the source types by removing the text ``Customer meters are excluded.''
The exclusion is already covered in both the industry segment
definition and in the definition of ``metering-regulating station''
provided in 40 CFR 98.238 and does not provide added clarity in this
context. Next, we are proposing to strike 40 CFR 98.232(j) in order to
address concerns raised that the inclusion of this provision resulted
in confusion amongst reporters as they were unsure how this provision
aligned with the flare emissions that are captured under the applicable
emissions source calculations throughout 40 CFR 98.233. In addition to
the proposal to strike 40 CFR 98.232(j), we are proposing to revise the
introductory sentences to 40 CFR 98.232(e), (f), (g), (h), and (i) to
clarify that N2O emissions, which are the primary GHG
emission from flaring, are also required to be reported under these
industry segments. This proposed amendment also clarifies that flare
emissions must only be calculated where ``flare stacks'' are either
specifically identified in a specific industry segment (e.g., onshore
natural gas processing) or where an emissions source that is covered in
an industry segment is routed to a flare (e.g., centrifugal compressors
under onshore natural gas transmission).
    Finally, we are proposing to further clarify in 40 CFR 98.232(k)
that the onshore production and natural gas distribution industry
segments are to report their combustion emissions under subpart W,
while the remaining industry segments are to report their combustion
emissions under subpart C of part 98.
    Calculating Greenhouse Gas Emissions. We are proposing several
clarifications, corrections, and amendments throughout 40 CFR 98.233.
    Natural Gas Pneumatic Device Venting. EPA is proposing to revise
Equation W-1 in 40 CFR 98.233(a) by

adding 40 CFR 98.233(a)(3) that allows the type of pneumatic devices to
be determined using engineering estimation based on best available
information. The proposed amendment for pneumatic devices was in
response to questions received about how to determine whether a
pneumatic device is high bleed or low bleed and the unanticipated
burden for industry if they would have to measure the bleed rate of all
pneumatic devices in order to determine how to characterize each
pneumatic device.
    EPA is also proposing to amend Equation W-1, to include a parameter
``T'' that estimates the total number of hours the devices were
operational. Previously, this equation assumed that all natural gas
pneumatic devices were operational all year, which would overestimate
the emissions where the pneumatic devices operate less than a full
year. Overall, we are proposing these amendments to Equation W-1 to
more accurately reflect operating conditions for natural gas pneumatic
device venting. Furthermore, EPA is clarifying in the definition for
``GHGi'' that compositions in 40 CFR 98.233(u) may be used
for the onshore petroleum and natural gas production, onshore natural
gas transmission compression, and underground natural gas storage
industry segments.
    In addition, with respect to the pneumatic device venting category,
we are proposing in 40 CFR 98.236(c)(1)(iv) to clarify that emissions
should be reported collectively for all high bleed pneumatic devices,
then separately for all intermittent bleed pneumatic devices, and
separately for all low bleed pneumatic devices. The 2010 final rule
stated merely ``report emissions collectively.'' The proposed amendment
is consistent with how data are collected and emissions calculated.
    Natural Gas Driven Pneumatic Pump Venting. We are proposing to
amend Equation W-2 in 40 CFR 98.233(c), which is used for calculating
GHG emissions from natural gas pneumatic pump venting, to include a
parameter ``T'' that estimates the total amount of hours the pumps were
operational. Previously, this equation assumed that all natural gas
pneumatic pumps were operational all year, which would overestimate the
emissions where the pneumatic devices operate less than a full year. We
are proposing this amendment to Equation W-2 to more accurately reflect
operating conditions for natural gas pneumatic pump venting.
    Acid Gas Removal Vents. We are proposing to amend the calculation
for estimating CO2 emissions from acid gas removal vents in
Equation W-4 in 40 CFR 98.233(d). EPA notes that the equation in the
2010 final rule is an approximation and works well when the amount of
CO2 in gas is relatively low, such as 1 percent. However,
the error rate in the estimate increases significantly as the amount of
CO2 in gas increases. Therefore, EPA is proposing a new
equation, which uses the exact same input parameters and thus will not
result in any additional burden to reporters, but will improve the
quality of the information submitted to EPA.
    We are also proposing to amend 40 CFR 98.233(d)(1) to specify that
the use of CEMS is required if a CO2 concentration monitor
and volumetric flow rate monitor are installed. This amendment was made
to clarify what conditions must be met to satisfy the subpart C:
Stationary Combustion Tier 4 calculation requirement for Acid Gas
Removal vents and to make the requirements consistent in subpart W
where use of CEMS is required.
    In 40 CFR 98.236(c)(3) we are proposing to clarify that reporting
of CO2 content should reflect the annual average of the
measurements undertaken in 40 CFR 98.233(d). The 2010 final rule was
not clear on whether or not to aggregate the measurements, and if so,
how.
    Dehydrator Vents. EPA is proposing several amendments to the
provisions in 40 CFR 98.233(e) for calculating GHGs from dehydrator
vents. First, we are proposing to clarify that gases other than natural
gas, such as nitrogen, flash gas from the flash tanks, or dry gas from
the absorber, that are used as stripping gases satisfy the requirements
stated in 40 CFR 98.233(e)(1) introductory language. The final rule
explicitly stated that natural gas was the gas considered to be the
stripping gas. We are proposing this amendment to more accurately
reflect operating conditions for glycol dehydrators in which gases
other than natural gas are used as stripping gases.
    We are also proposing to amend 40 CFR 98.233(e)(6) to clarify that
GHG mass emissions from glycol dehydrators are to be calculated from
volumetric GHG emissions using calculations in 40 CFR 98.233(v). In
addition, we are proposing to clarify that only for dehydrators that
use desiccant should GHG volumetric and mass emissions be calculated
using paragraphs 40 CFR 98.233(u) and 98.233(v). We are proposing this
amendment to account for calculation methodology 1 and 2, 40 CFR
98.233(e)(1)-(e)(3), that calculates total GHGi volumetric emissions in
standard cubic feet and will only need conversion to GHG mass emissions
using 40 CFR 98.233(v).
    With respect to the data reporting requirements, we are proposing
to clarify the requirement to report vented and flared emissions
individually. In the 2010 final rule, EPA intended that vented
emissions be reported as one value, and flared emissions as a separate
value. However, because these were entered in the same sub-paragraph,
40 CFR 98.236(c)(4)(i)(J), there was some ambiguity as to the
aggregation for reporting. Therefore, EPA is proposing to create
separate reporting requirements for vented and flared emissions. A
similar amendment is proposed for 40 CFR 98.236(c)(4)(ii)(D).
    Also for dehydrators, EPA is proposing to clarify that in
specifying whether any vent gas controls have been used, the owners or
operators should report which vent gas controls were used.
    Well Venting for Liquids Unloadings. First, we are proposing to
revise 40 CFR 98.233(f) methodology 1, methodology 2, and methodology 3
such that sampling would be done in a sub-basin category as opposed to
the field level as described earlier in Section II.C. of this preamble
(Sub-basin Category for Onshore Petroleum and Natural Gas Production).
    In the technical corrections rule, EPA proposed several technical
corrections to the provisions in 40 CFR 98.233(f) including corrections
to Equation W-8, W-9, and their respective definitions. In today's
action, we are proposing additional revisions to Equations W-8 and W-9
and their respective definitions. Because both proposed actions affect
the same paragraph of the rule, for clarity the part 98 amendatory
language at the end of this preamble contain the full set of revisions
from both proposed actions. The changes proposed today are explained
below in this preamble.
    First we are proposing to revise Equation W-8 by correcting the
definition for parameter Ea,n to be Es,n to
accurately reflect that the calculated emissions should be in standard
conditions and not actual conditions. The proposed revision from actual
conditions to standard conditions was made to be more uniform in
approach to calculate emissions. The parameters in Equation W-8 have
been made applicable to each venting instance, q, and for each well, p,
in a pressure grouping and sub-basin category. These changes are
notational amendments that correct the summation operation. Next, we
are proposing to amend the definition for ``SFR'' which is the average
sales flowrate to state that the

average sales flow rate of gas is to be obtained at standard
conditions, and also that Equation W-33 may be used to convert the
sales flow rate from actual to standard conditions. In addition, the
definition for parameter WDwp has been clarified to mean the
distance between the lowest packer to the bottom of the well. We are
also proposing to remove 40 CFR 98.233(f)(2)(i) to remove redundancy
with 40 CFR 98.233(f)(4). As stated previously, we are proposing to
amend Equation W-9 in the same manner as Equation W-8: By revising the
definition for ``Ea,n'' to accurately state that the
definition should result in standard conditions, thus
``Es,n'', and by revising the definition for SFR to state
that the average sales flow rate is to be calculated at standard
conditions using Equation W-33; and the parameters, where applicable,
have been made applicable to each venting event, q for each well, p, in
a pressure grouping and sub-basin category to correct the summation.
Finally, we are proposing to amend Equation W-8 and W-9 to account for
a change in aggregation from field level to sub-basin category for
reporting.
    For Calculation Method 1, where a representative measurement is
taken from one well unloading and then applied to all other wells of a
similar type, EPA is defining the categorization of ``similar types''
by five pressure ranges and three tubing diameters. The pressure ranges
were optimized using HPDI well counts in 5 psig pressure increments
from zero gauge pressure to 200 psig. The fifth ``unbounded'' pressure
range is ``greater than 200 psig,'' which EPA believes will have very
few well liquids unloading venting to the atmosphere. The three tubing
diameter ranges, equal or less than 1 inch, greater than 1 inch and
equal or less than 2 inch, and greater than 2 inch, were derived from
gas well tubing suppliers' specifications. The relevancy of these
pressure ranges and tubing diameter ranges is that liquids unloading
venting is dependent on both the shut-in pressure of the reservoir
(shut-in by liquids accumulation) and velocity of gas pushing liquids
up the tubing, which is a function of tubing diameter.
    Finally, in the data reporting requirements in 40 CFR 98.236(c)(5),
we are proposing to make a harmonizing change, consistent with the
amendments described above in (Sub-basin Category for Onshore Petroleum
and Natural Gas Production), that reporting should be for each well
tubing diameter grouping and pressure grouping within each sub-basin
category.
    Gas Well Venting During Completions and Workovers From Hydraulic
Fracturing. We are proposing several amendments to 40 CFR 98.233(g) to
account for the proposed change in aggregation from field level to sub-
basin category for taking measurements. For example, we are replacing
the term ``field'' with ``sub-basin and well type combination'' in the
definitions and clarifying that the GHG emissions are determined for
each sub-basin and well type combination. For further discussion on the
proposed changes from field level calculations and reporting to sub-
basin category, please refer to Section II.C of this preamble (Sub-
basin Category for Onshore Petroleum and Natural Gas Production).
    We are also proposing to revise equation W-10 by including a
provision to account for the time period in which we believe normal
production of a well would be established. In this action, we are
revising equation W-10 by defining a parameter, FRM, which would
represent the ratio of emissions (FRp) to the average 30 day
production from the well immediately following hydraulic fracturing
(PRP). The emissions, FRp, which in the final
rule as the average flow rate in cubic feet per hour converted to
standard conditions, are calculated using W-11A and W-11B. FRM is
calculated using the newly assigned Equation W-12. We believe that this
proposed revision will more accurately represent the production flow
from a well immediately following a well or completion using hydraulic
fracturing and will more accurately represent when a completion or
workover ends and when normal production begins. Finally, in Equation
W-10, EPA is proposing to add the parameter W, which is the number of
wells completed or worked over using hydraulic fracturing in a sub-
basin and well type combination, and, where appropriate, made the
parameters applicable to each well p. This amendment corrects the
summation operator to make it mathematically accurate.
    EPA also added Equation W-11C, which allows reporters to determine
whether the well flow rate of gas during venting to the atmosphere or a
flare (i.e., FRWP, is sonic or sub-sonic flow. Thus,
reporters can determine whether to use Equation W-11A, which is for
sub-sonic flow, or Equation W-11B, which is for sonic flow.
    We are also proposing several minor edits to 40 CFR 98.233(g)(3)
and 40 CFR 98.233(g)(5) to clarify that all requirements in 40 CFR
98.233(g) apply to gas well venting during completions and workovers
from hydraulic fracturing, consistent with the emission source name of
``Gas well venting during completions and workovers from hydraulic
fracturing''.
    In 40 CFR 98.233(g)(3) we are also proposing to delete the
reference to how to calculate the volume of recovered completion or
workover gas. The first sentence in that paragraph is already clear
that company records may be used, therefore the second sentence does
not provide any additional information and is duplicative.
    We are proposing several harmonizing changes to the data reporting
requirements for this emissions source. We are proposing to indicate
that reporting is required for each ``sub-basin category'' and well
type (horizontal or vertical). We are also proposing to clarify that
reporting of reduced emissions completions for both well completions
and workovers is required. Although this information is required to be
collected for both well completions and well workovers, EPA
inadvertently omitted the reporting requirement for reduced emissions
completions for well workovers.
    Also in 40 CFR 98.236, we are proposing to clarify that reporters
are only required to count the number of workovers that flare or vent
gas to the atmosphere. There is no reporting requirement for workovers
that do not flare or vent gas.
    Gas Well Venting During Completions and Workovers Without Hydraulic
Fracturing. In this section we are proposing to strike the term ``well
workovers not involving hydraulic fracturing'' from the introductory
text in paragraph (h) because it was repetitive.
    Second we are proposing to replace the term ``field'' used in the
definition for the parameter ``Nwo'' and ``f'' for the same
reasons stated in Section II.C. of this preamble (Sub-basin Category
for Onshore Petroleum and Natural Gas Production).
    Finally, EPA is proposing to amend the summation operator in
Equation W-13 to make it mathematically accurate. This includes making
specific parameters in Equation W-13 applicable to each well
completion, p.
    Blowdown Vent Stacks. In a previous action we proposed amendments
to the introductory sentences to 40 CFR 98.233(i). In this action,
based on additional questions received during implementation of subpart
W, we are proposing to further clarify the types of blowdowns that EPA
intended to cover. First, we are proposing to delete ``to atmosphere''
because not every blowdown will result in the blowdown chamber being
brought to atmospheric pressure. Operators often release only

part of the gas in the blowdown chamber and maintain it at low
pressure. It was always EPA's intent to cover these types of
``blowdowns'' and thus we are proposing to delete ``to atmosphere''.
Further we are clarifying that we only intend to cover the types of
blowdowns typically tracked by operators for planned maintenance or
emergency shutdowns. EPA had earlier proposed to exclude emergency
shutdowns in a previous action. However, EPA has since been informed
that operators track emergency shutdowns already. Therefore, EPA is
proposing to require emergency shutdowns to be reported. In addition,
we did not intend to capture blowdowns that are not typically tracked
by operators, such as pressure release valve releases designed to keep
equipment under safe operating mode.
    EPA has also considered other factors that could impact emissions
from blowdowns, for example compressibility. We have considered
accounting for gas compressibility but have not proposed this because
we believe that the effort in adjusting for a compressibility factor
outweighs the benefits in terms of increased accuracy. EPA seeks
comments on why such an allowance should be provided and how to
standardize this option so that those who choose to use it all do so in
the same way.
    Also in this action, we are proposing to revise the numbering of
Equation W-14b and include an additional Equation, W-14b that will take
into account that a chamber may not be blown down to atmospheric
pressure, and will allow facilities the option of tracking blowdowns by
each occurrence by blowdown volume. It has come to EPA's attention that
some facilities may log blowdowns at a facility by individual blowdown
occurrence. To enable facilities to retain their current tracking
system, we are proposing to add an option for calculating blowdown
emissions by equipment type. This option for tracking blowdowns would
not impact data quality. Harmonizing changes in 40 CFR 98.236(c)(7) are
being proposed to account for these amendments.
    Lastly, we are proposing to include a default composition for the
natural gas transmission industry segment, and for the LNG storage and
underground storage segments. EPA received feedback from industry that
a default composition of 95 percent methane and 1 percent
CO2 was a representative breakdown of the gas composition at
these types of facilities while limiting burden and should be
acceptable. EPA agrees that a default composition of 95 percent methane
and 1 percent CO2 is appropriate because the composition of
natural gas is monitored by transmission compression companies and
regulated by FERC.
    Onshore Production Storage Tanks. EPA is proposing to replace the
term ``field'' in 40 CFR 98.233(j)(1)(vii)(B), 40 CFR
98.233(j)(1)(vii)(C), and 40 CFR 98.233(j)(3)(i) with ``sub-basin
category'' consistent with the proposed amendments described in Section
II.C, (Sub-basin Category for Onshore Petroleum and Natural Gas
Production), of this preamble. We are also proposing to clarify this
level of reporting in the data reporting requirements in 40 CFR
98.236(c)(8).
    Also in the data reporting requirements, we are proposing to
clarify the reporting requirement in 40 CFR 98.236(c)(8)(i),
98.236(c)(8)(ii) and 98.236(c)(8)(iii) that reporters must report
vented, flared, and recovered emissions individually for Calculation
Methodology 1 and 2. This is consistent with the calculation
requirements.
    Transmission Storage Tanks. We are proposing to revise 40 CFR
98.233(k) to include an additional provision such that reporters would
now have the option of directly measuring the transmission storage
tanks while bypassing an initial screening with the optical gas imaging
instrument. EPA received feedback from industry that some owners and
operators would prefer to simply measure the tank annually without
having to be required to screen the tank vapors with a camera first. We
agree that allowing facilities to directly measure the emissions,
without first requiring leak detection, does not compromise data
quality, but could enable facilities to meet the requirements of the
rule with lower burden. Therefore, in this action, EPA is proposing to
allow operators to either screen their tanks first by using the optical
gas imaging instrument for 5 continuous minutes and if a leak is
detected, measure the leak according to the provisions in 40 CFR 98.234
consistent with the 2010 final rule, or measure the tank vent vapors
for 5 minutes using either a flow meter, calibrated bag, or high volume
sampler according to the provisions outlined in 40 CFR 98.234.
    Finally, with respect to the data reporting requirements in 40 CFR
98.236(c)(9), as described further above, we are proposing to clarify
the separate reporting requirements for vented and flared emissions.
    Well Testing Venting and Flaring. EPA is proposing In amendments to
the data reporting requirements in 40 CFR 98.236(c)(10). Specifically,
we are proposing to add a reporting requirement for the emissions of
the flaring gas collectively. This is consistent with other proposed
clarifications to report flared emissions separately.
    EPA is considering, and has not proposed, using the production rate
to estimate volume of emission from gas wells that produce dry gas. EPA
is soliciting comments on this suggested provision for gas wells.
    EPA has received several requests to exclude the well testing
venting and flaring emissions source from the rule. Industry has
informed EPA that this source has very little, if any, emissions
because the well testing is almost exclusively performed in a closed
system using a ``test separator,'' which industry has stated would
result in zero emissions.
    EPA has reviewed this request and in general, EPA continues to
believe that well testing venting and flaring is a relevant source in
the onshore petroleum and natural gas production industry segment. In
addition, EPA has determined that during well testing, some states
allow companies to flare sour gas for a maximum of 72 or 144 hours. EPA
has concluded that this approach would result in emissions from this
source that should be reported under this rule. If, however, for some
reason reporters do not have any emissions from this source (for e.g.,
states do not allow venting or flaring from well testing), they would
report zero emissions.
    Thus, EPA is retaining well testing venting and flaring in the
rule. However, EPA is seeking comment on how to reduce or eliminate
burden in cases where companies verify that zero emissions are
associated with this potential source, such as when a closed loop
system is employed.
    Associated Gas Venting and Flaring. EPA is proposing to revise 40
CFR 98.233(m) to replace the term ``field'' with the term ``sub-basin
category'' for the same reasons outlined in Section II.C. (Sub-basin
Category for Onshore Petroleum and Natural Gas Production) of this
preamble.
    Flare Stack Emissions. We are proposing two amendments in 40 CFR
98.233(n)(2) to clarify how to determine gas compositions for
hydrocarbon streams going to flare. First, we are proposing to amend 40
CFR 98.233(n)(2)(ii) to clarify that reporters must use the GHG mole
percent in feed natural gas for all streams for onshore natural gas
processing plants that solely fractionate a liquid stream. EPA is
proposing this amendment to address lack of clarity in the final
provisions

which did not explicitly state how natural gas processing plants which
only fractionate liquid streams would determine their gas compositions.
We are also proposing to clarify in 40 CFR 98.233(n)(2)(iii) that
methane, in addition to ethane, propane, butane, pentane-plus and mixed
light hydrocarbons, should be accounted for when the stream going to
the flare is a hydrocarbon product stream. This proposed technical
correction, to add methane, ensures that paragraph 40 CFR
98.233(n)(2)(iii) is consistent with the equation.
    In addition, we are proposing to clarify the summation operator in
W-21 to make it mathematically correct. We are also clarifying that
source types in 40 CFR 98.233 that send emissions to a flare must
determine volumetric flow rate, parameter ``Va'', in Equation W-19
through W-20, at actual conditions.
    We are also proposing to clarify that the volume of gas sent to the
flare should be calculated in actual conditions. This is consistent
with other proposed changes throughout this revision that clarify the
use of actual versus standard conditions.
    In addition, we are proposing to allow facilities the option to use
a continuous emissions monitoring system (CEMS) to estimate GHG
emissions from flares. EPA received questions as to why CEMS were
allowed for use for AGR vents, for example, but not for flares. We did
not intend to unnecessarily limit the measurement options for flares,
and therefore are proposing to add the option to use CEMS.
    The proposed text clarifies that the use of CEMS is required if a
CO2 concentration monitor and volumetric flow rate monitor
are installed and that optionally a user may install a CO2
concentration monitor and volumetric flow rate monitor to be eligible
to use the Tier 4 methodology. When CEMS are used to calculate
emissions for flare stacks the use of equations W-19 to W-21 would no
longer apply. With the relatively high quantity of unburned methane in
the emissions from flares, EPA has identified that it is not
appropriate to use the CH4 calculation methodology in
subpart C as most flared gases will not be fuels listed in Table C-1 of
subpart C. EPA is seeking comment on what form an equation should take
that would calculate CH4 and N2O for flares that
are monitored by CEMS. One option is to calculate the CH4 by
multiplying the concentration of CO2 measured by the CEMS by
the fraction of CH4 that was not combusted as determined by
flare efficiency.
    In the data reporting requirements in 40 CFR 98.236(c)(12) we are
proposing to add reporting requirements consistent with the calculation
requirements in Equations W-19 through W-21. Specifically, we are
proposing to add reporting of uncombusted CH4, combusted and
uncombusted CO2 and combustion-related N2O
emissions. The proposed amendments ensure consistency across the
calculation, monitoring and reporting requirements.
    Centrifugal Compressor Venting. Consistent with other
clarifications throughout this proposed rule, we are proposing to
clarify in the definition for the term MTm in Equation W-24 that flow
measurements should be determined in standard cubic feet per hour.
    Leak Detection and Leaker Emission Factors.
    We are proposing to revise 40 CFR 98.233(q)(8) to remove the term
``city gate stations at custody transfer'' and replace with
``transmission-distribution transfer stations'' for the reasons
described earlier in Section II.C of this preamble. We are also
proposing to remove the term ``meters and regulators'' and replace with
above ground ``metering-regulating stations''. The term ``meter-
regulating'' is a term that we are proposing to define in this action,
as described earlier in Section II.C of this preamble.
    The revisions to terminology for natural gas distribution
facilities have been proposed to clearly identify who is covered under
the 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 x 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 x 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 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,\5\ 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.
---------------------------------------------------------------------------

    \5\ Response to Comments Document: Subpart W--Petroleum and
Natural Gas Systems, part 2, page 28. Comment Number: EPA-HQ-OAR-
2009-0923-1039-23.
---------------------------------------------------------------------------

    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 Sec.
98.3(g)(2)(i) shall include an explanation of how company records,
engineering estimation, or best available information are used to
calculate each applicable parameter under this subpart.'' 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.
    Sub-Basin Category. With the change from field level reporting to
sub-basin category, EPA is proposing to add a definition for sub-basin
category to mean a subdivision of a basin into the unique combination
of wells with the surface coordinates within the boundaries of an
individual county and subsurface completion in one or more of each of
the following four formation types: Conventional with > 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 (RFA)

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of this 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 U.S.C. 603 and 604.
Thus, an agency may certify that a rule will not have a significant
economic impact on a substantial number of small entities if the rule
relieves regulatory burden, or otherwise has a positive

economic effect on all of the small entities subject to the rule.
    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 (UMRA)

    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: August 19, 2011.
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:

Sec.  98.1  Purpose and scope.

* * * * *
    (c) For facilities required to report under onshore petroleum and
natural gas production under subpart W of this part, the terms Owner
and Operator used in subpart A have the same definition as Onshore
petroleum and natural gas production owner or operator, as defined in
Sec.  98.238 of this part.
    3. Section 98.6 is amended by revising the definitions for
``Continuous bleed'' and ``Intermittent bleed pneumatic devices'' to
read as follows:

Sec.  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:

Sec.  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:

Sec.  98.92  GHGs to report.

    (a) You must report emissions of fluorinated GHGs (as defined in
Sec.  98.6), N2O, and fluorinated heat transfer fluids (as
defined in Sec.  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.

Sec.  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:

Sec.  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:

Sec.  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 by removing the definition of ``Heat transfer
fluids'' and adding the definition of ``Fluorinated heat transfer
fluids'' in alphabetical order to read as follows:

Sec.  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
------------------------------------------------------------------------
                                      Fluorinated GHGs and fluorinated
           Product type               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) through
(a)(4), and (a)(8) to read as follows:

Sec.  98.230  Definition of the source category.

    (a) * * *
    (2) Onshore petroleum and natural gas production. Onshore petroleum
and natural gas production means all equipment on a single well-pad or
associated with a single well-pad (including but not limited to
compressors, generators, dehydrators, storage vessels, and portable
non-self-propelled equipment which includes well drilling and
completion equipment, workover equipment, gravity separation equipment,
auxiliary non-transportation-related equipment, and leased, rented or
contracted equipment) used in the production, extraction, recovery,
lifting, stabilization, separation or treating of petroleum and/or
natural gas (including condensate). This equipment also includes
associated storage or measurement vessels and all enhanced oil recovery
(EOR) operations using CO2 or natural gas injection, and all
petroleum and natural gas production equipment located on islands,
artificial islands, or structures connected by a causeway to land, an
island, or an artificial island.
    (3) Onshore natural gas processing. Natural gas processing means
the separation of natural gas liquids (NGLs) or non-methane gases from
produced natural gas, or the separation of NGLs into one or more
component mixtures. Separation includes one or more of the following:
Forced extraction of natural gas liquids, sulfur and carbon dioxide
removal, fractionation of NGLs, or the capture of CO2
separated from natural gas streams. This segment also includes all
residue gas compression equipment owned or operated by the natural gas
processing plant. This industry segment includes processing plants that
fractionate gas liquids, and processing plants that do not fractionate
gas liquids but have an annual average throughput of 25 MMscf per day
or greater.
    (4) Onshore natural gas transmission compression. Onshore natural
gas transmission compression means any stationary combination of
compressors that move natural gas from production fields, natural gas
processing plants, or other transmission compressors through
transmission pipelines to natural gas distribution pipelines, LNG
storage facilities, or into underground storage. In addition, a
transmission compressor station includes equipment for liquids
separation, and tanks for the storage of water and hydrocarbon liquids.
Residue (sales) gas compression that is part of onshore natural gas
processing plants are included in the onshore natural gas processing
segment and are excluded from this segment.
* * * * *
    (8) Natural gas distribution. Natural gas distribution means the
distribution pipelines and metering and regulating equipment at
metering-regulating stations that are operated by a Local Distribution
Company (LDC) within a single state that is regulated as a separate
operating company by a public utility commission or that is operated as
an independent municipally-owned distribution system. This segment also
excludes customer meters and regulators, infrastructure, and pipelines
(both interstate and intrastate) delivering natural gas directly to
major industrial users and farm taps upstream of the local distribution
company inlet.
* * * * *
    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:

Sec.  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 Sec.  98.233(z) and report under
this subpart the emissions of CO2, CH4, and
N2O from stationary or portable fuel combustion equipment
that cannot move on roadways under its own power and drive train, and
that is located at an onshore petroleum and natural gas production
facility as defined in Sec.  98.238. Stationary or portable equipment
are the following equipment, which are integral to the extraction,
processing, or movement of oil or natural gas: well drilling and
completion equipment, workover equipment, natural gas dehydrators,
natural gas compressors, electrical generators, steam boilers, and
process heaters.
* * * * *
    (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:
    a. 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.
    b. Adding paragraph (a)(3).
    c. In paragraph (c), revising Equation W-2 and the definition of
``GHGi''; and adding the definition of ``T'' in Equation W-
2.
    d. Revising paragraphs (d) introductory text and (d)(1).
    e. In paragraph (d)(3), revising Equation W-4 and removing the
definition of ``[alpha]'' in Equation W-4.
    f. Revising paragraph (e)(1)(vii).
    g. Revising the definition of ``1000'' in Equation W-5 of paragraph
(e)(2).
    h. Revising paragraph (e)(6).
    i. Revising paragraphs (f) introductory text, (f)(1) introductory
text, and the definitions of Equation W-7 in paragraph (f)(1).
    j. Revising paragraphs (f)(1)(i)(A) through (f)(1)(i)(C).
    k. In paragraph (f)(2), revising Equation W-8 and the definitions
of Equation W-8.
    l. Removing paragraphs (f)(2)(i) and (f)(2)(ii).
    m. In paragraph (f)(3), revising Equation W-9 and the definitions
of Equation W-9.
    n. Removing paragraphs (f)(3)(i) and (f)(3)(ii).
    o. In paragraph (g), revising Equation W-10 and the definitions of
Equation W-10.
    p. Revising introductory texts for paragraphs (g)(1) and (g)(1)(i).
    q. Removing paragraphs (g)(1)(i)(A) through (g)(1)(i)(D).
    r. In paragraph (g)(1)(ii), revising paragraph (g)(1)(ii)
introductory text; redesignating Equation W-11 as Equation W-11A and
Equation W-12 as Equation W-11B respectively; and adding Equation W-
11C.
    s. 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).
    t. Removing paragraph (g)(1)(ii)(D).
    u. Revising introductory texts for paragraphs (g)(3) and (g)(5).
    v. In paragraph (h), revising paragraph (h) introductory text and
the definitions of ``Nwo'', ``f'', ``Vp'' and
``Tp'' in Equation W-13.
    w. Revising paragraph (i) introductory text and paragraphs (i)(1)
and (i)(2).
    x. In paragraph (i)(3), revising 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.
    y. Revising paragraph (i)(5).
    z. Revising paragraph (j)(1)(vii)(B), (j)(1)(vii)(C), and
(j)(3)(i).
    aa. Revising paragraphs (k)(1) and (k)(2)(i).
    bb. Revising paragraph (m)(1).
    cc. Revising paragraph (n)(2)(ii) and (n)(2)(iii), and in paragraph
(n)(4), revising equation W-21 and the definition for
``Yj''.
    dd. Redesignating paragraph (n)(9) as paragraph (n)(10) and adding
new paragraphs (n)(9) and (n)(11).
    ee. In paragraph (o)(6), revising the definition of
``MTm'' in Equation W-24.
    ff. In paragraph (p)(7)(i), revising the definition of
``MTm'' in Equation W-28.
    gg. In paragraph (q), revising equation W-30 and the definitions
for ``x'', ``EF'', ``GHGi'', ``Tp'', and revising
paragraph (q)(8).
    hh. In paragraph (r), revising the definitions of
``Counts'', ``EFs'', and ``GHGi'' in
Equation W-31.
    ii. Revising paragraphs (r)(2)(i)(A), (r)(6)(i), (r)(6)(ii)
introductory text, Equation W-32, and the definitions of Equation W-32.
    jj. Revising introductory texts for paragraphs (t), (t)(1), and
(t)(2).
    kk. Revising paragraph (u) introductory text and paragraph (u)(2).
    ll. In paragraph (v), revising paragraph (v) introductory text and
the definitions of ``Masss,i'', ``Es,i'', and
``[rho]i'' in Equation W-36.
    mm. Revising introductory texts for paragraphs (z), (z)(1), (z)(2),
(z)(2)(i), and (z)(2)(ii).
    nn. Adding paragraphs (z)(1)(i) and (z)(1)(ii).
    The revisions read as follows:

Sec.  98.233  Calculating GHG emissions.

    (a) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.000

* * * * *
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) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.001

* * * * *
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) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.002

* * * * *
    (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 Sec.  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 Sec.  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) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.003

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.
0.37x10-3 = {3.14 (pi)/4{time} /{14.7*144{time}  (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) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.004

Where:

Es,n = Annual natural gas emissions at standard
conditions, in cubic feet/year.
W = Total number of wells with well venting for liquids unloading at
the facility.
0.37x10-3 = {3.14 (pi)/4{time} /{14.7*144{time}  (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) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.005

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 Sec.  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 Sec.  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:
[GRAPHIC] [TIFF OMITTED] TP09SE11.006

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.

[GRAPHIC] [TIFF OMITTED] TP09SE11.007

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.

[GRAPHIC] [TIFF OMITTED] TP09SE11.008

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.

[GRAPHIC] [TIFF OMITTED] TP09SE11.009

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 Sec.  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
Sec.  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.
[GRAPHIC] [TIFF OMITTED] TP09SE11.010

Where:

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

[GRAPHIC] [TIFF OMITTED] TP09SE11.011

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 ([deg]F).
Ta = Temperature at actual conditions in the blowdown
equipment chamber ([deg]F) 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
Sec.  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
Sec.  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 Sec.  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 Sec.  98.234(b) through (d). If you do not have a continuous
flow measurement device, you may install a flow measuring device on the
tank vapor vent stack. If the vent is directly measured for five
minutes under paragraph Sec.  98.233(k)(1) of this section to detect
continuous leakage, this serves as the measurement.
    (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) * * *
    [GRAPHIC] [TIFF OMITTED] TP09SE11.012

* * * * *
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 Sec.  98.233 use Equations W-19 through W-
21 of this section, use estimate of emissions under actual conditions
for the parameter, Va, in these equations.

    (o) * * *
    (6) * * *
* * * * *
MTm = Flow Measurements from all centrifugal compressor
vents in each mode in (o)(1)(i) through (o)(1)(iii) of this section
in standard cubic feet per hour.
* * * * *
    (p) * * *
    (7) * * *
    (i) * * *
* * * * *
MTm = Meter readings from all reciprocating compressor
vents in each and mode, m, in standard cubic feet per hour.
* * * * *
    (q) * * *
* * * * *

[GRAPHIC] [TIFF OMITTED] TP09SE11.013

* * * * *
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 x
10-2 for CO2; for facilities listed in Sec.
98.230(a)(6) and (a)(7), GHGi equals 1 for CH4
and 0 for CO2; and for facilities listed in Sec.
98.230(a)(8), GHGi equals 1 for CH4 and 1.1 x
10-2 CO2.
Tp = The total time the component, p, was found leaking
and operational, in hours. If one leak detection survey is
conducted, assume the component was leaking for the entire calendar
year. If multiple leak detection surveys are conducted, assume that
the component found to be leaking has been leaking since the
previous survey 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 Sec.  98.230(a)(4) and (a)(5), GHGi
equals 0.952 for CH4 and 1.0 x 10-2 for
CO2; for facilities listed in Sec.  98.230(a)(6) and
(a)(7), GHGi equals 1 for CH4 and 0 for
CO2; and for facilities listed in Sec.  98.230(a)(8),
GHGi equals 1 for CH4 and 1.1 x
10-2 CO2.
* * * * *

    (2) * * *
    (i) * * *
    (A) Count all major equipment listed in Table W-1B and Table W-1C