on process knowledge and best available data to estimate the portions
of the total CO2 emissions measured by the CEMS that are
from well completions and workovers with hydraulic fracturing.
    (h) * * *
    (2) If any streams from gas well completions and workovers without
hydraulic fracturing are flared, calculate annual emissions of
CH4, CO2, and N2O as specified in
paragraphs (h)(2)(i) through (v) of this section. If you operate a CEMS
to monitor the emissions from the flare in accordance with paragraph
(n)(8) of this section, calculate emissions as specified in paragraph
(h)(2)(v) of this section instead of the provisions of paragraphs
(h)(2)(i) through (iv) of this section.
    (i) Determine the volume of gas from well completions and workovers
without hydraulic fracturing routed to each flare using any of the
methods specified in paragraph (h)(2)(i)(A) or (B) of this section. You
are not required to use the same method for all streams.
    (A) Use the gas well venting volume during well completions and
workovers without hydraulic fracturing that are flared as determined
using the methods specified in paragraphs (h) and (h)(1) of this
section.
    (B) Measure the flow from well completions and workovers without
hydraulic fracturing to the flare using a continuous flow measurement
device. If the measured volume is in a manifold that combines flow from
well completions and workovers without hydraulic fracturing and other
sources, use engineering calculations based on process knowledge and
best available data to estimate the portion(s) of the total flow (in
scf) from well completions and workovers without hydraulic fracturing.
    (ii) Determine composition of the gas from well completions and
workovers without hydraulic fracturing to each

flare using any of the methods specified in paragraphs (h)(2)(ii)(A)
through (C) of this section. You are not required to use the same
method for all streams.
    (A) Use the gas composition as determined in paragraphs (h)
introductory text and (h)(1) of this section.
    (B) Measure the composition of the gas from well completions and
workovers without hydraulic fracturing to the flare using a continuous
composition analyzer. If the measured composition is in a manifold that
combines streams only from well completions and workovers without
hydraulic fracturing, assume the measured composition applies to all
completions and workovers without hydraulic fracturing that route gas
through the manifold.
    (C) Measure the composition of the total gas to the flare using a
continuous composition analyzer. If the measured composition is in a
manifold that combines flow from well completions and workovers without
hydraulic fracturing and other sources, use engineering calculations
based on available sampling data for other sources, process knowledge,
and best available data to estimate the composition of the flow from
each well completions and workovers without hydraulic fracturing.
    (iii) If you continuously measure flow in accordance with paragraph
(h)(2)(i)(B) of this section and/or continuously measure gas
composition in accordance with paragraph (h)(2)(ii)(B) or (C) of this
section, then those measured data must be used, either directly or
after disaggregating to individual sources, to calculate well
completion and workover from hydraulic fracturing emissions from
flares.
    (iv) Use the calculation method of flare stacks in paragraphs
(n)(3) through (7) of this section to calculate annual emissions from
the flare for gas well venting to a flare during completions and
workovers without hydraulic fracturing.
    (v) If you monitor the flare with CEMS, use the calculation
procedures in paragraph (n)(8) of this section. If the flare receives
gas from multiple well completions and workovers without hydraulic
fracturing or from both well completions and workovers without
hydraulic fracturing and other sources, then use engineering
calculations based on process knowledge and best available data to
estimate the portions of the total CO2 emissions measured by
the CEMS that are from well completions and workovers without hydraulic
fracturing.
    (i) Blowdown vent stacks. Calculate CO2 and
CH4 blowdown vent stack emissions from the depressurization
of equipment to reduce system pressure for planned or emergency
shutdowns resulting from human intervention or to take equipment out of
service for maintenance as specified in either paragraph (i)(2) or (3)
of this section. You may use the method in paragraph (i)(2) of this
section for some blowdown vent stacks at your facility and the method
in paragraph (i)(3) of this section for other blowdown vent stacks at
your facility. Equipment with a unique physical volume of less than 50
cubic feet as determined in paragraph (i)(1) of this section are not
subject to the requirements in paragraphs (i)(2) through (4) of this
section. The requirements in this paragraph (i) do not apply to
blowdown vent stack emissions from depressurizing to a flare, over-
pressure relief, operating pressure control venting, and blowdown of
non-GHG gases.
* * * * *
    (2) Method for determining emissions from blowdown vent stacks
according to equipment or event type. If you elect to determine
emissions according to each equipment or event type, using unique
physical volumes as calculated in paragraph (i)(1) of this section, you
must calculate emissions as specified in paragraph (i)(2)(i) of this
section and either paragraph (i)(2)(ii) of this section or, if
applicable, paragraph (i)(2)(iii) of this section for each equipment or
event type. Categorize equipment and event types for each industry
segment as specified in paragraph (i)(2)(iv) of this section.
    (i) * * *

Ta = Temperature at actual conditions in the unique
physical volume ([deg]F). For emergency blowdowns at onshore
petroleum and natural gas gathering and boosting facilities and
onshore natural gas transmission pipeline facilities, engineering
estimates based on best available information may be used to
determine the temperature.

* * * * *

Pa = Absolute pressure at actual conditions in the unique
physical volume (psia). For emergency blowdowns at onshore petroleum
and natural gas gathering and boosting facilities and onshore
natural gas transmission pipeline facilities, engineering estimates
based on best available information may be used to determine the
pressure.

* * * * *

Ta,p = Temperature at actual conditions in the unique
physical volume ([deg]F) for each blowdown ``p''. For emergency
blowdowns at onshore petroleum and natural gas gathering and
boosting facilities and onshore natural gas transmission pipeline
facilities, engineering estimates based on best available
information may be used to determine the temperature.

* * * * *

Pa,b,p = Absolute pressure at actual conditions in the
unique physical volume (psia) at the beginning of the blowdown
``p''. For emergency blowdowns at onshore petroleum and natural gas
gathering and boosting facilities and onshore natural gas
transmission pipeline facilities, engineering estimates based on
best available information may be used to determine the pressure at
the beginning of the blowdown.

Pa,e,p = Absolute pressure at actual conditions in the
unique physical volume (psia) at the end of the blowdown ``p''; 0 if
blowdown volume is purged using non-GHG gases. For emergency
blowdowns at onshore petroleum and natural gas gathering and
boosting facilities and onshore natural gas transmission pipeline
facilities, engineering estimates based on best available
information may be used to determine the pressure at the end of the
blowdown.

* * * * *
    (iv) Categorize blowdown vent stack emission events as specified in
paragraphs (i)(2)(iv)(A) and (B) of this section, as applicable.
    (A) For the onshore natural gas processing, transmission
compression, LNG import and export equipment, and onshore petroleum and
natural gas gathering and boosting industry segments, equipment or
event types must be grouped into the following seven categories:
Facility piping (i.e., physical volumes associated with piping for
which the entire physical volume is located within the facility
boundary), pipeline venting (i.e., physical volumes associated with
pipelines for which a portion of the physical volume is located outside
the facility boundary and the remainder, including the blowdown vent
stack, is located within the facility boundary), compressors,
scrubbers/strainers, pig launchers and receivers, emergency shutdowns
(this category includes emergency shutdown blowdown emissions
regardless of equipment type), and all other equipment with a physical
volume greater than or equal to 50 cubic feet. If a blowdown event
resulted in emissions from multiple equipment types and the emissions
cannot be apportioned to the different equipment types, then categorize
the blowdown event as the equipment type that represented the largest
portion of the emissions for the blowdown event.
    (B) For the onshore natural gas transmission pipeline segment,
pipeline

segments or event types must be grouped into the following eight
categories: Pipeline integrity work (e.g., the preparation work of
modifying facilities, ongoing assessments, maintenance or mitigation),
traditional operations or pipeline maintenance, equipment replacement
or repair (e.g., valves), pipe abandonment, new construction or
modification of pipelines including commissioning and change of
service, operational precaution during activities (e.g. excavation near
pipelines), emergency shutdowns including pipeline incidents as defined
in 49 CFR 191.3, and all other pipeline segments with a physical volume
greater than or equal to 50 cubic feet. If a blowdown event resulted in
emissions from multiple categories and the emissions cannot be
apportioned to the different categories, then categorize the blowdown
event in the category that represented the largest portion of the
emissions for the blowdown event.
* * * * *
    (j) Onshore production and onshore petroleum and natural gas
gathering and boosting storage tanks. Calculate CH4,
CO2, and N2O (when flared) emissions from
atmospheric pressure fixed roof storage tanks receiving hydrocarbon
produced liquids from onshore petroleum and natural gas production
facilities and onshore petroleum and natural gas gathering and boosting
facilities (including stationary liquid storage not owned or operated
by the reporter), as specified in this paragraph (j). For gas-liquid
separators or onshore petroleum and natural gas gathering and boosting
non-separator equipment (e.g., stabilizers, slug catchers) with annual
average daily throughput of hydrocarbon liquids greater than or equal
to 10 barrels per day, calculate annual CH4 and
CO2 using Calculation Method 1 or 2 as specified in
paragraphs (j)(1) and (2) of this section. For wells flowing directly
to atmospheric storage tanks without passing through a separator with
throughput greater than or equal to 10 barrels per day, calculate
annual CH4 and CO2 emissions using Calculation
Method 2 as specified in paragraph (j)(2) of this section. For
hydrocarbon liquids flowing to gas-liquid separators or non-separator
equipment or directly to atmospheric storage tanks with throughput less
than 10 barrels per day, use Calculation Method 3 as specified in
paragraph (j)(3) of this section. If you use Calculation Method 1 or
Calculation Method 2 for separators, you must also calculate emissions
that may have occurred due to dump valves not closing properly using
the method specified in paragraph (j)(6) of this section. If emissions
from atmospheric pressure fixed roof storage tanks are routed to a
vapor recovery system, you must adjust the emissions downward according
to paragraph (j)(4) of this section. If emissions from atmospheric
pressure fixed roof storage tanks are routed to a flare, you must
calculate CH4, CO2, and N2O annual
emissions as specified in paragraph (j)(5) of this section.
    (1) Calculation Method 1. Calculate annual CH4 and
CO2 emissions from onshore production storage tanks and
onshore petroleum and natural gas gathering and boosting storage tanks
using operating conditions in the last gas-liquid separator or non-
separator equipment before liquid transfer to storage tanks. Calculate
flashing emissions with a software program, such as AspenTech
HYSYS[supreg] or API 4697 E&P Tank, that uses the Peng-Robinson
equation of state, models flashing emissions, and speciates
CH4 and CO2 emissions that will result when the
hydrocarbon liquids from the separator or non-separator equipment enter
an atmospheric pressure storage tank. The following parameters must be
determined for typical operating conditions over the year by
engineering estimate and process knowledge based on best available
data, and must be used at a minimum to characterize emissions from
liquid transferred to tanks:
* * * * *
    (iii) Sales oil or stabilized hydrocarbon liquids API gravity.
    (iv) Sales oil or stabilized hydrocarbon liquids production rate.
* * * * *
    (vii) Separator or non-separator equipment hydrocarbon liquids
composition and Reid vapor pressure. If this data is not available,
determine these parameters by using one of the methods described in
paragraphs (j)(1)(vii)(A) through (C) of this section.
    (A) If separator or non-separator equipment hydrocarbon liquid
composition and Reid vapor pressure default data are provided with the
software program, select the default values that most closely match
your separator or non-separator equipment pressure first, and API
gravity secondarily.
    (B) If separator or non-separator equipment hydrocarbon liquids
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 for onshore petroleum and natural gas production or from the
county for onshore petroleum and natural gas gathering and boosting.
    (C) Analyze a representative sample of separator or non-separator
equipment hydrocarbon liquids in each sub-basin category for onshore
petroleum and natural gas production or each county for onshore
petroleum and natural gas gathering and boosting for hydrocarbon
liquids composition and Reid vapor pressure using an appropriate
standard method published by a consensus-based standards organization.
    (2) Calculation Method 2. Calculate annual CH4 and
COCO2 emissions using the methods in paragraph (j)(2)(i) of
this section for gas-liquid separators with annual average daily
throughput of hydrocarbon liquids greater than or equal to 10 barrels
per day. Calculate annual CH4 and COCO2 emissions
using the methods in paragraph (j)(2)(ii) of this section for wells
with annual average daily hydrocarbon liquids production greater than
or equal to 10 barrels per day that flow directly to atmospheric
storage tanks in onshore petroleum and natural gas production and
onshore petroleum and natural gas gathering and boosting (if
applicable). Calculate annual CH4 and COCO2
emissions using the methods in paragraph (j)(2)(iii) of this section
for non-separator equipment with annual average daily hydrocarbon
liquids throughput greater than or equal to 10 barrels per day that
flow directly to atmospheric storage tanks in onshore petroleum and
natural gas gathering and boosting.
    (i) Flow to storage tank after passing through a separator. Assume
that all of the CH4 and COCO2 in solution at
separator temperature and pressure is emitted from hydrocarbon liquids
sent to storage tanks. You may use an appropriate standard method
published by a consensus-based standards organization if such a method
exists or you may use an industry standard practice as described in
Sec.  98.234(b) to sample and analyze separator hydrocarbon liquids
composition at separator pressure and temperature.
    (ii) Flow to storage tank direct from wells. Calculate
CH4 and COCO2 emissions using either of the
methods in paragraph (j)(2)(ii)(A) or (B) of this section.
    (A) If well production hydrocarbon liquids and gas compositions are
available through a previous analysis, select the latest available
analysis that is representative of produced hydrocarbon liquids and gas
from the sub-basin category and assume all of the CH4 and CO2 in both
hydrocarbon liquids and gas are emitted from the tank.

    (B) If well production hydrocarbon liquids and gas compositions are
not available, use default hydrocarbon liquids and gas compositions in
software programs, such as API 4697 E&P Tank, that most closely match
the well production gas/oil ratio and API gravity and assume all of the
CH4 and CO2 in both hydrocarbon liquids and gas are emitted from the
tank.
    (iii) Flow to storage tank direct from non-separator equipment.
Calculate CH4 and CO2 emissions using either of the methods in
paragraph (j)(2)(iii)(A) or (B) of this section.
    (A) If other non-separator equipment hydrocarbon liquids and gas
compositions are available through a previous analysis, select the
latest available analysis that is representative of hydrocarbon liquids
and gas from non-separator equipment in the same county and assume all
of the CH4 and CO2 in both hydrocarbon liquids and gas are emitted from
the tank.
    (B) If non-separator equipment hydrocarbon liquids and gas
compositions are not available, use default hydrocarbon liquids and gas
compositions in software programs, such as API 4697 E&P Tank, that most
closely match the non-separator equipment gas/liquid ratio and API
gravity and assume all of the CH4 and CO2 in both hydrocarbon liquids
and gas are emitted from the tank.
    (3) * * *

Count = Total number of separators, wells, or non-separator
equipment with annual average daily throughput less than 10 barrels
per day. Count only separators, wells, or non-separator equipment
that feed hydrocarbon liquids directly to the storage tank.
* * * * *
    (4) If the storage tank receiving your hydrocarbon liquids has a
vapor recovery system, calculate annual emissions from storage tanks as
specified in paragraphs (j)(4)(i) and (ii) of this section.
    (i) Using engineering estimates based on best available data,
determine the portion of the total emissions estimated in paragraphs
(j)(1) through (3) of this section that is recovered using a vapor
recovery system. You must take into account periods with reduced
capture efficiency of the vapor recovery system (e.g., when a thief
hatch is open or not properly seated) when calculating emissions
recovered.
    (ii) Determine total emissions not recovered by a vapor recovery
system as specified in paragraphs (j)(4)(ii)(A) and (B) of this
section.
    (A) Adjust the emissions estimated in paragraphs (j)(1) through (3)
of this section downward by the magnitude of emissions recovered using
a vapor recovery system and by the amount of emissions routed to
flares. Unrecovered emissions may include, but are not limited to,
emissions during periods when the vapor recovery system is not
operating, losses from the tank when the vapor recovery system is not
operating and the tank is connected to a flare, and losses from the
tank during periods when the vapor recovery system is operating. These
losses may include, but are not limited to, emissions due to open or
unseated thief hatches. Report unrecovered emissions that are not
routed to flares as emissions vented directly to the atmosphere.
    (B) If unrecovered emissions from atmospheric tanks are routed to
flares, determine the volume of gas routed to flares, calculate annual
emissions from flares as specified in paragraphs (j)(5)(i) through
(iii) of this section, and report as flared emissions from atmospheric
tanks.
    (5) If the storage tank receiving your hydrocarbon liquids has a
flare(s), calculate annual flared emissions from storage tanks as
specified in paragraphs (j)(5)(i) through (v) of this section and
calculate emissions vented directly to the atmosphere as specified in
paragraph (j)(5)(vi) of this section. For atmospheric tanks with
emissions calculated using Calculation Method 3 in paragraph (j)(3) of
this section, this paragraph (j)(5) only applies when at least half of
the hydrocarbon liquids flowing to gas-liquid separators or non-
separator equipment or directly to atmospheric storage tanks are
directed to atmospheric tanks that used flares to control emissions. If
you operate a CEMS to monitor the emissions from the flare in
accordance with paragraph (n)(8) of this section, calculate emissions
as specified in paragraph (j)(5)(v) of this section instead of the
provisions of paragraphs (j)(5)(i) through (iv) of this section.
    (i) Estimate the volume routed to the flare using any of the
methods specified in paragraph (j)(5)(i)(A) or (B) of this section. You
are not required to use the same method for all storage tanks.
    (A) If unrecovered emissions from the storage tank are calculated
in accordance with paragraph (j)(4) of this section, then determine the
volume of the unrecovered emissions routed to flares based on best
available data. If no emissions from the storage tank are routed to
vapor recovery, then use the storage tank emissions volume as
determined in paragraphs (j)(1) through (3) of this section, except
that you must also adjust this total volume of emissions downward by
the estimated portion of the total volume that is not routed to the
flare (e.g., when the flare is bypassed or when a thief hatch is open
or not properly seated). Estimate the volume of the emissions not
routed to flares based on best available data.
    (B) Measure the flow from the storage tank(s) to the flare using a
continuous flow measurement device. If the measured volume is in a
manifold that combines flow from storage tanks and other sources, use
engineering calculations based on process knowledge and best available
data to estimate the portion(s) of the total flow (in scf) from each
storage tank.
    (ii) Except as specified in paragraph (j)(5)(iii) of this section,
determine the composition of the gas from the storage tanks routed to
the flare using any of the methods specified in paragraphs
(j)(5)(ii)(A) through (C) of this section. You are not required to use
the same method for all storage tanks.
    (A) If you use Calculation Method 1 or Calculation Method 2, use
your gas composition as determined in paragraphs (j)(1) and (2) of this
section. If you use Calculation Method 3 in paragraph (j)(3) of this
section, determine the gas composition using either engineering
estimates based on best available data or the procedures specified in
paragraph (u)(2)(i) of this section.
    (B) Measure the composition of the gas from the storage tanks to
the flare using a continuous gas composition analyzer. If the measured
composition is in a manifold that combines streams only from multiple
storage tanks, assume the measured composition applies to all storage
tanks that route gas through the manifold.
    (C) Measure the composition of the total gas to the flare using a
continuous composition analyzer. If the measured composition is in a
manifold that combines flow from storage tanks and other sources, use
engineering calculations based on available sampling data for other
sources, process knowledge, and best available data to estimate the
composition of the flow from storage tanks.
    (iii) If you continuously measure flow in accordance with paragraph
(j)(5)(i)(B) of this section and/or continuously measure gas
composition in accordance with paragraph (j)(5)(ii)(B) or (C) of this
section, then those measured data must be used, either directly or
after disaggregating to individual sources, to calculate storage tank
emissions from flares.
    (iv) Use the calculation method of flare stacks in paragraphs
(n)(3) through (7) of this section with the volume and composition
determined according to paragraphs (j)(5)(i) and (ii) of this

section to determine storage tank emissions from the flare.
    (v) If you monitor the flare with CEMS, use the calculation
procedures in paragraph (n)(8) of this section. If the flare receives
gas from both storage tanks and other sources, then use engineering
calculations based on process knowledge and best available data to
estimate the portions of the total CO2 emissions measured by
the CEMS that are from storage tanks.
    (vi) For storage tanks with no vapor recovery system, if the volume
routed to the flare as determined in paragraph (j)(5)(i)(A) or (B) of
this section is less than the total volume of emissions from the tank
as estimated in paragraphs (j)(1) through (3) of this section, then use
the volume not sent to the flare to calculate emissions of flash gas
vented directly to the atmosphere from the storage tank.
    (6) If you use Calculation Method 1 or Calculation Method 2 in
paragraph (j)(1) or (2) of this section, calculate emissions from
occurrences of gas-liquid separator liquid dump valves not closing
during the calendar year by using Equation W-16 of this section.
[GRAPHIC] [TIFF OMITTED] TP21JN22.044

Where:

Es,i,dv = Annual volumetric GHG emissions (either
CO2 or CH4) at standard conditions in cubic
feet from storage tanks that resulted from the dump valve on the
gas-liquid separator not closing properly.
Es,i = Annual volumetric GHG emissions (either
CO2 or CH4) as determined in paragraphs (j)(1)
and (2) and, if applicable, (j)(4) and (5) of this section, in
standard cubic feet per year, from storage tanks with dump valves on
an associated gas-liquid separator that did not close properly.
Tdv = Total time a dump valve is not closing properly in
the calendar year in hours. Estimate Tdv based on
maintenance, operations, or routine separator inspections that
indicate the period of time when the valve was malfunctioning in
open or partially open position.
CFdv = Correction factor for tank emissions for time
period Tdv is 2.87 for crude oil production. Correction
factor for tank emissions for time period Tdv is 4.37 for
gas condensate production.
8,760 = Conversion to hourly emissions.
* * * * *
    (k) * * *
    (5) If any transmission storage tanks are routed to flares,
calculate emissions for the flare stack as specified in paragraph (n)
of this section and report emissions from the flare as specified in
Sec.  98.236(n), without subtracting emissions attributable to
transmission tanks from the flare. If the volume to the flare is not
continuously measured for the duration of time that flaring occurred,
then conduct an annual leak measurement as specified in paragraph
(k)(1)(ii) or (iv) of this section. If a leak is detected, quantify the
leak in accordance with paragraph (k)(2)(i) or (ii) of this section and
determine the time leaking as specified in paragraph (k)(3) of this
section. Use these data when estimating total flow to the flare in
accordance with paragraph (n)(1) of this section.
    (l) * * *
    (6) If any emissions from well testing are routed to a flare,
calculate flared emissions from well testing as specified in paragraphs
(l)(6)(i) through (v) of this section. If you operate a CEMS to monitor
the emissions from the flare in accordance with paragraph (n)(8) of
this section, calculate emissions as specified in paragraph (l)(6)(v)
of this section instead of the provisions of paragraphs (l)(6)(i)
through (iv) of this section.
    (i) Determine the volume of gas from well testing to each flare
using any of the methods specified in paragraph (l)(6)(i)(A) or (B) of
this section. You are not required to use the same method for all well
testing.
    (A) Use the well testing emissions volume as determined in
paragraphs (l)(1) through (4) of this section.
    (B) Measure the flow from well testing to the flare using a
continuous flow measurement device. If the measured volume is in a
manifold that combines flow from well testing and other sources, use
engineering calculations based on process knowledge and best available
data to estimate the portion(s) of the total flow (in scf) from well
testing.
    (ii) Except as specified in paragraph (l)(6)(iii) of this section,
determine composition of the gas from well testing to each flare using
any of the methods specified in paragraphs (l)(6)(ii)(A) through (C) of
this section. You are not required to use the same method for all well
testing.
    (A) Use the gas composition as determined in paragraphs (l)(1)
through (4) of this section.
    (B) Measure the composition of gas from well testing to the flare
using a continuous composition analyzer. If the measured composition is
in a manifold that combines streams only from testing of multiple
wells, assume the measured composition applies to all well testing gas
routed through the manifold.
    (C) Measure the composition of the total gas to the flare using a
continuous composition analyzer. If the measured composition is in a
manifold that combines flow from well testing and other sources, use
engineering calculations based on available sampling data for other
sources, process knowledge, and best available data to estimate the
composition of the flow from well testing.
    (iii) If you continuously measure flow in accordance with paragraph
(l)(6)(i)(B) of this section and/or continuously measure gas
composition in accordance with paragraph (l)(6)(ii)(B) or (C) of this
section, then those measured data must be used, either directly or
after disaggregating to individual sources, to calculate well testing
emissions from flares.
    (iv) Use the calculation method of flare stacks in paragraphs
(n)(3) through (7) of this section to determine annual well testing
emissions from the flare.
    (v) If you monitor the flare with CEMS, use the calculation
procedures in paragraph (n)(8) of this section. If the flare receives
gas from both well testing and other sources, then use engineering
calculations based on process knowledge and best available data to
estimate the portions of the total CO2 emissions measured by
the CEMS that are from well testing.
    (m) * * *
    (3) Estimate venting emissions using Equation W-18 of this section.
Alternatively, if you measure the flow to a vent using a continuous
flow measurement device, you must use the measured flow volumes to
calculate vented associated gas emissions.
* * * * *
Vp,q = Volume of oil produced, for well p in sub-basin q,
in barrels in the calendar year only during time periods in which
associated gas was vented or flared.
SGp,q = Volume of associated gas sent to sales, for well
p in sub-basin q, in standard cubic feet of gas in the calendar year
only during time periods in which associated gas was vented or
flared.
* * * * *
    (5) Calculate flared associated natural gas emissions as specified
in paragraphs (m)(5)(i) through (v) of this section. If you operate a
CEMS to monitor the emissions from the flare in accordance

with paragraph (n)(8) of this section, calculate emissions as specified
in paragraph (m)(5)(v) of this section instead of the provisions of
paragraphs (m)(5)(i) through (iv) of this section.
    (i) Determine the volume of associated gas to each flare using any
of the methods specified in paragraph (m)(5)(i)(A) or (B) of this
section. You are not required to use the same method for all associated
gas streams.
    (A) Use the associated natural gas volume as determined in
paragraphs (m)(1) through (4) of this section.
    (B) Measure the flow of associated gas to the flare using a
continuous flow measurement device. If the measured volume is in a
manifold that combines flow from multiple associated gas streams or
from associated gas streams and other sources, use engineering
calculations based on process knowledge and best available data to
estimate the portions of the total flow (in scf) that is associated
gas.
    (ii) Except as specified in paragraph (m)(5)(iii) of this section,
determine composition of the associated gas to each flare using any of
the methods specified in paragraphs (m)(5)(ii)(A) through (C) of this
section. You are not required to use the same method for all associated
gas streams.
    (A) Use the associated gas composition as determined in paragraphs
(m)(1) through (4) of this section.
    (B) Measure the composition of the associated gas to the flare
using a continuous composition analyzer. If the measured composition is
in a manifold that combines only associated gas streams, assume the
measured composition applies to all associated gas that is routed
through the manifold.
    (C) Measure the composition of the total gas to the flare using a
continuous composition analyzer. If the measured composition is in a
manifold that combines both associated gas and gas from other sources,
use engineering calculations based on available sampling data for other
sources, process knowledge, and best available data to estimate the
composition of the associated gas in the combined stream.
    (iii) If you continuously measure flow in accordance with paragraph
(m)(5)(i)(B) of this section and/or continuously measure gas
composition in accordance with paragraph (m)(5)(ii)(B) or (C) of this
section, then those measured data must be used, either directly or
after disaggregating to individual sources, to calculate associated gas
emissions from flares.
    (iv) Use the calculation method of flare stacks in paragraphs
(n)(3) through (7) of this section to calculate annual associated gas
emissions from flares.
    (v) If you monitor the flare with CEMS, use the calculation
procedures in paragraph (n)(8) of this section. If the flare receives
both associated gas and gas from other sources, then use engineering
calculations based on process knowledge and best available data to
estimate the portions of the total CO2 emissions measured by
the CEMS that are from associated gas.
    (n) Flare stack emissions. As applicable for the industry segment,
use the procedures in paragraphs (n)(3) through (9) of this section to
calculate CO2, CH4, and N2O emissions
per flare stack separately from dehydrators as specified in paragraph
(e)(5) of this section, completions and workovers with hydraulic
fracturing as specified in paragraph (g)(4) of this section,
completions and workovers without hydraulic fracturing as specified in
paragraph (h)(2) of this section, atmospheric tanks as specified in
paragraph (j)(5) of this section, well testing as specified in
paragraph (l)(6) of this section, and associated gas as specified in
paragraph (m)(5) of this section. Also use the procedures specified in
paragraphs (n)(1) through (9) of this section to calculate the
collective emissions per flare stack from all miscellaneous flared
sources (i.e., sources that are not subject to source-specific flared
emissions reporting for your industry segment).
    (1) If you have a continuous flow measurement device on gas to the
flare, you must use the measured flow volumes to calculate the flare
gas emissions from miscellaneous flared sources. If all of the flare
gas is not measured by the existing flow measurement device, then the
flow not measured can be estimated using engineering calculations based
on best available data. If you do not have a continuous flow
measurement device on gas to the flare, or if a continuous flow
measurement device measures a stream that combines flow from sources
that are subject to source-specific flared emissions reporting as well
as flow from miscellaneous flared sources, you can use engineering
calculations based on process knowledge and best available data to
estimate the flow from the miscellaneous flared sources. Best available
data also includes the procedures specified in paragraphs (e)(5),
(g)(4), (h)(2), (j)(5), (k)(5), (l)(6), and (m)(5) of this section. If
a continuous flow measurement device is not installed on an AGR that is
routed to a flare, the volumetric CO2 emissions calculated
using AGR Calculation Method 3 or 4 and paragraph (d)(9) of this
section must be incorporated into the parameter Vs in
Equation W-20 to account for the AGR portion of the total flared
CO2 emissions.
    (2) If you have a continuous gas composition analyzer on gas to the
flare, you must use these compositions in calculating emissions from
miscellaneous flared sources, except when the measured stream to the
flare includes emissions from an AGR unit that are comingled with
emissions from other sources. If you do not have a continuous gas
composition analyzer on gas to the flare, or if the stream to the flare
consists of AGR emissions that are comingled with emissions from other
sources, you must use the appropriate gas compositions for each stream
of hydrocarbons going to the flare from an emission source other than
an AGR vent as specified in paragraphs (n)(2)(i) through (iii) of this
section. For emissions from AGR vents that do not have a continuous gas
composition analyzer, you may use either site-specific engineering
estimates based on best available data or a default CO2 mole
fraction of 1.
* * * * *
    (5) Calculate GHG volumetric emissions from flaring at standard
conditions using Equations W-19 and W-20 of this section. Emissions may
be calculated per stream routed to the flare and then summed over all
streams per emissions source type. Alternatively, you may sum the total
volume of all streams from a particular emission source type, determine
the flow-weighted average CO2 and hydrocarbon concentrations
over all streams per source type, and then perform a single calculation
using Equation W-19 and a single calculation using Equation W-20 to
calculate the total CH4 and CO2 emissions per
source type.
[GRAPHIC] [TIFF OMITTED] TP21JN22.045

[GRAPHIC] [TIFF OMITTED] TP21JN22.046

Where:

Es,CH4 = Annual CH4 emissions per emission
source type from flare stack in cubic feet, at standard conditions.
Es,CO2 = Annual CO2 emissions per emission
source type from flare stack in cubic feet, at standard conditions.
Vs = Volume of gas sent to flare per emission source type
in standard cubic feet, during the year as determined in paragraph
(e)(5)(i), (g)(4)(i), (h)(2)(i), (j)(5)(i), (l)(6)(i), (m)(5)(i), or
(n)(1) of this section.
[eta] = Flare combustion efficiency, expressed as fraction of gas
combusted by a burning flare (default is 0.98).
XCH4 = Mole fraction of CH4 in the feed gas to
the flare per emission source type as determined in paragraph
(e)(5)(ii), (g)(4)(ii), (h)(2)(ii), (j)(5)(ii), (l)(6)(ii),
(m)(5)(ii), or (n)(2) of this section. Use a flow-weighted mole
fraction if multiple streams from the same source type are combined
for the emissions calculation.
XCO2 = Mole fraction of CO2 in the feed gas to
the flare per emission source type as determined in paragraph
(e)(5)(ii), (g)(4)(ii), (h)(2)(ii), (j)(5)(ii), (l)(6)(ii),
(m)(5)(ii), or (n)(2) of this section. Use a flow-weighted mole
fraction if multiple streams from the same source type are combined
for the emissions calculation.
ZU = Fraction of the feed gas sent to an un-lit flare per
emission source type determined by engineering estimate and process
knowledge based on best available data and operating records.
ZL = Fraction of the feed gas sent to a burning flare per
emission source type (equal to 1 - ZU).
Yj = Mole fraction of hydrocarbon constituents j (such as
methane, ethane, propane, butane, and pentanes-plus) in the feed gas
to the flare per emissions source type as determined in paragraph
(e)(5)(ii), (g)(4)(ii), (h)(2)(ii), (j)(5)(ii), (l)(6)(ii),
(m)(5)(ii), or (n)(2) of this section.
Rj = Number of carbon atoms in the hydrocarbon
constituent j in the feed gas to the flare per emission source type:
1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for
pentanes-plus).
* * * * *
    (o) Centrifugal compressor venting. If you are required to report
emissions from centrifugal compressor venting as specified in Sec.
98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct
volumetric emission measurements specified in paragraph (o)(1) of this
section using methods specified in paragraphs (o)(2) through (5) of
this section; perform calculations specified in paragraphs (o)(6)
through (9) of this section; and calculate CH4 and
CO2 mass emissions as specified in paragraph (o)(11) of this
section. If you are required to report emissions from centrifugal
compressor venting at an onshore petroleum and natural gas production
facility as specified in Sec.  98.232(c)(19) or an onshore petroleum
and natural gas gathering and boosting facility as specified in Sec.
98.232(j)(8), you must calculate volumetric emissions as specified in
paragraph (o)(10); and calculate CH4 and CO2 mass
emissions as specified in paragraph (o)(11). If emissions from a
compressor source are routed to a flare, paragraphs (o)(1) through (11)
do not apply and instead you must calculate CH4,
CO2, and N2O emissions as specified in paragraph
(o)(12) of this section. If emissions from a compressor source are
routed to combustion, paragraphs (o)(1) through (12) do not apply and
instead you must calculate and report emissions as specified in subpart
C of this part or paragraph (z) of this section, as applicable. If
emissions from a compressor source are routed to vapor recovery,
paragraphs (o)(1) through (12) do not apply.
    (1) * * *
    (i) Centrifugal compressor source as found measurements. Measure
venting from each compressor according to either paragraph
(o)(1)(i)(A), (B), or (C) of this section at least once annually, based
on the compressor mode (as defined in Sec.  98.238) in which the
compressor was found at the time of measurement, except as specified in
paragraph (o)(1)(i)(D) of this section. If additional measurements
beyond the required annual testing are performed (including duplicate
measurements or measurement of additional operating modes), then all
measurements satisfying the applicable monitoring and QA/QC that is
required by this paragraph (o) must be used in the calculations
specified in this section.
    (A) For a compressor measured in operating-mode, you must measure
volumetric emissions from blowdown valve leakage through the blowdown
vent as specified in paragraph (o)(2)(i) of this section, measure
volumetric emissions from wet seal oil degassing vents as specified in
paragraph (o)(2)(ii) of this section if the compressor has wet seal oil
degassing vents, and measure volumetric emissions from dry seal vents
as specified in paragraph (o)(2)(iii) of this section if the compressor
has dry seals.
    (B) For a compressor measured in not-operating-depressurized-mode,
you must measure volumetric emissions from isolation valve leakage as
specified in paragraph (o)(2)(i) of this section. If a compressor is
not operated and has blind flanges in place throughout the reporting
period, measurement is not required in this compressor mode.
    (C) For a compressor measured in standby-pressurized-mode, you must
measure volumetric emissions from blowdown valve leakage through the
blowdown vent as specified in paragraph (o)(2)(i) of this section,
measure volumetric emissions from wet seal oil degassing vents as
specified in paragraph (o)(2)(ii) of this section if the compressor has
wet seal oil degassing vents, and measure volumetric emissions from dry
seal vents as specified in paragraph (o)(2)(iii) of this section if the
compressor has dry seals.
* * * * *
    (2) Methods for performing as found measurements from individual
centrifugal compressor sources. If conducting measurements for each
compressor source, you must determine the volumetric emissions from
blowdown valves and isolation valves as specified in paragraph
(o)(2)(i) of this section, the volumetric emissions from wet seal oil
degassing vents as specified in paragraph (o)(2)(ii) of this section,
and the volumetric emissions from dry seal vents as specified in
paragraph (o)(2)(iii) of this section.
    (i) For blowdown valves on compressors in operating-mode or in
standby-pressurized-mode and for isolation valves on compressors in
not-operating-depressurized-mode, determine the volumetric emissions
using one of the methods specified in paragraphs (o)(2)(i)(A) through
(D) of this section.
* * * * *
    (ii) For wet seal oil degassing vents in operating-mode or in
standby-pressurized-mode, determine volumetric flow at standard
conditions, using one of the methods specified in paragraphs
(o)(2)(ii)(A) through (C) of this section. You must quantitatively
measure the volumetric flow for wet seal oil degassing vent; you may
not use screening methods set forth in Sec.  98.234(a) to screen for
emissions for the wet seal oil degassing vent.
    (A) Use a temporary meter such as a vane anemometer or permanent
flow meter according to methods set forth in Sec.  98.234(b).
    (B) Use calibrated bags according to methods set forth in Sec.
98.234(c).

    (C) Use a high volume sampler according to methods set forth in
Sec.  98.234(d).
    (iii) For dry seal vents in operating-mode or in standby-
pressurized-mode, determine volumetric flow at standard conditions from
each dry seal vent using one of the methods specified in paragraphs
(o)(2)(ii)(A) through (D) of this section. If a compressor has more
than one dry seal vent, determine the aggregate dry seal vent
volumetric flow for the compressor as the sum of the volumetric flows
determined for each dry seal vent on the compressor.
    (A) Use a temporary meter such as a vane anemometer or permanent
flow meter according to methods set forth in Sec.  98.234(b).
    (B) Use calibrated bags according to methods set forth in Sec.
98.234(c).
    (C) Use a high volume sampler according to methods set forth in
Sec.  98.234(d).
    (D) You may choose to use any of the methods set forth in Sec.
98.234(a)(1) through (3) to screen for emissions. If emissions are
detected using one of these specified methods, then you must use one of
the methods specified in paragraph (o)(2)(iii)(A) through (C) of this
section. If emissions are not detected using the methods in Sec.
98.234(a)(1) through (3), then you may assume that the volumetric
emissions are zero. For the purposes of this paragraph, when using any
of the methods in Sec.  98.234(a), emissions are detected whenever a
leak is detected according to the methods. Acoustic leak detection is
only applicable for through-valve leakage and is not applicable for
screening dry seal vents.
* * * * *
    (4) * * *
    (ii) * * *
    (E) You may choose to use any of the methods set forth in Sec.
98.234(a)(1) through (3) to screen for emissions. If emissions are
detected using one of these methods, then you must use one of the
methods specified in paragraph (o)(4)(ii)(A) through (D) of this
section. If emissions are not detected using the methods in Sec.
98.234(a)(1) through (3), then you may assume that the volumetric
emissions are zero. For the purposes of this paragraph, when using any
of the methods in Sec.  98.234(a), emissions are detected whenever a
leak is detected according to the method. Acoustic leak detection is
only applicable for through-valve leakage and is not applicable for
screening a manifolded group of compressor sources.
* * * * *
    (6) * * *
    (i) Using Equation W-21 of this section, calculate the annual
volumetric GHG emissions for each centrifugal compressor mode-source
combination specified in paragraphs (o)(1)(i)(A) through (C) of this
section that was measured during the reporting year.
* * * * *
m = Compressor mode-source combination specified in paragraph
(o)(1)(i)(A), (B), or (C) of this section that was measured for the
reporting year.

    (ii) Using Equation W-22 of this section, calculate the annual
volumetric GHG emissions from each centrifugal compressor mode-source
combination specified in paragraphs (o)(1)(i)(A) through (C) of this
section that was not measured during the reporting year.
* * * * *
m = Compressor mode-source combination specified in paragraph
(o)(1)(i)(A), (B), or (C) of this section that was not measured in
the reporting year.

    (iii) Using Equation W-23 of this section, develop an emission
factor for each compressor mode-source combination specified in
paragraphs (o)(1)(i)(A) through (C) of this section. These emission
factors must be calculated annually and used in Equation W-22 of this
section to determine volumetric emissions from a centrifugal compressor
in the mode-source combinations that were not measured in the reporting
year.
* * * * *
m = Compressor mode-source combination specified in paragraph
(o)(1)(i)(A), (B), or (C) of this section.
* * * * *
    (8) * * *
Tg = Total time the manifolded group of compressor sources g had
potential for emissions in the reporting year, in hours. Include all
time during which at least one compressor source in the manifolded
group of compressor sources g was in a mode-source combination
specified in either paragraph (o)(1)(i)(A), (o)(1)(i)(B),
(o)(1)(i)(C), (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this
section. Default of 8760 hours may be used.
* * * * *
    (10) Method for calculating volumetric GHG emissions from wet seal
oil degassing vents at an onshore petroleum and natural gas production
facility or an onshore petroleum and natural gas gathering and boosting
facility. You must calculate emissions from atmospheric centrifugal
compressor wet seal oil degassing vents at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility using Equation W-25 of this section.
Emissions from centrifugal compressor wet seal oil degassing vents that
are routed to a flare, combustion, or vapor recovery are not required
to be determined under this paragraph (o).
* * * * *
Count = Total number of centrifugal compressors that have wet seal
oil degassing vents that are vented to the atmosphere.
* * * * *
    (p) Reciprocating compressor venting. If you are required to report
emissions from reciprocating compressor venting as specified in Sec.
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct
volumetric emission measurements specified in paragraph (p)(1) of this
section using methods specified in paragraphs (p)(2) through (5) of
this section; perform calculations specified in paragraphs (p)(6)
through (9) of this section; and calculate CH4 and CO2 mass emissions
as specified in paragraph (p)(11) of this section. If you are required
to report emissions from reciprocating compressor venting at an onshore
petroleum and natural gas production facility as specified in Sec.
98.232(c)(11) or an onshore petroleum and natural gas gathering and
boosting facility as specified in Sec.  98.232(j)(5), you must
calculate volumetric emissions as specified in paragraph (p)(10); and
calculate CH4 and CO2 mass emissions as specified in paragraph (p)(11).
If emissions from a compressor source are routed to a flare, paragraphs
(p)(1) through (11) do not apply and instead you must calculate CH4,
CO2, and N2O emissions as specified in paragraph (p)(12) of this
section. If emissions from a compressor source are routed to
combustion, paragraphs (p)(1) through (12) do not apply and instead you
must calculate and report emissions as specified in subpart C of this
part or paragraph (z) of this section, as applicable. If emissions from
a compressor source are routed to vapor recovery, paragraphs (p)(1)
through (12) do not apply.
    (1) * * *
    (i) Reciprocating compressor source as found measurements. Measure
venting from each compressor according to either paragraph
(p)(1)(i)(A), (B), or (C) of this section at least once annually, based
on the compressor mode (as defined in Sec.  98.238) in which the
compressor was found at the time of measurement, except as specified in
paragraph (p)(1)(i)(D) of this section. If additional measurements
beyond the required annual testing are performed (including duplicate
measurements or measurement of additional operating modes), then all
measurements satisfying the applicable monitoring and QA/QC that is
required by this

paragraph (p) must be used in the calculations specified in this
section.
    (A) For a compressor measured in operating-mode, you must measure
volumetric emissions from blowdown valve leakage through the blowdown
vent as specified in paragraph (p)(2)(i) of this section, and measure
volumetric emissions from reciprocating rod packing as specified in
paragraph (p)(2)(ii) or (iii) of this section, as applicable.
    (B) For a compressor measured in not-operating-depressurized-mode,
you must measure volumetric emissions from isolation valve leakage as
specified in paragraph (p)(2)(i) of this section. If a compressor is
not operated and has blind flanges in place throughout the reporting
period, measurement is not required in this compressor mode.
    (C) For a compressor measured in standby-pressurized-mode, you must
measure volumetric emissions from blowdown valve leakage through the
blowdown vent as specified in paragraph (p)(2)(i) of this section and
measure volumetric emissions from reciprocating rod packing as
specified in paragraph (p)(2)(ii) or (iii) of this section, as
applicable.
    (D) An annual as found measurement is not required in the first
year of operation for any new compressor that begins operation after as
found measurements have been conducted for all existing compressors.
For only the first year of operation of new compressors, calculate
emissions according to paragraph (p)(6)(ii) of this section.
* * * * *
    (2) Methods for performing as found measurements from individual
reciprocating compressor sources. If conducting measurements for each
compressor source, you must determine the volumetric emissions from
blowdown valves and isolation valves as specified in paragraph
(p)(2)(i) of this section. You must determine the volumetric emissions
from reciprocating rod packing as specified in paragraph (p)(2)(ii) or
(iii) of this section, as applicable.
* * * * *
    (ii) For reciprocating rod packing equipped with an open-ended vent
line on compressors in operating-mode or standby-pressurized-mode,
determine the volumetric emissions using one of the methods specified
in paragraphs (p)(2)(ii)(A) through (C) of this section.
* * * * *
    (C) You may choose to use any of the methods set forth in Sec.
98.234(a)(1) through (3) to screen for emissions. If emissions are
detected using one of these specified methods, then you must use one of
the methods specified in paragraph (p)(2)(ii)(A) and (B) of this
section. If emissions are not detected using the methods in Sec.
98.234(a)(1) through (3), then you may assume that the volumetric
emissions are zero. For the purposes of this paragraph (p)(2)(ii)(C),
when using any of the methods in Sec.  98.234(a), emissions are
detected whenever a leak is detected according to the method. Acoustic
leak detection is only applicable for through-valve leakage and is not
applicable for screening or measuring rod packing emissions.
    (iii) * * *
    (A) You must use the methods described in Sec.  98.234(a)(1)
through (3) to conduct annual leak detection of equipment leaks from
the packing case into an open distance piece, or for compressors with a
closed distance piece, conduct annual detection of gas emissions from
the rod packing vent, distance piece vent, compressor crank case
breather cap, or other vent emitting gas from the rod packing. Acoustic
leak detection is only applicable for through-valve leakage and is not
applicable for screening rod packing emissions.
* * * * *
    (4) * * *
    (ii) * * *
    (C) A high volume sampler according to methods set forth in Sec.
98.234(d).
* * * * *
    (E) You may choose to use any of the methods set forth in Sec.
98.234(a)(1) through (3) to screen for emissions. If emissions are
detected using one of these specified methods, then you must use one of
the methods specified in paragraph (p)(4)(ii)(A) through (D) of this
section. If emissions are not detected using the methods in Sec.
98.234(a)(1) through (3), then you may assume that the volumetric
emissions are zero. For the purposes of this paragraph, when using any
of the methods in Sec.  98.234(a), emissions are detected whenever a
leak is detected according to the method. Acoustic leak detection is
only applicable for through-valve leakage and is not applicable for
screening a manifolded group of compressor sources.
* * * * *
    (6) * * *
    (ii) Using Equation W-27 of this section, calculate the annual
volumetric GHG emissions from each reciprocating compressor mode-source
combination specified in paragraphs (p)(1)(i)(A) through (C) of this
section that was not measured during the reporting year.
* * * * *
    (iii) Using Equation W-28 of this section, develop an emission
factor for each compressor mode-source combination specified in
paragraphs (p)(1)(i)(A) through (C) of this section. These emission
factors must be calculated annually and used in Equation W-27 of this
section to determine volumetric emissions from a reciprocating
compressor in the mode-source combinations that were not measured in
the reporting year.
* * * * *
    (10) Method for calculating volumetric GHG emissions from
reciprocating compressor venting at an onshore petroleum and natural
gas production facility or an onshore petroleum and natural gas
gathering and boosting facility. You must calculate emissions from
reciprocating compressor atmospheric venting of rod packing emissions
at an onshore petroleum and natural gas production facility or an
onshore petroleum and natural gas gathering and boosting facility using
Equation W-29D of this section. Reciprocating compressor rod packing
emissions that are routed to a flare, combustion, or vapor recovery are
not required to be determined under this paragraph (p).
* * * * *
Count = Total number of reciprocating compressors with rod packing
emissions vented to the atmosphere.
* * * * *
    (q) Equipment leak surveys. For the components identified in
paragraphs (q)(1)(i) through (iii) of this section, you must conduct
equipment leak surveys using the leak detection methods specified in
paragraphs (q)(1)(i) through (iii) and (v) of this section. For the
components identified in paragraph (q)(1)(iv) of this section, you may
elect to conduct equipment leak surveys, and if you elect to conduct
surveys, you must use a leak detection method specified in paragraph
(q)(1)(iv) of this section. This paragraph (q) applies to components in
streams with gas content greater than 10 percent CH4 plus
CO2 by weight. Components in streams with gas content less
than or equal to 10 percent CH4 plus CO2 by
weight are exempt from the requirements of this paragraph (q) and do
not need to be reported. Tubing systems equal to or less than one half
inch diameter are exempt from the requirements of this paragraph (q)
and do not need to be reported.
    (1) Survey requirements. (i) For the components listed in Sec.
98.232(e)(7), (f)(5), (g)(4), and (h)(5), that are not subject to the
well site or compressor station fugitive emissions standards in Sec.
60.5397a of this chapter, the fugitive

emissions standards for well sites and compressor stations in part 60,
subpart OOOOb of this chapter, or an applicable approved state plan or
applicable Federal plan in part 62 of this chapter, you must conduct
surveys using any of the leak detection methods listed in Sec.
98.234(a) and calculate equipment leak emissions using the procedures
specified in either paragraph (q)(2) or (3) of this section.
    (ii) For the components listed in Sec.  98.232(i)(1), you must
conduct surveys using any of the leak detection methods listed in Sec.
98.234(a) except Sec.  98.234(a)(2)(ii) and calculate equipment leak
emissions using the procedures specified in either paragraph (q)(2) or
(3) of this section.
    (iii) For the components listed in Sec.  98.232(c)(21)(i), (e)(7)
and (8), (f)(5) through (8), (g)(4), (g)(6) and (7), (h)(5), (h)(7) and
(8), and (j)(10)(i) that are subject to the well site or compressor
station fugitive emissions standards in Sec.  60.5397a of this chapter,
the fugitive emissions standards for well sites and compressor stations
in part 60, subpart OOOOb of this chapter, or an applicable approved
state plan or applicable Federal plan in part 62 of this chapter, you
must conduct surveys using any of the leak detection methods in Sec.
98.234(a)(1)(ii) or (iii) or (a)(2)(ii), as applicable, and calculate
equipment leak emissions using the procedures specified in either
paragraph (q)(2) or (3) of this section.
    (iv) For the components listed in Sec.  98.232(c)(21)(i), (e)(8),
(f)(6) through (8), (g)(6) or (7), (h)(7) or (8), or (j)(10)(i), that
are not subject to fugitive emissions standards in Sec.  60.5397a of
this chapter, the fugitive emissions standards for well sites and
compressor stations in part 60, subpart OOOOb of this chapter, or an
applicable approved state plan or applicable Federal plan in part 62 of
this chapter, you may elect to conduct surveys according to this
paragraph (q), and, if you elect to do so, then you must use one of the
leak detection methods in Sec.  98.234(a).
    (A) If you elect to use a leak detection method in Sec.  98.234(a)
for the surveyed component types in Sec.  98.232(c)(21)(i), (f)(7),
(g)(6), (h)(7), or (j)(10)(i) in lieu of the population count
methodology specified in paragraph (r) of this section, then you must
calculate emissions for the surveyed component types in Sec.
98.232(c)(21)(i), (f)(7), (g)(6), (h)(7), or (j)(10)(i) using the
procedures in either paragraph (q)(2) or (3) of this section.
    (B) If you elect to use a leak detection method in Sec.  98.234(a)
for the surveyed component types in Sec.  98.232(e)(8), (f)(6) and (8),
(g)(7), and (h)(8), then you must use the procedures in either
paragraph (q)(2) or (3) of this section to calculate those emissions.
    (C) If you elect to use a leak detection method in Sec.
98.234(a)(1)(ii) or (iii), or (a)(2)(ii), as applicable, for any
elective survey under this subparagraph (q)(1)(iv), then you must
survey the component types in Sec.  98.232(c)(21)(i), (e)(8), (f)(6)
through (8), (g)(6) and (7), (h)(7) and (8), and (j)(10)(i) that are
not subject to fugitive emissions standards in Sec.  60.5397a of this
chapter, the fugitive emissions standards for well sites and compressor
stations in 40 CFR part 60, subpart OOOOb of this chapter, or an
applicable approved state plan or applicable Federal plan in part 62 of
this chapter, and you must calculate emissions from the surveyed
component types in Sec.  98.232(c)(21)(i), (e)(8), (f)(6) through (8),
(g)(6) and (7), (h)(7) and (8), and (j)(10)(i) using the emission
calculation requirements in either paragraph (q)(2) or (3) of this
section.
    (v) For the components listed in Sec.  98.232(d)(7), you must
conduct surveys as specified in paragraphs (q)(1)(v)(A) and (B) of this
section and you must calculate equipment leak emissions using the
procedures specified in either paragraph (q)(2) or (3) of this section.
    (A) For the components listed in Sec.  98.232(d)(7) that are not
subject to the equipment leak standards in the equipment leak standards
for processing plants in part 60, subpart OOOOb of this chapter, or an
applicable approved state plan or applicable Federal plan in part 62 of
this chapter, you may use any of the leak detection methods listed in
Sec.  98.234(a).
    (B) For the components listed in Sec.  98.232(d)(7) that are
subject to the equipment leak standards in the equipment leak standards
for processing plants in part 60, subpart OOOOb of this chapter, or an
applicable approved state plan or applicable Federal plan in part 62 of
this chapter, you must use either of the leak detection methods in
Sec.  98.234(a)(1)(iii) or (a)(2)(ii).
    (vi) Except as provided in paragraph (q)(1)(vii) of this section,
you must conduct at least one complete leak detection survey in a
calendar year. If you conduct multiple complete leak detection surveys
in a calendar year, you must use the results from each complete leak
detection survey when calculating emissions using the procedures
specified in either paragraph (q)(2) or (3) of this section. Except as
provided in paragraphs (q)(1)(v)(A) through (G) of this section, a
complete leak detection survey is a survey in which all equipment
components required to be surveyed as specified in paragraphs (q)(1)(i)
through (v) of this section are surveyed.
    (A) For components subject to the well site and compressor station
fugitive emissions standards in Sec.  60.5397a of this chapter, each
survey conducted in accordance with Sec.  60.5397a of this chapter will
be considered a complete leak detection survey for purposes of this
section.
    (B) For components subject to the well site and compressor station
fugitive emissions standards in the fugitive emissions standards for
well sites and compressor stations in part 60, subpart OOOOb of this
chapter, each survey conducted in accordance with the fugitive
emissions standards for well sites and compressor stations in part 60,
subpart OOOOb of this chapter will be considered a complete leak
detection survey for purposes of this section.
    (C) For components subject to the well site and compressor station
fugitive emissions standards in an applicable approved state plan or
applicable Federal plan in part 62 of this chapter, each survey
conducted in accordance with the applicable approved state plan or
applicable Federal plan in part 62 of this chapter will be considered a
complete leak detection survey for purposes of this section.
    (D) For an onshore petroleum and natural gas production facility
electing to conduct leak detection surveys according to paragraph
(q)(1)(iv) of this section, a survey of all required components at a
single well-pad will be considered a complete leak detection survey for
purposes of this section.
    (E) For an onshore petroleum and natural gas gathering and boosting
facility electing to conduct leak detection surveys according to
paragraph (q)(1)(iv) of this section, a survey of all required
components at a gathering compressor station or centralized oil
production site, as defined in Sec.  98.238, will be considered a
complete leak detection survey for purposes of this section.
    (F) For an onshore natural gas processing facility subject to the
equipment leak standards for onshore natural gas processing plants in
the equipment leak standards for onshore natural gas processing plants
in part 60, subpart OOOOb of this chapter or an applicable approved
state plan or applicable Federal plan in part 62 of this chapter, each
survey conducted in accordance with the equipment leak standards for
onshore natural gas processing plants in part 60, subpart OOOOb of this
chapter or an applicable approved state plan or applicable Federal plan
in part 62 of this chapter will be considered a complete leak

detection survey for the purposes of calculating emissions using the
procedures specified in either paragraph (q)(2) or (3) of this section.
However, this provision does not absolve you of the responsibility to
conduct a complete leak detection survey of all components listed in
Sec.  98.232(d)(7) and subject to this paragraph (q) at least once
during the calendar year.
    (G) For natural gas distribution facilities that choose to conduct
equipment leak surveys at all above grade transmission-distribution
transfer stations over multiple years as provided in paragraph
(q)(1)(vii) of this section, a survey of all required components at the
above grade transmission-distribution transfer stations monitored
during the calendar year will be considered a complete leak detection
survey for purposes of this section.
    (vii) Natural gas distribution facilities are required to perform
equipment leak surveys only at above grade stations that qualify as
transmission-distribution transfer stations. Below grade transmission-
distribution transfer stations and all metering-regulating stations
that do not meet the definition of transmission-distribution transfer
stations are not required to perform equipment leak surveys under this
section. Natural gas distribution facilities may choose to conduct
equipment leak surveys at all above grade transmission-distribution
transfer stations over multiple years ``n,'' not exceeding a five-year
period to cover all above grade transmission-distribution transfer
stations. If the facility chooses to use the multiple year option, then
the number of transmission-distribution transfer stations that are
monitored in each year should be approximately equal across all years
in the cycle.
    (2) Calculation Method 1: Leaker emission factor calculation
methodology. If you elect to use this method, you must use this method
for all components included in a complete leak survey. For industry
segments listed in Sec.  98.230(a)(2) through (9), if equipment leaks
are detected during surveys required or elected for components listed
in paragraphs (q)(1)(i) through (iv) of this section, then you must
calculate equipment leak emissions per component type per reporting
facility using Equation W-30 of this section and the requirements
specified in paragraphs (q)(2)(i) through (ix) of this section. For the
industry segment listed in Sec.  98.230(a)(8), the results from
Equation W-30 are used to calculate population emission factors on a
meter/regulator run basis using Equation W-31 of this section. If you
chose to conduct equipment leak surveys at all above grade
transmission-distribution transfer stations over multiple years, ``n,''
according to paragraph (q)(1)(vii) of this section, then you must
calculate the emissions from all above grade transmission-distribution
transfer stations as specified in paragraph (q)(2)(xi) of this section.
* * * * *
EFs,p = Leaker emission factor for specific component
types by leak detection method listed in Tables W-1E, W-2A, W-3A, W-
4A, W-5A, W-6A, and W-7A to this subpart.
* * * * *
    (i) The leak detection surveys selected for use in Equation W-30
must be conducted during the calendar year as indicated in paragraph
(q)(1)(vi) and (vii) of this section, as applicable.
* * * * *
    (iii) Onshore petroleum and natural gas production facilities must
use the appropriate default whole gas leaker emission factors
consistent with the well type, where components associated with gas
wells are considered to be in gas service and components associated
with oil wells are considered to be in oil service as listed in Table
W-1E to this subpart.
* * * * *
    (v) Onshore natural gas processing facilities must use the
appropriate default total hydrocarbon leaker emission factors for
compressor components in gas service and non-compressor components in
gas service listed in Table W-2A to this subpart.
* * * * *
    (x) Natural gas distribution facilities must use Equation W-30 of
this section and the default methane leaker emission factors for
transmission-distribution transfer station components in gas service
listed in Table W-7 to this subpart to calculate component emissions
from annual equipment leak surveys conducted at above grade
transmission-distribution transfer stations.
    (A) Use Equation W-31 of this section to determine the meter/
regulator run population emission factors for each GHGi. As additional
survey data become available, you must recalculate the meter/regulator
run population emission factors for each GHGi annually according to
paragraph (q)(2)(x)(B) of this section.
[GRAPHIC] [TIFF OMITTED] TP21JN22.047

Where:

EFs,MR,i = Meter/regulator run population emission factor
for GHGi based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic
feet of GHGi per operational hour of all meter/regulator
runs.
Es,p,i,y = Annual total volumetric emissions at standard
conditions of GHGi from component type ``p'' during year
``y'' in standard (``s'') cubic feet, as calculated using Equation
W-30 of this section.
p = Seven component types listed in Table W-7 to this subpart for
transmission-distribution transfer stations.
Tw,y = The total time the surveyed meter/regulator run
``w'' was operational, in hours during survey year ``y'' using an
engineering estimate based on best available data.
CountMR,y = Count of meter/regulator runs surveyed at
above grade transmission-distribution transfer stations in year
``y''.
y = Year of data included in emission factor ``EFs,MR,i''
according to paragraph (q)(2)(x)(B) of this section.
n = Number of years of data, according to paragraph (q)(1)(vii) of
this section, whose results are used to calculate emission factor
``EFs,MR,i'' according to paragraph (q)(2)(x)(B) of this
section.

    (B) The emission factor ``EFs,MR,i'' based on annual
equipment leak surveys at above grade transmission-distribution
transfer stations, must be calculated annually. If you chose to conduct
equipment leak surveys at all above grade transmission-distribution
transfer stations over multiple years, ``n,'' according to paragraph
(q)(1)(vii) of this section and you have submitted a smaller number of
annual reports than the duration of the selected cycle period of 5
years or less, then all available data from the current year and
previous years

must be used in the calculation of the emission factor
``EFs,MR,i'' from Equation W-31 of this section. After the
first survey cycle of ``n'' years is completed and beginning in
calendar year (n+1), the survey will continue on a rolling basis by
including the survey results from the current calendar year ``y'' and
survey results from all previous (n-1) calendar years, such that each
annual calculation of the emission factor ``EFs,MR,i'' from
Equation W-31 is based on survey results from ``n'' years. Upon
completion of a cycle, you may elect to change the number of years in
the next cycle period (to be 5 years or less). If the number of years
in the new cycle is greater than the number of years in the previous
cycle, calculate ``EFs,MR,i'' from Equation W-31 in each
year of the new cycle using the survey results from the current
calendar year and the survey results from the preceding number years
that is equal to the number of years in the previous cycle period. If
the number of years, ``nnew,'' in the new cycle is smaller
than the number of years in the previous cycle, ``n,'' calculate
``EFs,MR,i'' from Equation W-31 in each year of the new
cycle using the survey results from the current calendar year and
survey results from all previous (nnew-1) calendar years.
    (xi) If you chose to conduct equipment leak surveys at all above
grade transmission-distribution transfer stations over multiple years,
``n,'' according to paragraph (q)(1)(vii) of this section, you must use
the meter/regulator run population emission factors calculated using
Equation W-31 of this section and the total count of all meter/
regulator runs at above grade transmission-distribution transfer
stations to calculate emissions from all above grade transmission-
distribution transfer stations using Equation W-32B in paragraph (r) of
this section.
    (3) Calculation Method 2: Leaker measurement methodology. If you
elect to use this method, you must use this method for all components
included in a complete leak survey. For industry segments listed in
Sec.  98.230(a)(2) through (9), if equipment leaks are detected during
surveys required or elected for components listed in paragraphs
(q)(1)(i) through (v) of this section, you must determine the
volumetric flow rate of each natural gas leak identified during the
leak survey and aggregate the emissions by component type as specified
in paragraphs (q)(3)(i) through (vii) of this section.
    (i) Determine the volumetric flow rate of each natural gas leak
identified during the leak survey following the methods Sec.  98.234(b)
through (d), as appropriate for each leak identified. You do not need
to use the same measurement method for each leak measured.
    (ii) For each leak, calculate the volume of natural gas emitted as
the product of the natural gas flow rate measured in paragraph
(q)(3)(i) of this section and the duration of the leak. If one leak
detection survey is conducted in the calendar year, assume the
component was leaking for the entire calendar year. If multiple leak
detection surveys are conducted in the calendar year, assume a
component found leaking in the first survey was leaking since the
beginning of the year until the date of the survey; assume a component
found leaking in the last survey of the year was leaking from the
preceding survey through the end of the year; assume a component found
leaking in a survey between the first and last surveys of the year was
leaking since the preceding survey until the date of the survey. For
each leaking component, account for time the component was not
operational (i.e., not operating under pressure) using an engineering
estimate based on best available data.
    (iii) For each leak, convert the volumetric emissions of natural
gas determined in paragraph (q)(3)(ii) of this section to standard
conditions using the method specified in paragraph (t)(1) of this
section.
    (iv) For each leak, convert the volumetric emissions of natural gas
at standard conditions determined in paragraph (q)(3)(iii) of this
section to CO2 and CH4 volumetric emissions at
standard conditions using the methods specified in paragraph (u) of
this section.
    (v) For each leak, convert the GHG volumetric emissions at standard
conditions determined in paragraph (q)(3)(iv) of this section to GHG
mass emissions using the methods specified in paragraph (v) of this
section.
    (vi) Sum the CO2 and CH4 mass emissions
determined in paragraph (q)(3)(v) of this section separately for each
type of component required to be surveyed for which a leak was
detected.
    (vii) For natural gas distribution facilities:
    (A) Use Equation W-31 of this section to determine the meter/
regulator run population emission factors for each GHGi
using the methods as specified in paragraphs (q)(2)(x)(A) and (B) of
this section, except use the GHG mass emissions calculated in paragraph
(q)(3)(vi) rather than the emissions calculated using Equation W-30.
    (B) If you chose to conduct equipment leak surveys at all above
grade transmission-distribution transfer stations over multiple years,
``n,'' according to paragraph (q)(1)(vii) of this section, you must use
the meter/regulator run population emission factors calculated
according to paragraph (q)(3)(vii)(A) of this section and the total
count of all meter/regulator runs at above grade transmission-
distribution transfer stations to calculate emissions from all above
grade transmission-distribution transfer stations using Equation W-32B
in paragraph (r) of this section.
    (r) Equipment leaks by population count. This paragraph (r) applies
to emissions sources listed in Sec.  98.232(c)(21)(ii), (f)(7), (g)(5),
(h)(6), and (j)(10)(ii) if you are not required to comply with
paragraph (q) of this section and if you do not elect to comply with
paragraph (q) of this section for these components in lieu of this
paragraph (r). This paragraph (r) also applies to emission sources
listed in Sec.  98.232(i)(2) through (6) and (j)(11). To be subject to
the requirements of this paragraph (r), the listed emissions sources
also must contact streams with gas content greater than 10 percent
CH4 plus CO2 by weight. Emissions sources that
contact streams with gas content less than or equal to 10 percent
CH4 plus CO2 by weight are exempt from the
requirements of this paragraph (r) and do not need to be reported.
Tubing systems equal to or less than one half inch diameter are exempt
from the requirements of paragraph (r) of this section and do not need
to be reported. You must calculate emissions from all emission sources
listed in this paragraph (r) using Equation W-32A of this section,
except for natural gas distribution facility emission sources listed in
Sec.  98.232(i)(3). Natural gas distribution facility emission sources
listed in Sec.  98.232(i)(3) must calculate emissions using Equation W-
32B of this section and according to paragraph (r)(6)(ii) of this
section.
* * * * *
Es,e,i = Annual volumetric emissions of GHGi
from the emission source type in standard cubic feet. The emission
source type may be a major equipment (e.g., wellhead, separator),
component (e.g., connector, open-ended line), below grade metering-
regulating station, below grade transmission-distribution transfer
station, distribution main, distribution service, or gathering
pipeline.
Es,MR,i = Annual volumetric emissions of GHGi
from all meter/regulator runs at above grade metering regulating
stations that are not above grade transmission-distribution transfer
stations or, when used to calculate emissions according to paragraph
(q)(2)(xi) or (q)(3)(vii)(B) of this section, the annual volumetric
emissions of GHGi from all meter/regulator runs at above
grade

transmission-distribution transfer stations.
Counte = Total number of the emission source type at the
facility. Onshore petroleum and natural gas production facilities
and onshore petroleum and natural gas gathering and boosting
facilities must count each major equipment piece listed in Table W-
1A to this subpart. Onshore petroleum and natural gas gathering and
boosting facilities must also count the miles of gathering pipelines
by material type (protected steel, unprotected steel, plastic, or
cast iron). Underground natural gas storage facilities must count
each component listed in Table W-4B to this subpart. LNG storage
facilities must count the number of vapor recovery compressors. LNG
import and export facilities must count the number of vapor recovery
compressors. Natural gas distribution facilities must count the: (1)
Number of distribution services by material type; (2) miles of
distribution mains by material type; (3) number of below grade
transmission-distribution transfer stations; and (4) number of below
grade metering-regulating stations; as listed in Table W-8 to this
subpart.
CountMR = Total number of meter/regulator runs at above
grade metering-regulating stations that are not above grade
transmission-distribution transfer stations or, when used to
calculate emissions according to paragraph (q)(2)(xi) or
(q)(3)(vii)(B) of this section, the total number of meter/regulator
runs at above grade transmission-distribution transfer stations.
EFs,e = Population emission factor for the specific
emission source type, as listed in Tables W-1A, W-4B, W-5B, W-6B,
and W-8 to this subpart.
* * * * *
    (2) Onshore petroleum and natural gas production facilities and
onshore petroleum and natural gas gathering and boosting facilities
must use the appropriate default whole gas population emission factors
listed in Table W-1A of this subpart. Major equipment associated with
gas wells are considered gas service equipment in Table W-1A of this
subpart. Onshore petroleum and natural gas gathering and boosting
facilities shall use the gas service equipment emission factors in
Table W-1A of this subpart. Major equipment associated with crude oil
wells are considered crude service equipment in Table W-1A of this
subpart. Where facilities conduct EOR operations the emission factor
listed in Table W-1A of this subpart shall be used to estimate all
streams of gases, including recycle CO2 stream. For meters/
piping, use one meters/piping per well-pad for onshore petroleum and
natural gas production operations and the number of meters in the
facility for onshore petroleum and natural gas gathering and boosting
operations.
* * * * *
    (6) * * *
    (i) Below grade transmission-distribution transfer stations, below
grade metering-regulating stations, distribution mains, and
distribution services must use the appropriate default methane
population emission factors listed in Table W-8 of this subpart to
estimate emissions from components listed in Sec.  98.232(i)(2), (4),
(5), and (6), respectively.
    (ii) Above grade metering-regulating stations that are not above
grade transmission-distribution transfer stations must use the meter/
regulator run population emission factor calculated in Equation W-31
for the components listed in Sec.  98.232(i)(3). Natural gas
distribution facilities that do not have above grade transmission-
distribution transfer stations are not required to calculate emissions
for above grade metering-regulating stations and are not required to
report GHG emissions in Sec.  98.236(r)(2)(v).
    (s) Offshore petroleum and natural gas production facilities.
Report CO2, CH4, and N2O emissions for
offshore petroleum and natural gas production from all equipment leaks,
vented emission, and flare emission source types as identified in the
data collection and emissions estimation study conducted by BOEM in
compliance with 30 CFR 550.302 through 304.
    (1) Offshore production facilities under BOEM jurisdiction shall
report the same annual emissions as calculated and reported by BOEM in
data collection and emissions estimation study published by BOEM
referenced in 30 CFR 550.302 through 304.
    (i) For any calendar year that does not overlap with the most
recent BOEM emissions study publication year, report the most recent
BOEM reported emissions data published by BOEM referenced in 30 CFR
550.302 through 304. Adjust emissions based on the operating time for
the facility relative to the operating time in the most recent BOEM
published study.
    (ii) [Reserved]
    (2) Offshore production facilities that are not under BOEM
jurisdiction must use the most recent monitoring methods and
calculation methods published by BOEM referenced in 30 CFR 550.302
through 304 to calculate and report annual emissions.
    (i) For any calendar year that does not overlap with the most
recent BOEM emissions study publication, you may report the most
recently reported emissions data submitted to demonstrate compliance
with this subpart of part 98, with emissions adjusted based on the
operating time for the facility relative to operating time in the
previous reporting period.
    (ii) [Reserved]
    (3) If BOEM discontinues or delays their data collection effort by
more than 4 years, then offshore reporters shall once in every 4 years
use the most recent BOEM data collection and emissions estimation
methods to estimate emissions. These emission estimates would be used
to report emissions from the facility sources as required in paragraph
(s)(1)(i) of this section.
    (4) For either first or subsequent year reporting, offshore
facilities either within or outside of BOEM jurisdiction that were not
covered in the previous BOEM data collection cycle must use the most
recent BOEM data collection and emissions estimation methods published
by BOEM referenced in 30 CFR 550.302 through 304 to calculate and
report emissions.
    (t) * * *
    (2) * * *
* * * * *
Za = Compressibility factor at actual conditions for
GHGi. You may use either a default compressibility factor
of 1, or a site-specific compressibility factor based on actual
temperature and pressure conditions.
* * * * *
    (u) * * *
    (2) * * *
    (ii) GHG mole fraction in feed natural gas for all emissions
sources upstream of the de-methanizer or dew point control and GHG mole
fraction in facility specific residue gas to transmission pipeline
systems for all emissions sources downstream of the de-methanizer
overhead or dew point control for onshore natural gas processing
facilities. For onshore natural gas processing plants that solely
fractionate a liquid stream, use the GHG mole percent in feed natural
gas liquid for all streams. If you have a continuous gas composition
analyzer on feed natural gas, you must use these values for determining
the mole fraction. If you do not have a continuous gas composition
analyzer, then annual samples must be taken according to methods set
forth in Sec.  98.234(b).
* * * * *
    (y) Other large release events. Calculate CO2 and
CH4 emissions from other release events for each release
that emits GHG in excess of 250 metric tons of CO2e as
specified in paragraphs (y)(1) through (4) of this section.
    (1) Estimate the total volume of gas released during the event in
standard

cubic feet using any combination of measurement data, engineering
estimates, and best available data. Typically, total volume of gas
released would be estimated as the product of the estimated flow or
release rate and the estimated event duration.
    (2) Determine the composition of the gas released to the atmosphere
using measurement data, if available, or process knowledge, engineering
estimates and best available data. In the event of an explosion or
fire, where a portion of the natural gas may be combusted, estimate the
composition of the gas released to the atmosphere considering the
fraction of natural gas that was converted to CO2 during the
release event.
    (3) Calculate the GHG volumetric emissions using Equation W-35 in
paragraph (u)(1) of this section.
    (4) Calculate both CH4 and CO2 mass emissions
from volumetric emissions using calculations in paragraph (v) of this
section.
    (z) Onshore petroleum and natural gas production, onshore petroleum
and natural gas gathering and boosting, and natural gas distribution
combustion emissions. Except as specified in paragraphs (z)(5) and (6)
of this section, calculate CO2, CH4, and
N2O combustion-related emissions from stationary or portable
equipment using the applicable method in paragraphs (z)(1) through (3)
of this section according to the fuel combusted as specified in those
paragraphs:
    (1) If a fuel combusted in the stationary or portable equipment
meets the specifications of paragraph (z)(1)(i) of this section, then
calculate emissions according to paragraph (z)(1)(ii) of this section.
    (i) The fuel combusted in the stationary or portable equipment is
listed in Table C-1 of subpart C of this part or is a blend in which
all fuels are listed in Table C-1. If the fuel is natural gas or the
blend contains natural gas, the natural gas must also meet the criteria
of paragraphs (z)(1)(i)(A) and (B) of this section.
    (A) The natural gas must be of pipeline quality specification.
    (B) The natural gas must have a minimum higher heating value of 950
Btu per standard cubic foot.
    (ii) For fuels listed in paragraph (z)(1)(i) of this section,
calculate CO2, CH4, and N2O emissions
according to any Tier listed in subpart C of this part, except that
natural gas-fired compressor-drivers must use the appropriate emission
factor in Table W-9 for quantifying CH4 emissions instead of
the CH4 emission factor in Table C-2 of subpart C of this
part. You must follow all applicable calculation requirements for that
tier listed in Sec.  98.33, any monitoring or QA/QC requirements listed
for that tier in Sec.  98.34, any missing data procedures specified in
Sec.  98.35, and any recordkeeping requirements specified in Sec.
98.37. You must report emissions according to paragraph (z)(4) of this
section.
    (2) If a fuel combusted in the stationary or portable equipment
meets the specifications of paragraph (z)(2)(i) of this section, then
calculate emissions according to paragraph (z)(2)(ii) of this section.
    (i) The fuel combusted in the stationary or portable equipment is
natural gas that is not pipeline quality or it is a blend containing
natural gas that is not pipeline quality and other gaseous fuels listed
in Table C-1. The natural gas also must meet the criteria of paragraphs
(z)(2)(i)(A) through (C) of this section.
    (A) The natural gas must have a minimum higher heating value of 950
Btu per standard cubic foot.
    (B) The natural gas must have a maximum CO2 content of 1
percent by volume.
    (C) The natural gas must have a minimum CH4 content of
85 percent by volume.
    (ii) For fuels listed in paragraph (z)(2)(i) of this section,
calculate CO2, CH4, and N2O emissions
according to Tier 2, Tier 3, or Tier 4 listed in subpart C of this
part, except that natural gas-fired compressor-drivers must use the
appropriate emissions factor in Table W-9 for quantifying
CH4 emissions instead of the CH4 emission factor
in Table C-2 of subpart C of this part. You must follow all applicable
calculation requirements for that tier listed in Sec.  98.33, any
monitoring or QA/QC requirements listed for that tier in Sec.  98.34,
any missing data procedures specified in Sec.  98.35, and any
recordkeeping requirements specified in Sec.  98.37. You must report
emissions according to paragraph (z)(4) of this section.
    (3) If a fuel combusted in the stationary or portable equipment
meets the specifications of paragraph (z)(3)(i) of this section, then
calculate emissions according to paragraph (z)(3)(ii) of this section.
    (i) The fuel is not listed in Table C-1 of subpart C of this part,
the fuel is a blend containing one or more fuels not listed in Table C-
1, or the fuel is natural gas or contains natural gas that does not
meet the criteria of either paragraph (z)(1)(i) or (z)(2)(i) of this
section. This includes natural gas that has a higher heating value of
less than 950 Btu per standard cubic feet and natural gas that is not
pipeline quality and does not meet the composition criteria of either
paragraph (z)(2)(i)(B) or (C) of this section. This also includes field
gas that does not meet the definition of natural gas in Sec.  98.238,
and blends containing field gas that does not meet the definition of
natural gas in Sec.  98.238.
    (ii) For fuels listed in paragraph (z)(3)(i) of this section,
calculate combustion emissions for each unit or group of units
combusting the same fuel as follows:
    (A) You may use company records to determine the volume of fuel
combusted in the unit or group of units during the reporting year.
    (B) If you have a continuous gas composition analyzer on fuel to
the combustion unit(s), you must use these compositions for determining
the concentration of each hydrocarbon constituent in the flow of gas to
the unit or group of units. If you do not have a continuous gas
composition analyzer on gas to the combustion unit(s), you may use
engineering estimates based on best available data to determine the
concentration of each hydrocarbon constituent in the flow of gas to the
unit or group of units. Otherwise, you must use the appropriate gas
compositions for each stream of hydrocarbons going to the combustion
unit(s) as specified in the applicable paragraph in (u)(2) of this
section.
    (C) Calculate GHG volumetric emissions at actual conditions using
Equations W-39A and W-39B of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.048

[GRAPHIC] [TIFF OMITTED] TP21JN22.049

Where:

Ea,CO2 = Contribution of annual CO2 emissions
from portable or stationary fuel combustion sources in cubic feet,
under actual conditions.
Va = Volume of gas sent to the combustion unit or group
of units in actual cubic feet, during the year.
YCO2 = Mole fraction of CO2 in gas sent to the
combustion unit or group of units.
Ea,CH4 = Contribution of annual CH4 emissions
from portable or stationary fuel combustion sources in cubic feet,
under actual conditions.
[eta] = Fraction of gas combusted for portable and stationary
equipment determined using engineering estimation. For internal
combustion devices that are not compressor-drivers, a default of
0.995 can be used. For two-stroke lean-burn compressor-drivers, a
default of 0.953 must be used; for four- stroke lean-burn
compressor-drivers, a default of 0.962 must be used; and for four-
stroke rich-burn compressor-drivers, a default of 0.997 must be
used.
Yj = Mole fraction of hydrocarbon constituent j (such as
methane, ethane, propane, butane, and pentanes plus) in gas sent to
the combustion unit or group of units.
Rj = Number of carbon atoms in the hydrocarbon
constituent j in gas sent to the combustion unit or group of units;
1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for
pentanes plus.
YCH4 = Mole fraction of methane in gas sent to the
combustion unit or group of units.

    (D) Calculate GHG volumetric emissions at standard conditions using
calculations in paragraph (t) of this section.
    (E) Calculate both combustion-related CH4 and
CO2 mass emissions from volumetric CH4 and
CO2 emissions using calculation in paragraph (v) of this
section.
    (F) Calculate N2O mass emissions using Equation W-40 of
this section.
[GRAPHIC] [TIFF OMITTED] TP21JN22.050

Where:

MassN2O = Annual N2O emissions from the
combustion of a particular type of fuel (metric tons).
Fuel = Annual mass or volume of the fuel combusted (mass or volume
per year, choose appropriately to be consistent with the units of
HHV).
HHV = Higher heating value of fuel, mmBtu/unit of fuel (in units
consistent with the fuel quantity combusted). For field gas or
process vent gas, you may use either a default higher heating value
of 1.235 x 10-3 mmBtu/scf or a site-specific higher
heating value. For natural gas that is not of pipeline quality or
that has a higher heating value less than 950 Btu per standard cubic
foot, use a site-specific higher heating value.
EF = Use 1.0 x 10-\4\ kg N2O/mmBtu.
1 x 10-\3\ = Conversion factor from kilograms to metric
tons.

    (4) Emissions from fuel combusted in stationary or portable
equipment at onshore petroleum and natural gas production facilities,
at onshore petroleum and natural gas gathering and boosting facilities,
and at natural gas distribution facilities that are calculated
according to the procedures in either paragraph (z)(1)(ii) or
(z)(2)(ii) of this section must be reported according to the
requirements specified in Sec.  98.236(z) rather than the reporting
requirements specified in subpart C of this part.
    (5) External fuel combustion sources with a rated heat capacity
equal to or less than 5 mmBtu/hr do not need to report combustion
emissions or include these emissions for threshold determination in
Sec.  98.231(a). You must report the type and number of each external
fuel combustion unit.
    (6) Internal fuel combustion sources, not compressor-drivers, with
a rated heat capacity equal to or less than 1 mmBtu/hr (or the
equivalent of 130 horsepower), do not need to report combustion
emissions or include these emissions for threshold determination in
Sec.  98.231(a). You must report the type and number of each internal
fuel combustion unit.
0
58. Amend Sec.  98.234 by revising the introductory text, paragraph
(a), and paragraph (d)(3) and adding paragraphs (d)(5) and (i) to read
as follows:

Sec.  98.234  Monitoring and QA/QC requirements.

    The GHG emissions data for petroleum and natural gas emissions
sources must be quality assured as applicable as specified in this
section. Offshore petroleum and natural gas production facilities shall
adhere to the monitoring and QA/QC requirements as set forth in 30 CFR
550.
    (a) You must use any of the applicable methods described in
paragraphs (a)(1) through (5) of this section to conduct leak
detection(s) or screening survey(s) as specified in Sec.  98.233(k),
(o), and (p) that occur during a calendar year. You must use any of the
methods described in paragraphs (a)(1) through (5) of this section to
conduct leak detection(s) of equipment leaks from components as
specified in Sec.  98.233(q)(1)(i) or (ii) or (q)(1)(v)(A) that occur
during a calendar year. You must use one of the methods described in
paragraph (a)(1)(ii) or (iii) or (a)(2)(ii) of this section, as
applicable, to conduct leak detection(s) of equipment leaks from
components as specified in Sec.  98.233(q)(1)(iii) or (q)(1)(v)(B). If
electing to comply with Sec.  98.233(q) as specified in Sec.
98.233(q)(1)(iv), you must use any of the methods described in
paragraphs (a)(1) through (5) of this section to conduct leak
detection(s) of equipment leaks from component types as specified in
Sec.  98.233(q)(1)(iv) that occur during a calendar year. Inaccessible
emissions sources, as defined in 40 CFR part 60, are not exempt from
this subpart. If the primary leak detection method employed cannot be
used to monitor inaccessible components without elevating the
monitoring personnel more than 2 meters above a support surface, you
must use alternative leak detection devices as described in paragraph
(a)(1) or (3) of this section to monitor inaccessible equipment leaks
or vented emissions at least once per calendar year.
    (1) Optical gas imaging instrument. Use an optical gas imaging
instrument for equipment leak detection as specified in either
paragraph (a)(1)(i), (ii), or (iii) of this section. You may use any of
the methods as specified in paragraphs (a)(1)(i) through (iii) of this
section unless you are required to use a specific method to comply with
the fugitive emission component requirements in part 60, subpart OOOOa
of this chapter or with the fugitive emission component or equipment
leak requirements in part 60, OOOOb of this chapter or with the
fugitive emission component or equipment leak requirements in an
applicable approved state plan or applicable Federal plan in part 62 of
this chapter.
    (i) Optical gas imaging instrument as specified in Sec.  60.18 of
this chapter. Use an optical gas imaging instrument for equipment leak
detection in accordance with 40 CFR part 60, subpart A, Sec.  60.18 of
the Alternative work practice for monitoring equipment leaks, Sec.
60.18(i)(1)(i); Sec.  60.18(i)(2)(i) except

that the minimum monitoring frequency shall be annual using the
detection sensitivity level of 60 grams per hour as stated in 40 CFR
part 60, subpart A, Table 1: Detection Sensitivity Levels; Sec.
60.18(i)(2)(ii) and (iii) except the gas chosen shall be methane, and
Sec.  60.18(i)(2)(iv) and (v); Sec.  60.18(i)(3); Sec.  60.18(i)(4)(i)
and (v); including the requirements for daily instrument checks and
distances, and excluding requirements for video records. Any emissions
detected by the optical gas imaging instrument from an applicable
component is a leak. In addition, you must operate the optical gas
imaging instrument to image the source types required by this subpart
in accordance with the instrument manufacturer's operating parameters.
    (ii) Optical gas imaging instrument as specified in Sec.  60.5397a
of this chapter. Use an optical gas imaging instrument for equipment
leak detection in accordance with Sec.  60.5397a(b), (c)(3) and (7),
and (e) of this chapter and paragraphs (a)(1)(ii)(A) through (C) of
this section.
    (A) For the purposes of this subpart, any visible emissions
observed by the optical gas imaging instrument from a component
required or elected to be monitored as specified in Sec.  98.233(q)(1)
is a leak.
    (B) For the purposes of this subpart, the term ``fugitive emissions
component'' in Sec.  60.5397a of this chapter means ``component.''
    (C) For the purpose of complying with Sec.  98.233(q)(1)(iv), the
phrase ``the collection of fugitive emissions components at well sites
and compressor stations'' in Sec.  60.5397a(b) of this chapter means
``the collection of components for which you elect to comply with Sec.
98.233(q)(1)(iv).''
    (iii) Optical gas imaging instrument as specified in appendix K to
part 60 of this chapter. Use an optical gas imaging instrument for
equipment leak detection in accordance with appendix K to part 60,
Determination of Volatile Organic Compound and Greenhouse Gas Leaks
Using Optical Gas Imaging. Any emissions detected by the optical gas
imaging instrument from an applicable component is a leak.
    (2) Method 21. Use the equipment leak detection methods in Method
21 in appendix A-7 to part 60 of this chapter as specified in paragraph
(a)(2)(i) or (ii) of this section. You may use either of the methods as
specified in paragraphs (a)(2)(i) and (ii) of this section unless you
are required to use a specific method to comply with the fugitive
emission component requirements in part 60, subpart OOOOa of this
chapter or with the fugitive emission component or equipment leak
requirements in part 60, subpart OOOOb of this chapter or with the
fugitive emission component or equipment leak requirements in an
applicable approved state plan or applicable Federal plan in part 62 of
this chapter. You must survey all applicable source types at the
facility needed to conduct a complete equipment leak survey as defined
in Sec.  98.233(q)(1). For the purposes of this subpart, the term
``fugitive emissions component'' in Sec.  60.5397a of this chapter
means ``component.''
    (i) Method 21 with a leak definition of 10,000 ppm. Use the
equipment leak detection methods in Method 21 in appendix A-7 to part
60 of this chapter using methane as the reference compound. If an
instrument reading of 10,000 ppm or greater is measured for any
applicable component, a leak is detected.
    (ii) Method 21 with a leak definition of 500 ppm. Use the equipment
leak detection methods in Method 21 in appendix A-7 to part 60 of this
chapter using methane as the reference compound. If an instrument
reading of 500 ppm or greater is measured for any applicable component,
a leak is detected.
    (3) Infrared laser beam illuminated instrument. Use an infrared
laser beam illuminated instrument for equipment leak detection. Any
emissions detected by the infrared laser beam illuminated instrument is
a leak. In addition, you must operate the infrared laser beam
illuminated instrument to detect the source types required by this
subpart in accordance with the instrument manufacturer's operating
parameters.
    (4) [Reserved]
    (5) Acoustic leak detection device. Use the acoustic leak detection
device to detect through-valve leakage. When using the acoustic leak
detection device to quantify the through-valve leakage, you must use
the instrument manufacturer's calculation methods to quantify the
through-valve leak. When using the acoustic leak detection device, if a
leak of 3.1 scf per hour or greater is calculated, a leak is detected.
In addition, you must operate the acoustic leak detection device to
monitor the source valves required by this subpart in accordance with
the instrument manufacturer's operating parameters. Acoustic
stethoscope type devices designed to detect through valve leakage when
put in contact with the valve body and that provide an audible leak
signal but do not calculate a leak rate can be used to identify
through-valve leakage. For these acoustic stethoscope type devices, a
leak is detected if an audible leak signal is observed or registered by
the device. If the acoustic stethoscope type device is used as a
screening to a measurement method and a leak is detected, the leak must
be measured using any one of the methods specified in paragraphs (b)
through (d) of this section.
* * * * *
    (d) * * *
    (3) For high volume samplers that output methane mass emissions,
you must use the calculations in Sec.  98.233(u) and (v) in reverse to
determine the natural gas volumetric emissions at standard conditions.
For high volume samplers that output methane volumetric flow in actual
conditions, divide the volumetric methane flow rate by the mole
fraction of methane in the natural gas according to the provisions in
Sec.  98.233(u) and estimate natural gas volumetric emissions at
standard conditions using calculations in Sec.  98.233(t). Estimate
CH4 and CO2 volumetric and mass emissions from
volumetric natural gas emissions using the calculations in Sec.
98.233(u) and (v).
* * * * *
    (5) If the measured methane flow exceeds the manufacturer's
reported quantitation limit or if the measured natural gas flow
determined as specified in paragraph (d)(3) of this section exceeds 70
percent of the manufacturer's reported maximum sampling flow rate, then
the flow exceeds the capacity of the instrument and you must either use
a temporary or permanent flow meter according to paragraph (b) of this
section or use calibrated bags according to paragraph (c) of this
section to determine the leak or flow rate.
* * * * *
    (i) Special reporting provisions for best available monitoring
methods in reporting year 2023--(1) Use of best available monitoring
methods. From January 1, 2023, to December 31, 2023, you must use the
calculation methodologies and equations in Sec.  98.233 but you may use
the best available monitoring method as described in paragraph (i)(2)
of this section for any parameter specified in paragraphs (i)(3)
through (7) of this section for which it is not reasonably feasible to
acquire, install, and operate a required piece of monitoring equipment
by January 1, 2023. Starting no later than January 1, 2024, you must
discontinue using best available methods and begin following all
applicable monitoring and QA/QC requirements of this part.
    (2) Best available monitoring methods. Best available monitoring

methods means any of the following methods:
    (i) Monitoring methods currently used by the facility that do not
meet the specifications of this subpart.
    (ii) Supplier data.
    (iii) Engineering calculations.
    (iv) Other facility records.
    (3) Best available monitoring methods for measurement data for
natural gas pneumatic devices. You may use best available monitoring
methods for any measurement data, including activity data such as gas
compositions and hours of operation, that cannot reasonably be measured
according to the monitoring and QA/QC requirements of this subpart for
natural gas pneumatic devices as specified in Sec.  98.233(a) at
onshore natural gas processing plants and for natural gas intermittent
bleed pneumatic devices that are monitored as specified in Sec.
98.233(a)(6).
    (4) Best available monitoring methods for measurement data for LNG
import/export facilities. You may use best available monitoring methods
for any measurement data, including activity data such as flow rates,
gas compositions, and hours of operation, that cannot reasonably be
measured according to the monitoring and QA/QC requirements of this
subpart for acid gas removal vents as specified in Sec.  98.233(d) at
LNG import/export facilities.
    (5) Best available monitoring methods for measurement data for
other large release events. You may use best available monitoring
methods for any measurement data, including activity data such as flow
rates, gas compositions, and hours of operation, that cannot reasonably
be measured according to the monitoring and QA/QC requirements of this
subpart for other large release events as specified in Sec.  98.233(y).
    (6) Best available monitoring methods for measurement data for
miscellaneous flared sources. You may use best available monitoring
methods for any measurement data, including activity data such as flow
rates and gas compositions, that cannot reasonably be obtained
according to the monitoring and QA/QC requirements of this subpart for
miscellaneous flared sources as specified in Sec.  98.233(n)(1) and
(2).
    (7) Best available monitoring methods for measurement data for
specific emission sources routed to vapor recovery. You may use best
available monitoring methods for any measurement data, including
activity data such as flow rates, gas compositions, and hours of
operation, that cannot reasonably be obtained according to the
monitoring and QA/QC requirements of this subpart for dehydrator vents
and storage tank vents routed to vapor recovery as specified in Sec.
98.233(e)(4) and (j)(4), respectively.
    (8) Best available monitoring methods for measurement data for
compressors. You may use best available monitoring methods for any
measurement data that cannot reasonably be obtained according to the
monitoring and QA/QC requirements of this subpart for dry seal vents on
centrifugal compressors and all compressor sources for centrifugal
compressors found in standby-pressurized-mode as specified in Sec.
98.233(o). You may use best available monitoring methods for any
measurement data that cannot reasonably be obtained according to the
monitoring and QA/QC requirements of this subpart for rod packing on
reciprocating compressors in standby-pressurized-mode as specified in
Sec.  98.233(p).
    (9) Best available monitoring methods for measurement data for a
facility that was part of a facility with respect to onshore petroleum
and natural gas gathering and boosting prior to January 1, 2023, and
meets the definition of onshore natural gas processing in Sec.
98.230(a)(3) effective as of January 1, 2023. You may use best
available monitoring methods for measurement data, including activity
data, as listed in paragraphs (i)(9)(i) through (iv) of this section
that cannot reasonably be obtained according to the monitoring and QA/
QC requirements of this subpart.
    (i) Temperature and pressure for emergency blowdowns in Sec.
98.233(i).
    (ii) Equipment leak surveys in Sec.  98.233(q).
    (iii) Centrifugal compressors in Sec.  98.233(o).
    (iv) Reciprocating compressors in Sec.  98.233(p).
    (10) Best available monitoring methods for measurement data for a
facility that was an onshore natural gas processing facility prior to
January 1, 2023, and became part of a facility with respect to onshore
petroleum and natural gas gathering and boosting as defined in Sec.
98.238 as of January 1, 2023, due to the change in definition of
onshore natural gas processing in Sec.  98.230(a)(3) effective as of
January 1, 2023. You may use best available monitoring methods for
measurement data, including activity data, as listed in paragraphs
(i)(10)(i) through (iii) of this section that cannot reasonably be
obtained according to the monitoring and QA/QC requirements of this
subpart.
    (i) Natural gas driven pneumatic pumps in Sec.  98.233(c).
    (ii) Storage tanks in Sec.  98.233(j).
    (iii) Equipment leak surveys in Sec.  98.233(q) and/or equipment
leaks by population count in Sec.  98.233(r), as applicable, for
equipment components not required for the onshore natural gas
processing industry segment (i.e., pumps, flanges, other components,
and gathering pipelines).
0
59. Amend Sec.  98.236 by:
0
a. Revising the introductory text and paragraphs (a)(1) introductory
text and (a)(1)(xviii);
0
b. Adding paragraph (a)(1)(xix);
0
c. Revising paragraphs (a)(2) and (a)(3) introductory text;
0
d. Redesignating paragraphs (a)(3)(i) through (vii) as paragraphs
(a)(3)(ii) through (viii), respectively;
0
e. Adding new paragraph (a)(3)(i) and paragraph (a)(3)(ix);
0
f. Revising paragraph (a)(4) introductory text;
0
g. Adding paragraph (a)(4)(viii);
0
h. Revising paragraph (a)(5) introductory text;
0
i. Adding paragraph (a)(5)(vii);
0
j. Revising paragraph (a)(6) introductory text;
0
k. Adding paragraph (a)(6)(vi);
0
l. Revising paragraph (a)(7) introductory text;
0
m. Redesignating paragraphs (a)(7)(i) through (vi) as paragraphs
(a)(7)(ii) through (vii), respectively;
0
n. Adding new paragraph (a)(7)(i) and paragraph (a)(7)(viii);
0
o. Revising paragraph (a)(8) introductory text;
0
p. Adding paragraph (a)(8)(iv);
0
q. Revising paragraphs (a)(9) introductory text and (a)(9)(xii);
0
r. Adding paragraph (a)(9)(xiii);
0
s. Revising paragraphs (a)(10), (b), (c), (d)(1)(iii), and
(d)(2)(iii)(L);
0
t. Adding paragraph (d)(2)(iv);
0
u. Revising paragraphs (e) introductory text, (e)(1) introductory text,
and (e)(1)(viii), (xi), (xii), and (xv) through (xviii);
0
v. Adding paragraph (e)(1)(xix);
0
w. Revising paragraph (e)(2);
0
x. Removing and reserving paragraph (e)(3);
0
y. Revising paragraphs (f)(1) introductory text and (f)(1)(iii);
0
z. Adding paragraphs (f)(1)(xi)(F) and (f)(1)(xii)(F);
0
aa. Revising paragraphs (f)(2) introductory text and (f)(2)(iii), (ix)
and (x);
0
bb. Adding paragraphs (f)(2)(xi) and (xii);
0
cc. Revising paragraphs (g)(10), (h)(2) introductory text, and
(h)(2)(v) through (vii);
0
dd. Adding paragraphs (h)(2)(viii) through (xvi);
0
ee. Revising paragraphs (h)(4) introductory text and (h)(4)(iii)
through (v);

0
ff. Adding paragraphs (h)(4)(vi) through (xiv);
0
gg. Revising paragraphs (i)(1) introductory text, (j) introductory
text, (j)(1) and (2), (j)(3)(ii), (k)(1)(ii) through (iv), (k)(2)
introductory text, (k)(3), (l)(1) introductory text, (l)(2)
introductory text, and (l)(2)(vi) through (viii);
0
hh. Adding paragraphs (l)(2)(ix) through (xvii);
0
ii. Revising paragraphs (l)(3) introductory text, (l)(4) introductory
text, and (l)(4)(v) through (vii);
0
jj. Adding paragraphs (l)(4)(viii) through (xvi);
0
kk. Revising paragraphs (m)(4) through (8), (n), (o)(1), (o)(2)(i)(B),
(o)(2)(ii)(A), (o)(5)(i) through (iii), (p)(1), (p)(2)(ii)(A),
(p)(3)(ii) introductory text, (p)(5)(i) through (iii), (q)(1)
introductory text, and (q)(1)(iii);
0
ll. Adding paragraphs (q)(1)(vi) and (vii);
0
mm. Revising paragraphs (q)(2), (r)(1) introductory text, and
(r)(1)(i);
0
nn. Removing and reserving paragraph (r)(3);
0
oo. Revising paragraphs (s) introductory text, (y), (z) introductory
text, (z)(2)(i) and (iv) through (vi), (aa)(3) introductory text, and
(aa)(3)(i);
0
pp. Adding paragraph (aa)(3)(viii);
0
qq. Removing and reserving paragraph (aa)(9);
0
rr. Revising paragraph (aa)(10) introductory text;
0
ss. Adding paragraphs (aa)(10)(v) and (vi); and
0
tt. Revising paragraphs (aa)(11)(ii) and (iii), (bb) introductory text,
and (cc).
    The revisions and additions read as follows:

Sec.  98.236  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain reported emissions and related information
as specified in this section. Reporters that use a flow or volume
measurement system that corrects to standard conditions as provided in
the introductory text in Sec.  98.233 for data elements that are
otherwise required to be determined at actual conditions, report gas
volumes at standard conditions rather than the gas volumes at actual
conditions and report the standard temperature and pressure used by the
measurement system rather than the actual temperature and pressure.
    (a) * * *
    (1) Onshore petroleum and natural gas production. For the
equipment/activities specified in paragraphs (a)(1)(i) through (xix) of
this section, report the information specified in the applicable
paragraphs of this section.
* * * * *
    (xviii) Other large release events. Report the information
specified in paragraph (y) of this section.
    (xix) Combustion equipment. Report the information specified in
paragraph (z) of this section.
    (2) Offshore petroleum and natural gas production. Report the
information specified in paragraphs (s) and (y) of this section.
    (3) Onshore natural gas processing. For the equipment/activities
specified in paragraphs (a)(3)(i) through (ix) of this section, report
the information specified in the applicable paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified
in paragraph (b) of this section.
* * * * *
    (ix) Other large release events. Report the information specified
in paragraph (y) of this section.
    (4) Onshore natural gas transmission compression. For the
equipment/activities specified in paragraphs (a)(4)(i) through (viii)
of this section, report the information specified in the applicable
paragraphs of this section.
* * * * *
    (viii) Other large release events. Report the information specified
in paragraph (y) of this section.
    (5) Underground natural gas storage. For the equipment/activities
specified in paragraphs (a)(5)(i) through (vii) of this section, report
the information specified in the applicable paragraphs of this section.
* * * * *
    (vii) Other large release events. Report the information specified
in paragraph (y) of this section.
    (6) LNG storage. For the equipment/activities specified in
paragraphs (a)(6)(i) through (vi) of this section, report the
information specified in the applicable paragraphs of this section.
* * * * *
    (vi) Other large release events. Report the information specified
in paragraph (y) of this section.
    (7) LNG import and export equipment. For the equipment/activities
specified in paragraphs (a)(7)(i) through (viii) of this section,
report the information specified in the applicable paragraphs of this
section.
    (i) Acid gas removal units. Report the information specified in
paragraph (d) of this section.
* * * * *
    (viii) Other large release events. Report the information specified
in paragraph (y) of this section.
    (8) Natural gas distribution. For the equipment/activities
specified in paragraphs (a)(8)(i) through (iv) of this section, report
the information specified in the applicable paragraphs of this section.
* * * * *
    (iv) Other large release events. Report the information specified
in paragraph (y) of this section.
    (9) Onshore petroleum and natural gas gathering and boosting. For
the equipment/activities specified in paragraphs (a)(9)(i) through
(xiii) of this section, report the information specified in the
applicable paragraphs of this section.
* * * * *
    (xii) Other large release events. Report the information specified
in paragraph (y) of this section.
    (xiii) Combustion equipment. Report the information specified in
paragraph (z) of this section.
    (10) Onshore natural gas transmission pipeline. For blowdown vent
stacks, report the information specified in paragraphs (i) and (y) of
this section.
    (b) Natural gas pneumatic devices. You must indicate whether the
facility contains the following types of equipment: Continuous high
bleed natural gas pneumatic devices, continuous low bleed natural gas
pneumatic devices, and intermittent bleed natural gas pneumatic
devices. If the facility contains any continuous high bleed natural gas
pneumatic devices, continuous low bleed natural gas pneumatic devices,
or intermittent bleed natural gas pneumatic devices, then you must
report the information specified in paragraphs (b)(1) through (4) of
this section.
    (1) The number of natural gas pneumatic devices as specified in
paragraphs (b)(1)(i) through (iii) of this section.
    (i) For onshore natural gas processing, onshore natural gas
transmission compression, and underground natural gas storage
facilities, the total number of devices of each type (continuous low
bleed, continuous high bleed, and intermittent bleed), determined
according to Sec.  98.233(a)(2).
    (ii) For onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting facilities, the number
of devices by each type as specified in paragraphs (b)(1)(ii)(A)
through (E) of this section.
    (A) Continuous low bleed devices.
    (B) Continuous high bleed devices.
    (C) Intermittent bleed devices subject to part 60, subpart OOOOb of
this chapter or an applicable approved state plan or applicable Federal
plan in part 62 of this chapter (i.e., the number required to use
Equation W-1B).
    (D) Intermittent bleed devices not subject to part 60, subpart
OOOOb of

this chapter or an applicable approved state plan or applicable Federal
plan in part 62 of this chapter but routinely monitored (i.e., the
number electing to use Equation W-1B).
    (E) Intermittent bleed devices not subject to part 60, subpart
OOOOb of this chapter or an applicable approved state plan or
applicable Federal plan in part 62 of this chapter and not routinely
monitored (i.e., the number using Equation W-1A).
    (iii) If the reported values in paragraphs (b)(1)(ii)(A), (B), and
(E) of this section are estimated values determined according to Sec.
98.233(a)(3), then you must report the information specified in
paragraphs (b)(1)(iii)(A) through (C) of this section.
    (A) The number of devices of each type reported in paragraphs
(b)(1)(ii)(A), (B), and (E) of this section that are counted.
    (B) The number of devices of each type reported in paragraphs
(b)(1)(ii)(A), (B), and (E) of this section that are estimated (not
counted).
    (C) Whether the calendar year is the first calendar year of
reporting or the second calendar year of reporting.
    (2) For each type of pneumatic device for which Equation W-1A of
this subpart is used, report the information in paragraphs (b)(2)(i)
through (iii) of this section.
    (i) The estimated average number of hours in the calendar year that
the natural gas pneumatic devices reported in paragraph (b)(1)(i) or
paragraphs (b)(1)(ii)(A), (B), and (E) of this section, as applicable,
were in service (i.e., supplied with natural gas) in the calendar year
(``Tt'' in Equation W-1A of this subpart).
    (ii) Annual CO2 emissions, in metric tons
CO2, for the natural gas pneumatic devices combined,
calculated using Equation W-1A of this subpart and Sec.  98.233(a)(5),
and reported in paragraph (b)(1)(i) or paragraphs (b)(1)(ii)(A), (B),
and (E) of this section, as applicable.
    (iii) Annual CH4 emissions, in metric tons
CH4, for the natural gas pneumatic devices combined,
calculated using Equation W-1A of this subpart and Sec.  98.233(a)(5),
and reported in paragraph (b)(1)(i) or paragraphs (b)(1)(ii)(A), (B),
and (E) of this section, as applicable.
    (3) For intermittent bleed pneumatic devices for which Equation W-
1B of this subpart is used, report the information in paragraphs
(b)(3)(i) through (iii) of this section.
    (i) The total number of intermittent devices detected as
malfunctioning in any pneumatic device monitoring survey during the
calendar year (``x'' in Equation W-1B of this subpart).
    (ii) Average time the intermittent devices were in service (i.e.,
supplied with natural gas) and assumed to be malfunctioning in the
calendar year (average value of ``Tz'' in Equation W-1B of
this subpart).
    (iii) The total number of intermittent devices that were monitored
but were not detected as malfunctioning in any pneumatic device
monitoring survey during the calendar year (``Count'' in Equation W-1B
of this subpart).
    (iv) Average time the intermittent devices that were monitored but
were not detected as malfunctioning in any pneumatic device monitoring
survey during the calendar year were in service (i.e., supplied with
natural gas) during the calendar year (``Tavg'' in Equation
W-1B of this subpart).
    (v) Annual CO2 emissions, in metric tons CO2,
for the natural gas intermittent bleed pneumatic devices combined for
which emissions were calculated using Equation W-1B of this subpart and
Sec.  98.233(a)(6).