was supplied to the devices to the number of hours the natural gas
supplied to the devices was measured.
    (B) Convert the natural gas volumetric flow from paragraph
(a)(1)(i)(A) of this section to CH4 and CO2
volumetric emissions following the provisions in paragraph (u) of this
section.
    (C) Convert the CH4 and CO2 volumetric
emissions from paragraph (a)(1)(i)(B) of this section to CH4
and CO2 mass emissions using calculations in paragraph (v)
of this section.
    (ii) For mass flow monitors:
    (A) Determine the cumulative annual mass flow, in metric tons, as
measured by the flow monitor in the reporting year. If all natural gas
pneumatic devices supplied by the measured natural gas supply line are
vented directly to the atmosphere for only a portion of the year and
are routed to a flare, combustion, or vapor recovery system for the
remaining portion of the year, determine the cumulative annual mass
flow considering only those times when one or more of the natural gas
pneumatic devices were vented directly to the atmosphere. If the flow
meter was installed during the year, escalate the measured mass flow by
the ratio of the total hours for which natural gas was supplied to the
devices to the number of hours the natural gas supplied to the devices
was measured.
    (B) Convert the cumulative mass flow from paragraph (a)(1)(ii)(A)
of this section to CH4 and CO2 mass emissions by
multiplying by the mass fraction of CH4 and CO2
in the supplied natural gas. You must follow the provisions in
paragraph (u) of this section for determining the mole fraction of
CH4 and CO2 and use molecular weights of 16 kg/
kg-mol and 44 kg/kg-mol for CH4 and CO2,
respectively. You may assume unspecified components have an average
molecular weight of 28 kg/kg-mol.
    (iii) If the flow meter on the natural gas supply line serves both
natural gas pneumatic devices and natural gas driven pneumatic pumps,
disaggregate the total measured amount of natural gas to pneumatic
devices and natural gas driven pneumatic pumps based on engineering
calculations and best available data.
    (iv) The flow meter must be operated and calibrated according to
the methods set forth in Sec.  98.234(b).
    (2) Calculation Method 2. Except as provided in paragraphs (a)(1)
and (3) of this section, you must measure the volumetric flow rate of
each natural gas pneumatic device vent that vents directly to the
atmosphere at your facility as specified in paragraphs (a)(2)(i)
through (ix) of this section. You must exclude the counts of devices
measured according to paragraph (a)(1) of this section from the counts
of devices to be measured or for which emissions are calculated
according to the requirements in this paragraph (a)(2).
    (i) For facilities in the onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and boosting
industry segments, you must measure all natural gas pneumatic devices
at your facility at least once every 5 years. If you elect to measure
your pneumatic devices over multiple years, you must measure
approximately the same number of devices each year. When you measure
the emissions from natural gas pneumatic devices at a well-pad or
gathering and boosting site, you must measure all natural gas pneumatic
devices that are vented directly to the atmosphere at the well-pad or
gathering and boosting site during the same calendar year.
    (ii) For facilities in the onshore natural gas processing, onshore
natural gas transmission compression, underground natural gas storage,
or natural gas distribution industry

segments, you must either measure all natural gas pneumatic devices
vented directly to the atmosphere at your facility each year if your
facility has less than 26 pneumatic devices or over multiple years not
to exceed the number of years as specified in paragraphs (a)(2)(ii)(A)
through (D) of this section. If you elect to measure your pneumatic
devices over multiple years, you must measure approximately the same
number of devices each year.
    (A) If your facility has at least 26 but not more than 50 natural
gas pneumatic devices vented directly to the atmosphere, the maximum
number of years to measure all devices at your facility is 2 years.
    (B) If your facility has at least 51 but not more than 75 natural
gas pneumatic devices vented directly to the atmosphere, the maximum
number of years to measure all devices at your facility is 3 years.
    (C) If your facility has at least 76 but not more than 100 natural
gas pneumatic devices vented directly to the atmosphere, the maximum
number of years to measure all devices at your facility is 4 years.
    (D) If your facility has 101 or more natural gas pneumatic devices
vented directly to the atmosphere, the maximum number of years to
measure all devices at your facility is 5 years.
    (iii) For all industry segments, determine the volumetric flow rate
of each natural gas pneumatic device vent (in standard cubic feet per
hour) using one of the methods specified in Sec.  98.234(b) through
(d), as appropriate, according to the requirements specified in
paragraphs (a)(2)(iii)(A) through (D) of this section.
    (A) If you use a temporary meter, such as a vane anemometer,
according to the methods set forth in Sec.  98.234(b) or a high volume
sampler according to methods set forth Sec.  98.234(d), you must
measure the emissions from each device for a minimum of 15 minutes
while the device is in service (i.e., supplied with natural gas),
except for natural gas pneumatic isolation valve actuators. For natural
gas pneumatic isolation valve actuators, you must measure the emissions
from each device for a minimum of 5 minutes while the device is in
service (i.e., supplied with natural gas). If there is no measurable
flow from the natural gas pneumatic device after the minimum sampling
period, you can discontinue monitoring and follow the applicable
methods in paragraph (a)(2)(v) of this section.
    (B) If you use calibrated bagging, follow the methods set forth in
Sec.  98.234(c) except you need only fill one bag to have a valid
measurement. You must collect sample for a minimum of 5 minutes for
natural gas pneumatic isolation valve actuators or 15 minutes for other
natural gas pneumatic devices. If no gas is collected in the calibrated
bag during the minimum sampling period, you can discontinue monitoring
and follow the applicable methods in paragraph (a)(2)(v) of this
section. If gas is collected in the bag during the minimum sampling
period, you must either continue sampling until you fill the calibrated
bag or you may elect to remeasure the vent according to paragraph
(a)(2)(iii)(A) of this section.
    (C) You do not need to use the same measurement method for each
natural gas pneumatic device vent.
    (D) If the measurement method selected measures the volumetric flow
rate in actual cubic feet, convert the measured flow to standard cubic
feet following the methods specified in paragraph (t)(1) of this
section.
    (iv) For all industry segments, if there is measurable flow from
the device vent, calculate the volume of natural gas emitted from each
natural gas pneumatic device vent as the product of the natural gas
flow rate measured in paragraph (a)(2)(iii) of this section and the
number of hours the pneumatic device was in service (i.e., supplied
with natural gas) in the calendar year.
    (v) For all industry segments, if there is no measurable flow from
the device vent, estimate the emissions from the device according to
the methods in paragraphs (a)(2)(v)(A) through (C) of this section, as
applicable.
    (A) For continuous high bleed pneumatic devices:
    (1) Confirm that the device is in-service. If not, remeasure the
device according to paragraph (a)(2)(iii) of this section at a time the
device is in-service.
    (2) Confirm that the device is correctly characterized as a
continuous high bleed pneumatic device according to the provisions in
paragraph (a)(6) of this section. If the device type was
mischaracterized, recharacterize the device type and use the
appropriate methods in paragraphs (a)(2)(v)(B) or (C) of this section,
as applicable.
    (3) Upon confirmation of the items in paragraphs (a)(2)(v)(A)(1)
and (2) of this section, remeasure the device vent using a different
measurement method or longer monitoring duration until the volumetric
venting rate can be accurately quantified.
    (B) For continuous low bleed pneumatic devices:
    (1) Confirm that the device is in-service. If not, remeasure the
device according to paragraph (a)(2)(iii) of this section at a time the
device is in-service.
    (2) Determine natural gas bleed rate (in standard cubic feet per
hour) at the supply pressure used for the pneumatic device based on the
manufacturer's steady state natural gas bleed rate reported for the
device. If the steady state bleed rate is reported in terms of air
consumption, multiply the air consumption rate by 1.29 to calculate the
steady state natural gas bleed rate. If a steady state bleed rate is
not reported, you need to reassess whether the device is correctly
characterized as a continuous low bleed pneumatic device according to
the provisions in paragraph (a)(6) of this section.
    (3) Calculate the volume of natural gas emitted from the natural
gas pneumatic device vent as the product of the natural gas steady
state bleed rate determined in paragraph (a)(2)(v)(B)(2) of this
section and number of hours the pneumatic device was in service (i.e.,
supplied with natural gas) in the calendar year.
    (C) For intermittent bleed pneumatic devices:
    (1) Confirm that the device is in-service. If not, remeasure the
device according to paragraph (a)(2)(iii) of this section at a time the
device is in-service and calculate natural gas emissions according to
paragraph (a)(2)(iv) of this section. For devices confirmed to be in-
service during the measurement period, calculate natural gas emissions
according to paragraph (a)(2)(v)(C)(2) through (5) of this section.
    (2) Calculate the volume of the controller, tubing and actuator (in
actual cubic feet) based on the device and tubing size.
    (3) Sum the volumes in paragraph (a)(2)(v)(C)(2) of this section
and convert the volume to standard cubic feet following the methods
specified in paragraph (t)(1) of this section based on the natural gas
supply pressure.
    (4) Estimate the number of actuations during the year based on
company records, if available, or best engineering estimates. For
isolation valve actuators, you may multiply the number of valve
closures during the year by 2 (one actuation to close the valve; one
actuation to open the valve).
    (5) Calculate the volume of natural gas emitted from the natural
gas pneumatic device vent as the product of the per actuation volume in
standard cubic feet determined in paragraph (a)(2)(v)(C)(3) of this
section, the number of actuations during the year as determined in
paragraph (a)(2)(v)(C)(4) of this section, and the relay correction
factor. Use 1 for the relay correction factor if there is no relay; use
3 for the relay correction factor if there is a relay.
    (6) Calculate the hourly average volume of natural gas emitted from
the

natural gas pneumatic device vent by dividing the volume of natural gas
emitted as determined in paragraph (a)(2)(v)(C)(5) of this section by
the number of hours the pneumatic device was in service (i.e., supplied
with natural gas) in the calendar year.
    (vi) For each pneumatic device, convert the volumetric emissions of
natural gas at standard conditions determined in paragraph (a)(2)(iv)
or (v) of this section, as applicable, to CO2 and
CH4 volumetric emissions at standard conditions using the
methods specified in paragraph (u) of this section.
    (vii) For each pneumatic device, convert the GHG volumetric
emissions at standard conditions determined in paragraph (a)(2)(vi) of
this section to GHG mass emissions using the methods specified in
paragraph (v) of this section.
    (viii) Sum the CO2 and CH4 mass emissions
determined in paragraph (a)(2)(vii) of this section separately for each
type of natural gas pneumatic device (continuous high bleed, continuous
low bleed, and intermittent bleed).
    (ix) If you chose to conduct natural gas pneumatic device
measurements over multiple years, ``n,'' according to paragraph
(a)(2)(i) or (ii) of this section, then you must calculate the
emissions from all pneumatic devices at your facility as specified in
paragraph (a)(2)(ix)(A) through (D) of this section.
    (A) Use the emissions calculated in (a)(2)(viii) of this section
for the devices measured during the reporting year.
    (B) Calculate the whole gas emission factor for each type of
pneumatic device at the facility using Equation W-1A and all available
data from the current year and the previous years in your monitoring
cycle (n-1 years) for which natural gas pneumatic device vent
measurements were made according to Calculation Method 2 in paragraph
(a)(2) of this section (e.g., if your monitoring cycle is 3 years, then
use measured data from the current year and the two previous years).
This emission factor must be updated annually.
[GRAPHIC] [TIFF OMITTED] TP01AU23.000

Where:

EFt = Whole gas population emission factor for natural
gas pneumatic device vents of type ``t'' (continuous high bleed,
continuous low bleed, intermittent bleed), in standard cubic feet
per hour per device.
MTs,t,y = Volumetric whole gas emissions rate measurement
at standard (``s'') conditions from component type ``t'' during year
``y'' in standard cubic feet per hour, as calculated in paragraph
(a)(2)(iii) [if there was measurable flow from the device vent],
(a)(2)(v)(B)(2), or (a)(2)(v)(C)(6) of this section, as applicable.
Countt,y = Count of natural gas pneumatic device vents of
type ``t'' measured according to Calculation Method 2 in year ``y.''
n = Number of years of data to include in the emission factor
calculation according to the number of years used to monitor all
natural gas pneumatic device vents at the facility.

    (C) Calculate CH4 and CO2 volumetric
emissions from continuous high bleed, continuous low bleed, and
intermittent bleed natural gas pneumatic devices that were not measured
during the reporting year using Equation W-1B of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.001

Where:

Es,i = Annual total volumetric GHG emissions at standard
conditions in standard cubic feet per year from natural gas
pneumatic device vents, of types ``t'' (continuous high bleed,
continuous low bleed, intermittent bleed), for GHGi.
Countt = Total number of natural gas pneumatic devices of
type ``t'' (continuous high bleed, continuous low bleed,
intermittent bleed) as determined in paragraphs (a)(4) through (6)
of this section that vent directly to the atmosphere and that were
not directly measured according to the requirements in paragraph
(a)(1) or (a)(2)(iii) of this section.
EFt = Population emission factors for natural gas
pneumatic device vents (in standard cubic feet per hour per device)
of each type ``t'' (continuous high bleed, continuous low bleed,
intermittent bleed) as calculated using Equation W-1A of this
section.
GHGi = For onshore petroleum and natural gas production
facilities, onshore petroleum and natural gas gathering and boosting
facilities, onshore natural gas processing, onshore natural gas
transmission compression facilities, underground natural gas storage
facilities, and natural gas distribution facilities, concentration
of GHGi, CH4 or CO2, in produced
natural gas or processed natural gas for each facility as specified
in paragraph (u)(2) of this section.
Tt = Average estimated number of hours in the operating
year the devices, of each type ``t'', were in service (i.e.,
supplied with natural gas) using engineering estimates based on best
available data. Default is 8,760 hours.

    (D) Convert the volumetric emissions calculated using Equation W-1B
to CH4 and CO2 mass emissions using the methods
specified in paragraph (v) of this section.
    (E) Sum the CH4 and CO2 mass emissions
calculated in paragraphs (a)(2)(ix)(A) and (D) of this section
separately for each type of pneumatic device (continuous high bleed,
continuous low bleed, intermittent bleed) to calculate the total
CH4 and CO2 mass emissions by device type for
Calculation Method 2.
    (3) Calculation Method 3. As an alternative to Calculation Method
2, you may elect to use the applicable methods specified in paragraphs
(a)(3)(i) through (v) of this section, as applicable, to calculate
CH4 and CO2 emissions from your natural gas
pneumatic devices that are vented directly to the atmosphere at your
facility except those that are measured according to paragraph (a)(1)
of this section. You must exclude the counts of devices measured
according to paragraph (a)(1) of this section from the counts of
devices to be monitored or for which emissions are calculated according
to the requirements in this paragraph (a)(3).
    (i) For continuous high bleed and continuous low bleed natural gas
pneumatic devices vented directly to the atmosphere, you must calculate
CH4 and CO2 volumetric emissions using either the
methods in paragraph (a)(3)(i)(A) or (B) of this section.

    (A) Measure all continuous high bleed and continuous low bleed
pneumatic devices at your well-pad, gathering and boosting site, or
facility, as applicable, according to the provisions in paragraphs
(a)(2) of this section.
    (B) Use Equation W-1B, except use the appropriate default whole gas
population emission factors for natural gas pneumatic device vents (in
standard cubic feet per hour per device) of each type ``t'' (continuous
high bleed and continuous low bleed) as listed in table W-1 to this
subpart.
    (ii) For intermittent bleed pneumatic devices, you must monitor
each intermittent bleed pneumatic device at your facility using the
methods specified in paragraph (a)(3)(ii)(A) of this section at the
frequency specified in paragraph (a)(3)(ii)(B) or (C) of this section,
as applicable.
    (A) You must use one of the monitoring methods specified in Sec.
98.234(a)(1) through (3) except that the monitoring dwell time for each
device vent must be at least 2 minutes or until a malfunction is
identified, whichever is shorter. A device is considered malfunctioning
if any leak is observed when the device is not actuating or if a leak
is observed for more than 5 seconds during a device actuation. If you
cannot tell when a device is actuating, any observed leak from the
device indicates a malfunctioning device.
    (B) For facilities in the onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and boosting
industry segments, you must monitor all natural gas intermittent bleed
pneumatic devices at your facility at least once every 5 years. If you
elect to monitor your pneumatic devices over multiple years, you must
monitor approximately the same number of devices each year. When you
monitor the emissions from natural gas pneumatic devices at a well-pad
or gathering and boosting site, you must monitor all natural gas
intermittent bleed pneumatic devices that are vented directly to the
atmosphere at the well-pad or gathering and boosting site during the
same calendar year.
    (C) For facilities in the onshore natural gas processing, onshore
natural gas transmission compression, underground natural gas storage,
or natural gas distribution industry segments you must either monitor
all natural gas intermittent bleed pneumatic devices vented directly to
the atmosphere at your facility each year if your facility has less
than 101 intermittent bleed pneumatic devices or over multiple years
not to exceed the number of years as specified in paragraphs
(a)(3)(ii)(C)(1) through (4) of this section. If you elect to monitor
your intermittent bleed pneumatic devices over multiple years, you must
monitor approximately the same number of devices each year.
    (1) If your facility has at least 101 but not more than 200 natural
gas intermittent bleed pneumatic devices vented directly to the
atmosphere, the maximum number of years to monitor all devices at your
facility is 2 years.
    (2) If your facility has at least 201 but not more than 300 natural
gas intermittent bleed pneumatic devices vented directly to the
atmosphere, the maximum number of years to monitor all devices at your
facility is 3 years.
    (3) If your facility has at least 301 but not more than 400 natural
gas intermittent bleed pneumatic devices vented directly to the
atmosphere, the maximum number of years to monitor all devices at your
facility is 4 years.
    (4) If your facility has 401 or more natural gas intermittent bleed
pneumatic devices vented directly to the atmosphere, the maximum number
of years to monitor all devices at your facility is 5 years.
    (iii) For intermittent bleed pneumatic devices that are monitored
according to paragraph (a)(3)(ii)(A) of this section during the
reporting year, you must calculate CH4 and CO2
volumetric emissions from intermittent bleed natural gas pneumatic
devices vented directly to the atmosphere using Equation W-1C of this
section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.002

Where:
Ei = Annual total volumetric emissions of GHGi
from intermittent bleed natural gas pneumatic devices in standard
cubic feet.
GHGi = Concentration of GHGi, CH4, or
CO2, in natural gas supplied to the intermittent bleed
natural gas pneumatic device as defined in paragraph (u)(2) of this
section.
x = Total number of intermittent bleed natural gas pneumatic devices
detected as malfunctioning in any pneumatic device monitoring survey
during the year. A component found as malfunctioning in two or more
surveys during the year is counted as one malfunctioning component.
16.1 = Whole gas emission factor for malfunctioning intermittent
bleed natural gas pneumatic devices, in standard cubic feet per hour
per device.
Tmal,z = The total time the surveyed pneumatic device
``z'' was in service (i.e., supplied with natural gas) and assumed
to be malfunctioning, in hours. If one pneumatic device monitoring
survey is conducted in the calendar year, assume the device found
malfunctioning was malfunctioning for the entire calendar year. If
multiple pneumatic device monitoring surveys are conducted in the
calendar year, assume a device found malfunctioning in the first
survey was malfunctioning since the beginning of the year until the
date of the survey; assume a device found malfunctioning in the last
survey of the year was malfunctioning from the preceding survey
through the end of the year; assume a device found malfunctioning in
a survey between the first and last surveys of the year was
malfunctioning since the preceding survey until the date of the
survey; and sum times for all malfunctioning periods.
Tt,z = The total time the surveyed natural gas pneumatic
device ``z'' was in service (i.e., supplied with natural gas) during
the year. Default is 8,760 hours for non-leap years and 8,784 hours
for leap years.
2.82 = Whole gas emission factor for properly operating intermittent
bleed natural gas pneumatic devices, in standard cubic feet per hour
per device.
Count = Total number of intermittent bleed natural gas pneumatic
devices that were never observed to be malfunctioning during any
monitoring survey during the year.
Tavg = The average time the intermittent bleed natural
gas pneumatic devices that were never observed to be malfunctioning
during any monitoring survey were in service (i.e., supplied with
natural gas) using engineering estimates based on best available
data. Default is 8,760 hours for non-leap years and 8,784 hours for
leap years.

    (A) You must conduct at least one complete pneumatic device
monitoring survey in a calendar year. If you conduct multiple complete
pneumatic device monitoring surveys in a calendar year, you must use
the results from each complete pneumatic device monitoring survey when
calculating emissions using Equation W-1C.
    (B) For the purposes of paragraph (a)(3)(iii)(A) of this section, a
complete monitoring survey is a survey of all

intermittent bleed natural gas pneumatic devices vented directly to the
atmosphere at a well-pad for onshore petroleum and natural gas
production facilities, all intermittent bleed pneumatic devices vented
directly to the atmosphere at a gathering and boosting site for onshore
petroleum and natural gas gathering and boosting facilities, or all
intermittent bleed natural gas pneumatic devices vented directly to the
atmosphere at a facility required to be monitored during a given year
for other applicable industry segments.
    (iv) For intermittent bleed natural gas pneumatic devices that are
not monitored according to paragraph (a)(3)(ii)(A) of this section
during the reporting you, you must calculate CH4 and
CO2 volumetric emissions from intermittent bleed natural gas
pneumatic devices vented directly to the atmosphere as specified in
paragraphs (a)(3)(iv)(A) through (D) of this section.
    (A) Count the number of unique intermittent bleed natural gas
pneumatic devices vented directly to the atmosphere that were monitored
during the reporting year. If you conducted multiple monitoring
surveys, count each device only once; do not count the same device
twice if it was monitored two times during the reporting year.
    (B) Count the number of unique intermittent bleed natural gas
pneumatic devices vented directly to the atmosphere that were monitored
during the reporting year that were identified as malfunctioning during
the reporting year. If you conducted multiple monitoring surveys, count
each device only once; do not count the same device twice if it was
monitored and identified as malfunctioning two separate times during
the reporting. If a device was malfunctioning during one monitoring
survey and not during a second, count that device as a device that was
identified as malfunctioning during the reporting year.
    (C) Determine the number of intermittent bleed natural gas
pneumatic devices vented directly to the atmosphere at your facility
that were not monitored during the reporting year as the difference
between the total count of devices at your facility as determined
according to paragraphs (a)(4) through (6) of this section and the
count of unique devices monitored during the reporting year as
determined in paragraph (a)(3)(vi)(A) of this section.
    (D) Calculate CH4 and CO2 volumetric
emissions from intermittent bleed natural gas pneumatic devices vented
directly to the atmosphere that were not monitored during the reporting
year using Equation W-1D of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.003

Where:

Ei = Annual total volumetric emissions of GHGi
from intermittent bleed natural gas pneumatic devices in standard
cubic feet.
GHGi = Concentration of GHGi, CH4 or CO2, in
natural gas supplied to the intermittent bleed device as defined in
paragraph (u)(2) of this section.
Tavg = The average time the intermittent bleed natural
gas pneumatic devices that were not surveyed during the year were in
service (i.e., supplied with natural gas) using engineering
estimates based on best available data. Default is 8,760 hours.
CountC = Total number of intermittent bleed pneumatic
devices that were not surveyed during the year as determined
according to paragraph (a)(3)(iv)(C) of this section.
16.1 = Whole gas emission factor for malfunctioning intermittent
bleed natural gas pneumatic devices, in standard cubic feet per hour
per device.
CountB = Total number of unique intermittent bleed
natural gas pneumatic devices vented directly to the atmosphere that
were monitored during the reporting year that were identified as
malfunctioning during the reporting year as determined according to
paragraph (a)(3)(iv)(B) of this section.
CountA = Total number the number of unique intermittent
bleed natural gas pneumatic devices vented directly to the
atmosphere that were monitored during the reporting year as
determined according to paragraph (a)(3)(iv)(A) of this section.
2.82 = Whole gas emission factor for properly operating intermittent
bleed natural gas pneumatic devices, in standard cubic feet per hour
per device.

    (v) You must convert the CH4 and CO2
volumetric emissions as determined according to paragraphs (a)(3)(i),
(iii) and (iv) of this section and calculate both CO2 and
CH4 mass emissions using calculations in paragraph (v) of
this section for each type of natural gas pneumatic device (continuous
high bleed, continuous low bleed, and intermittent bleed).
    (4) Counts of natural gas pneumatic devices. For all industry
segments, determine ``Countt'' for Equation W-1A, W-1B, or W-1C of this
subpart for each type of natural gas pneumatic device (continuous high
bleed, continuous low bleed, and intermittent bleed) by counting the
total number of devices at the facility, the number of devices that are
vented directly to the atmosphere and the number of those devices that
were measured or monitored during the reporting year, as applicable,
except as specified in paragraph (a)(5) of this section.
    (5) Counts of onshore petroleum and natural gas production industry
segment or the onshore petroleum and natural gas gathering and boosting
natural gas pneumatic devices. For facilities in the onshore petroleum
and natural gas production industry segment or the onshore petroleum
and natural gas gathering and boosting industry segment, you have the
option in the first two consecutive calendar years to determine the
total number of natural gas pneumatic devices at the facility and the
number of devices that are vented directly to the atmosphere for each
type of natural gas pneumatic device (continuous high bleed, continuous
low bleed, and intermittent bleed), as applicable, using engineering
estimates based on best available data. Counts of natural gas pneumatic
devices measured or monitored during the reporting year must be made
based on actual counts.
    (6) Type of natural gas pneumatic devices. For all industry
segments, determine the type of natural gas pneumatic device using
engineering estimates based on best available information.
    (7) Routing to flares, combustion, or vapor recovery systems.
Calculate emissions from natural gas pneumatic devices routed to
flares, combustion, or vapor recovery systems as specified in paragraph
(a)(7)(i) or (ii) of this section, as applicable. If a device was
vented directly to the atmosphere for part of the year and routed to a
flare, combustion unit, or vapor recovery system during another part of
the year, then calculate emissions from the time the device vents
directly to the atmosphere as specified in paragraph (a)(1), (2) or (3)
of this section, as applicable, and calculate emissions from the time
the device was routed to a flare or combustion as specified in
paragraph (a)(7)(i) or (ii) of this section, as applicable. During
periods when natural

gas pneumatic device emissions are collected in a vapor recovery system
that is not routed to combustion, paragraphs (a)(1) through (3) and
(a)(7)(i) and (ii) of this section do not apply and no emissions
calculations are required.
    (i) If any natural gas pneumatic devices were routed to a flare,
you must calculate CH4, CO2, and N2O
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).
    (ii) If emissions from any natural gas pneumatic devices were
routed to combustion units, you must calculate and report emissions as
specified in subpart C of this part or calculate emissions as specified
in paragraph (z) of this section and report emissions from the
combustion equipment as specified in Sec.  98.236(z), as applicable.
* * * * *
    (c) Natural gas driven pneumatic pump venting. Calculate emissions
from natural gas driven pneumatic pumps venting directly to the
atmosphere as specified in paragraph (c)(1), (2), or (3) of this
section, as applicable. If you have a flow meter on the natural gas
supply line that is dedicated to any one or more natural gas driven
pneumatic pumps, each of which only vents directly to the atmosphere,
you must use Calculation Method 1 as specified in paragraph (c)(1) of
this section to calculate vented CH4 and CO2
emissions from those pumps. Use Calculation Method 1 for any portion of
a year when all of the pumps on the measured natural gas supply line
were vented directly to atmosphere. For natural gas driven pneumatic
pumps vented directly to the atmosphere for which the natural gas
supply rate is not measured, use either the method specified in
paragraph (c)(2) or (3) of this section to calculate vented
CH4 and CO2 emissions for all of the natural gas
driven pneumatic pumps at your facility that are not subject to
Calculation Method 1; you may not use Calculation Method 2 for some
vented natural gas driven pneumatic pumps and Calculation Method 3 for
other natural gas driven pneumatic pumps. Similarly, if a flow meter is
on a natural gas supply line that supplies some pumps that vent
directly to the atmosphere and others that route emissions to flares,
combustion, or vapor recovery systems, then use either the method
specified in paragraph (c)(2) or (3) of this section to calculate
vented CH4 and CO2 emissions because Calculation
Method 1 may not be used for this natural gas supply line. Calculate
emissions from natural gas driven pneumatic pumps routed to flares or
combustion as specified in paragraph (c)(4) of this section. If a pump
vents directly to the atmosphere for part of the year and to a flare or
combustion unit for another part of the year, then calculate vented
emissions for the portion of the year when venting occurs using the
applicable method in paragraph (c)(1), (2), or (3) of this section for
the period when venting occurs, and calculate emissions for the portion
of the year when the emissions are routed to a flare or combustion unit
using the method in paragraph (c)(4) of this section. No emissions
calculation is required during periods when emissions from a pump are
routed to a vapor recovery system without subsequently being routed to
combustion. All references to natural gas driven pneumatic pumps for
Calculation Method 1 in this paragraph (c) also apply to combinations
of pneumatic devices and natural gas driven pneumatic pumps that are
served by a common natural gas supply line; when the supply line serves
both pneumatic devices and natural gas driven pneumatic pumps,
disaggregate the total measured amount of natural gas to pneumatic
devices and natural gas driven pneumatic pumps based on engineering
calculations and best available data. You do not have to calculate
emissions from natural gas driven pneumatic pumps covered in paragraph
(e) of this section under this paragraph (c).
    (1) Calculation Method 1. If you have or elect to install a flow
meter on a supply line to natural gas driven pneumatic pumps, then for
the period of the year when the natural gas supply line is dedicated to
any one or more natural gas driven pneumatic pumps, and the pumps are
vented directly to the atmosphere, you must use the applicable methods
specified in paragraphs (c)(1)(i) or (ii) of this section to calculate
vented CH4 and CO2 emissions from those pumps.
    (i) For volumetric flow monitors:
    (A) Determine the cumulative annual volumetric flow, in standard
cubic feet, as measured by the flow monitor in the reporting year. If
the flow meter was installed during the year, calculate the total
annual volume of natural gas used in the pumps that are connected to
the measured supply line by escalating the measured volumetric flow by
the ratio of the total hours for which natural gas was supplied to the
pumps to the number of hours the natural gas supplied to the pumps was
measured as specified in Equation W-2A of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.004

Where:

Es = Annual natural gas emissions for pumps connected to
natural gas supply line that had a natural gas flow meter installed
during the year, in standard cubic feet.
Es,M = Measured volume of natural gas in the supply line,
from the time that the natural gas flow meter began measuring to the
end of the year, in standard cubic feet.
T = Total hours during the year in which at least one of the pumps
connected to the supply line was operating, hr/yr.
TM = Total hours during the year when the natural gas
supply flow meter was measuring flow.

    (B) Convert the natural gas volumetric flow from paragraph
(c)(1)(i)(A) of this section to CH4 and CO2
volumetric emissions following the provisions in paragraph (u) of this
section.
    (C) Convert the CH4 and CO2 volumetric
emissions from paragraph (c)(1)(i)(B) of this section to CH4
and CO2 mass emissions using calculations in paragraph (v)
of this section.
    (ii) For mass flow monitors:
    (A) Determine the cumulative annual mass flow, in metric tons, as
measured by the flow monitor in the reporting year. If the flow meter
was installed during the year, calculate the total annual mass of
natural gas used in the pumps that are connected to the measured supply
line by escalating the measured mass flow by the ratio of the total
hours for which natural gas was supplied to the pumps to the number of
hours the natural gas supplied to the pumps was measured as specified
in Equation W-2A of paragraph (c)(1)(i)(A) of this section, except that
Es and Es,M are in metric tons per year instead
of standard cubic feet per year.
    (B) Convert the cumulative mass flow from paragraph (c)(1)(ii)(A)
of this section to CH4 and CO2 mass emissions

by multiplying by the mass fraction of CH4 and
CO2 in the supplied natural gas. You must follow the
provisions in paragraph (u) of this section for determining the mole
fraction of CH4 and CO2 and use molecular weights
of 16 kg/kg-mol and 44 kg/kg-mol for CH4 and CO2,
respectively. You may assume unspecified components have an average
molecular weight of 28 kg/kg-mol.
    (2) Calculation Method 2. Except as provided in paragraph (c)(1) of
this section, you may elect to measure the volumetric flow rate of each
natural gas driven pneumatic pump at your facility that vents directly
to the atmosphere as specified in paragraphs (c)(2)(i) through (vii) of
this section. You must exclude the counts of pumps measured according
to paragraph (c)(1) of this section from the counts of pumps to be
measured and for which emissions are calculated according to the
requirements in this paragraph (c)(2).
    (i) Measure all natural gas driven pneumatic pumps at your facility
at least once every 5 years. If you elect to measure your pneumatic
pumps over multiple years, you must measure approximately the same
number of pumps each year. When you measure the emissions from natural
gas driven pneumatic pumps at a well-pad or gathering and boosting
site, you must measure all pneumatic pumps that are vented directly to
the atmosphere at the well-pad or gathering and boosting site during
the same calendar year.
    (ii) Determine the volumetric flow rate of each natural gas driven
pneumatic pump (in standard cubic feet per hour) using one of the
methods specified in Sec.  98.234(b) through (d), as appropriate,
according to the requirements specified in paragraphs (c)(2)(ii)(A)
through (D) of this section.
    (A) If you use a temporary meter, such as a vane anemometer,
according to the methods set forth in Sec.  98.234(b) or a high volume
sampler according to methods set forth Sec.  98.234(d), you must
measure the emissions from each pump for a minimum of 5 minutes, during
a period when the pump is continuously pumping liquid.
    (B) If you use calibrated bagging, follow the methods set forth in
Sec.  98.234(c), except under Sec.  98.234(c)(2), only one bag must be
filled to have a valid measurement. You must collect sample for a
minimum of 5 minutes, or until the bag is full, whichever is shorter,
during a period when the pump is continuously pumping liquid. If the
bag is not full after 5 minutes, you must either continue sampling
until you fill the calibrated bag or you may elect to remeasure the
vent according to paragraph (c)(2)(ii)(A) of this section.
    (C) You do not need to use the same measurement method for each
natural gas driven pneumatic pump vent.
    (D) If the measurement method selected measures the volumetric flow
rate in actual cubic feet, convert the measured flow to standard cubic
feet following the methods specified in paragraph (t)(1) of this
section. Convert the measured flow during the test period to standard
cubic feet per hour, as appropriate.
    (iii) Calculate the volume of natural gas emitted from each natural
gas driven pneumatic pump vent as the product of the natural gas
emissions flow rate measured in paragraph (c)(2)(ii) of this section
and the number of hours that liquid was pumped by the pneumatic pump in
the calendar year.
    (iv) For each pneumatic pump, convert the volumetric emissions of
natural gas at standard conditions determined in paragraph (c)(2)(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 pneumatic pump, convert the GHG volumetric emissions
at standard conditions determined in paragraph (c)(2)(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 (c)(2)(v) of this section.
    (vii) If you chose to conduct natural gas pneumatic pump
measurements over multiple years, ``n,'' according to paragraph
(c)(2)(i) of this section, then you must calculate the emissions from
all pneumatic pumps at your facility as specified in paragraph
(c)(2)(vii)(A) through (D) of this section.
    (A) Use the emissions calculated in paragraph (c)(2)(vi) of this
section for the pumps measured during the reporting year.
    (B) Calculate the whole gas emission factor for pneumatic pumps at
the facility using Equation W-2B of this section and all available data
from the current year and the previous years in your monitoring cycle
(n-1 years) for which natural gas pneumatic pump vent measurements were
made according to Calculation Method 2 in paragraph (c)(2) of this
section (e.g., if your monitoring cycle is 3 years, then use measured
data from the current year and the two previous years). This emission
factor must be updated annually.
[GRAPHIC] [TIFF OMITTED] TP01AU23.005

Where:

EFs = Whole gas population emission factor for natural
gas pneumatic pump vents, in standard cubic feet per hour per pump.
MTs,y = Volumetric whole gas emissions rate measurement
at standard (``s'') conditions during year ``y'' in standard cubic
feet per hour, as calculated in paragraph (c)(2)(iii) of this
section.
County = Count of natural gas driven pneumatic pump vents measured
according to Calculation Method 2 in year ``y.''
n = Number of years of data to include in the emission factor
calculation according to the number of years used to monitor all
natural gas pneumatic pump vents at the facility.

    (C) Calculate CH4 and CO2 volumetric
emissions from natural gas driven pneumatic pumps that were not
measured during the reporting year using Equation W-2C of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.006

Where:

Es,i = Annual total volumetric GHG emissions at standard
conditions in standard cubic feet per year from natural gas driven
pneumatic pump vents, for GHGi.
Count = Total number of natural gas driven pneumatic pumps that
vented directly to the atmosphere and that were not directly
measured according to the requirements in paragraphs (c)(1) or
(c)(2)(ii) of this section.

EFs = Population emission factors for natural gas driven
pneumatic pumps (in standard cubic feet per hour per pump) as
calculated using Equation W-2B of this section.
GHGi = Concentration of GHGi, CH4 or
CO2, in produced natural gas as defined in paragraph
(u)(2)(i) of this section.
T = Average estimated number of hours in the operating year the
pumps that vented directly to the atmosphere were pumping liquid
using engineering estimates based on best available data. Default is
8,760 hours for pumps that only vented directly to the atmosphere.

    (D) Calculate both CH4 and CO2 mass emissions
from volumetric emissions calculated using Equation W-2C of this
section using calculations in paragraph (v) of this section.
    (E) Sum the CH4 and CO2 mass emissions
calculated in paragraphs (c)(2)(vii)(A) and (D) of this section to
calculate the total CH4 and CO2 mass emissions
for Calculation Method 2.
    (3) Calculation Method 3. If you elect not to measure emissions as
specified in Calculation Method 2, then you must use the applicable
method specified in paragraphs (c)(3)(i) and (ii) of this section to
calculate CH4 and CO2 emissions from all natural
gas driven pneumatic pumps that are vented directly to the atmosphere
at your facility and that are not measured according to paragraph
(c)(1) of this section. You must exclude the counts of devices measured
according to paragraph (c)(1) of this section from the counts of pumps
for which emissions are calculated according to the requirements in
this paragraph (c)(3).
    (i) Calculate CH4 and CO2 volumetric
emissions from natural gas driven pneumatic pumps using Equation W-2C
of this section, except use the appropriate default whole gas
population emission factor for natural gas pneumatic pump vents (in
standard cubic feet per hour per device) as provided in table W-1 to
this subpart.
    (ii) Convert the CH4 and CO2 volumetric
emissions determined according to paragraph (c)(3)(i) of this section
to CO2 and CH4 mass emissions using calculations
in paragraph (v) of this section.
    (4) Routing to flares, combustion, or vapor recovery systems.
Calculate emissions from natural gas driven pneumatic pumps for periods
when they are routed to flares or combustion as specified in paragraph
(c)(4)(i) or (ii) of this section, as applicable. If a pump was vented
directly to the atmosphere for part of the year and routed to a flare
or combustion during another part of the year, then calculate emissions
from the time the pump vents directly to the atmosphere as specified in
paragraphs (c)(2) or (3) of this section and calculate emissions from
the time the pump was routed to a flare or combustion as specified in
paragraphs (c)(4)(i) and (ii) of this section, as applicable. For
emissions that are collected in a vapor recovery system that is never
routed to combustion during the reporting year, paragraphs (c)(2) and
(3) and paragraphs (c)(4)(i) and (ii) of this section do not apply and
no emissions calculations are required.
    (i) If any natural gas driven pneumatic pumps were routed to a
flare, you must calculate CH4, CO2, and
N2O 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).
    (ii) If emissions from any natural gas driven pneumatic pumps were
routed to combustion, you must calculate emissions for the combustion
equipment as specified in paragraph (z) of this section and report
emissions from the combustion equipment as specified in Sec.
98.236(z).
    (d) Acid gas removal unit (AGR) vents and Nitrogen removal unit
(NRU) vents. For AGR vents (including processes such as amine,
membrane, molecular sieve or other absorbents and adsorbents),
calculate emissions for CH4 and CO2 vented
directly to the atmosphere or emitted through a sulfur recovery plant,
using any of the calculation methods described in paragraphs (d)(1)
through (4) of this section, and also comply with paragraphs (d)(5)
through (11) of this section, as applicable. For NRU vents, calculate
emissions for CH4 vented directly to the atmosphere using
any of the calculation methods described in paragraphs (d)(1) through
(4) of this section, and also comply with paragraphs (d)(5) through
(11) of this section, as applicable. If any AGR vents or NRU vents are
routed to a flare, you must calculate CH4, CO2,
and N2O 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). If any AGR vents or NRU vents are routed
through an engine (e.g., permeate from a membrane or de-adsorbed gas
from a pressure swing adsorber used as fuel supplement) (i.e., routed
to combustion, you must calculate CH4, CO2, and
N2O emissions as specified in subpart C of this part or as
specified in paragraph (z) of this section, as applicable.
    (1) Calculation Method 1. If you operate and maintain a continuous
emissions monitoring system (CEMS) that has both a CO2
concentration monitor and volumetric flow rate monitor, you must
calculate CO2 emissions under this subpart by following the
Tier 4 Calculation Method and all associated calculation, quality
assurance, reporting, and recordkeeping requirements for Tier 4 in
subpart C of this part (General Stationary Fuel Combustion Sources).
Alternatively, you may follow the manufacturer's instructions or
industry standard practice. If a CO2 concentration monitor
and volumetric flow rate monitor are not available, you may elect to
install a CO2 concentration monitor and a volumetric flow
rate monitor that comply with all of the requirements specified for the
Tier 4 Calculation Method in subpart C of this part (General Stationary
Fuel Combustion Sources).
    (2) Calculation Method 2. For CO2 emissions, if a CEMS
is not available but a vent meter is installed, use the CO2
composition and annual volume of vent gas to calculate emissions using
Equation W-3 of this section. For CH4 emissions, if a vent
meter is installed, including the volumetric flow rate monitor on a
CEMS for CO2, use the CH4 composition and annual
volume of vent gas to calculate emissions using Equation W-3 of this
section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.007

Where:

Ea,i = Annual total volumetric GHGi (either
CO2 or CH4) emissions at actual conditions, in
cubic feet per year.
Va = Total annual volume of vent gas flowing out of the
AGR or NRU in cubic feet per year at actual conditions as determined
by flow meter using methods set forth in Sec.  98.234(b).
Alternatively, you may follow the manufacturer's instructions or
industry standard practice for calibration of the vent meter.
Voli = Annual average volumetric fraction of GHGi (either
CO2 or CH4) content in vent gas flowing out of
the AGR or NRU as determined in paragraph (d)(7) of this section.

    (3) Calculation Method 3. If a CEMS for CO2 or a vent
meter is not installed, you may use the inlet and/or outlet gas

flow rate of the AGR or NRU to calculate emissions for CH4
and CO2 using Equations W-4A, W-4B, or W-4C of this section.
If inlet gas flow rate and CH4 and CO2 content of
the vent gas are known, use Equation W-4A. If outlet gas flow rate and
CH4 and CO2 content of the vent gas are known,
use Equation W-4B. If inlet gas flow rate and outlet gas flow rate are
known, use Equation W-4C.
[GRAPHIC] [TIFF OMITTED] TP01AU23.008

[GRAPHIC] [TIFF OMITTED] TP01AU23.009

[GRAPHIC] [TIFF OMITTED] TP01AU23.010

Where:

Ea,i = Annual total volumetric GHGi (either
CH4 or CO2) emissions at actual conditions, in
cubic feet per year.
Vin = Total annual volume of natural gas flow into the
AGR or NRU in cubic feet per year at actual conditions as determined
using methods specified in paragraph (d)(5) of this section.
Vout = Total annual volume of natural gas flow out of the
AGR or NRU in cubic feet per year at actual conditions as determined
using methods specified in paragraph (d)(5) of this section.
VolI,i = Annual average volumetric fraction of GHGi
(either CH4 or CO2) content in natural gas
flowing into the AGR or NRU as determined in paragraph (d)(7) of
this section.
VolO,i = Annual average volumetric fraction of GHGi
(either CH4 or CO2) content in natural gas
flowing out of the AGR or NRU as determined in paragraph (d)(8) of
this section.
VolEM,i = Annual average volumetric fraction of GHGi
(either CH4 or CO2) content in the vent gas
flowing out of the AGR or NRU as determined in paragraph (d)(6) of
this section.

    (4) Calculation Method 4. If CEMS for CO2 or a vent
meter is not installed, you may calculate CH4 and
CO2 emissions from an AGR or NRU using any standard
simulation software package, such as AspenTech HYSYS[supreg], or API
4679 AMINECalc, that uses the Peng-Robinson equation of state and
speciates CH4 and CO2 emissions. A minimum of the
parameters listed in paragraph (d)(4)(i) through (x) of this section,
as applicable, must be used to characterize emissions. If paragraph
(d)(4)(i) through (x) of this section indicates that an applicable
parameter must be measured, collect measurements reflective of
representative operating conditions over the time period covered by the
simulation. Determine all other applicable parameters in paragraph
(d)(4)(i) through (x) of this section by engineering estimate and
process knowledge based on best available data and, if necessary,
adjust parameters to represent the operating conditions over the time
period covered by the simulation. Determine the number of simulations
and associated time periods such that the simulations cover the entire
reporting year (i.e., if you calculate emissions using one simulation,
use representative parameters for the operating conditions over the
calendar year; if you use periodic simulations to cover the calendar
year, use parameters for the operating conditions over each
corresponding appropriate portion of the calendar year).
    (i) Natural gas feed temperature, pressure, and flow rate (must be
measured).
    (ii) Acid gas content of feed natural gas (must be measured).
    (iii) Acid gas content of outlet natural gas.
    (iv) CH4 content of feed natural gas (must be measured).
    (v) CH4 content of outlet natural gas.
    (vi) For NRU, nitrogen content of feed natural gas (must be
measured).
    (vii) For NRU, nitrogen content of outlet natural gas.
    (viii) Unit operating hours, excluding downtime for maintenance or
standby.
    (ix) Exit temperature of natural gas.
    (x) For AGR, solvent type, pressure, temperature, circulation rate,
and composition.
    (5) Flow rate of inlet. For Calculation Method 3, determine the gas
flow rate of the inlet when using Equation W-4A or W-4C of this section
or the gas flow rate of the outlet when using Equation W-4B or W-4C of
this section for the natural gas stream of an AGR or NRU using a meter
according to methods set forth in Sec.  98.234(b). If you do not have a
continuous flow meter, either install a continuous flow meter or use an
engineering calculation to determine the flow rate.
    (6) Composition of vent gas. For Calculation Method 2 or
Calculation Method 3 when using Equation W-4A or W-4B of this section,
if a continuous gas analyzer is not available on the vent stack, either
install a continuous gas analyzer or take quarterly gas samples from
the vent gas stream for each quarter that the AGR or NRU is operating
to determine Voli in Equation W-3 of this section or Equation W-4A or
W-4B of this section, according to the methods set forth in Sec.
98.234(b).
    (7) Composition of inlet gas stream. For Calculation Method 3, if a
continuous gas analyzer is installed on the inlet gas stream, then the
continuous gas analyzer results must be used. If a continuous gas
analyzer is not available, either install a continuous gas analyzer or
take quarterly gas samples from the inlet gas stream for each quarter
that the AGR or NRU is operating to determine VolI,i in Equation W-4A,
W-4B, or W-4C of this section, according to the methods set forth in
Sec.  98.234(b).
    (8) Composition of outlet gas stream. For Calculation Method 3,
determine annual average volumetric fraction of GHGi (either
CH4 or CO2) content in natural gas flowing out of
the AGR or NRU using one of the methods specified in paragraphs
(d)(8)(i) through (iii) of this section.
    (i) If a continuous gas analyzer is installed on the outlet natural
gas stream, then the continuous gas analyzer results must be used. If a
continuous gas analyzer is not available, you may install a continuous
gas analyzer.
    (ii) If a continuous gas analyzer is not available or installed,
quarterly gas samples may be taken from the outlet natural gas stream
for each quarter that the AGR or NRU is operating to

determine VolO,i in Equation W-4A, W-4B, or W-4C of this
section, according to the methods set forth in Sec.  98.234(b).
    (iii) If a continuous gas analyzer is not available or installed,
you may use the outlet pipeline quality specification for
CO2 in natural gas and the outlet quality specification for
CH4 in natural gas.
    (9) Volumetric emissions. Calculate annual volumetric
CH4 and CO2 emissions at standard conditions
using calculations in paragraph (t) of this section.
    (10) Mass emissions. Calculate annual mass CH4 and
CO2 emissions using calculations in paragraph (v) of this
section.
    (11) Emissions recovered and transferred outside the facility.
Determine if CO2 emissions from the AGR are recovered and
transferred outside the facility. Adjust the CO2 emissions
estimated in paragraphs (d)(1) through (d)(10) of this section downward
by the magnitude of CO2 emissions recovered and transferred
outside the facility.
    (e) Dehydrator vents. For dehydrator vents, calculate annual
CH4 and CO2 emissions using the applicable
calculation methods described in paragraphs (e)(1) through (5) of this
section. For glycol dehydrators that have an annual average daily
natural gas throughput that is greater than or equal to 0.4 million
standard cubic feet per day, use Calculation Method 1 in paragraph
(e)(1) of this section. For glycol dehydrators that have an annual
average of daily natural gas throughput that is greater than 0 million
standard cubic feet per day and less than 0.4 million standard cubic
feet per day, use either Calculation Method 1 in paragraph (e)(1) of
this section or Calculation Method 2 in paragraph (e)(2) of this
section. If you are required to or elect to use the method in paragraph
(e)(1) of this section, you must use the results of the model to
determine annual mass emissions. If emissions from dehydrator vents are
routed to a vapor recovery system, you must adjust the emissions
downward according to paragraph (e)(4) of this section. If emissions
from dehydrator vents are routed to a regenerator firebox/fire tubes,
you must calculate CH4, CO2, and N2O
annual emissions as specified in paragraph (e)(5) of this section. If
any dehydrator vents are routed to a flare, you must calculate
CH4, CO2, and N2O 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).
    (1) Calculation Method 1. Calculate annual mass emissions from
glycol dehydrators by using a software program, such as AspenTech
HYSYS[supreg], Bryan Research & Engineering ProMax[supreg], or GRI-
GLYCalcTM, that uses the Peng-Robinson equation of state to calculate
the equilibrium coefficient, speciates CH4 and
CO2 emissions from dehydrators, and has provisions to
include regenerator control devices, a separator flash tank, stripping
gas, and a gas injection pump or gas assist pump. If you elect to use
ProMax[supreg], you must use version 5.0 or above. Emissions must be
modeled from both the still vent and, if applicable, the flash tank
vent. A minimum of the parameters listed in paragraph (e)(1)(i) through
(xi) of this section, as applicable, must be used to characterize
emissions. If paragraph (e)(1)(i) through (xi) of this section
indicates that an applicable parameter must be measured, collect
measurements reflective of representative operating conditions for the
time period covered by the simulation. Determine all other applicable
parameters in paragraph (e)(1)(i) through (xi) of this section by
engineering estimate and process knowledge based on best available data
and, if necessary, adjust parameters to represent the operating
conditions over the time period covered by the simulation. Determine
the number of simulations and associated time periods such that the
simulations cover the entire reporting year (i.e., if you calculate
emissions using one simulation, use representative parameters for the
operating conditions over the calendar year; if you use periodic
simulations to cover the calendar year, use parameters for the
operating conditions over each corresponding appropriate portion of the
calendar year).
    (i) Feed natural gas flow rate (must be measured).
    (ii) Feed natural gas water content (must be measured).
* * * * *
    (x) Wet natural gas temperature and pressure at the absorber inlet
(must be measured).
    (xi) Wet natural gas composition. Measure this parameter using one
of the methods described in paragraphs (e)(1)(xi)(A) and (B) of this
section.
    (A) Use an appropriate standard method published by a consensus-
based standards organization if such a method exists or you may use an
industry standard practice as specified in Sec.  98.234(b) to sample
and analyze wet natural gas composition.
    (B) If only composition data for dry natural gas is available,
assume the wet natural gas is saturated.
    (2) Calculation Method 2. Calculate annual volumetric emissions
from glycol dehydrators using Equation W-5 of this section, and then
calculate the collective CH4 and CO2 mass
emissions from the volumetric emissions using the procedures in
paragraph (v) of this section:
* * * * *
Count = Total number of glycol dehydrators that have an annual average
daily natural gas throughput that is greater than 0 million standard
cubic feet per day and less than 0.4 million standard cubic feet per
day for which you elect to use this Calculation Method 2.
* * * * *
    (3) Calculation Method 3. For dehydrators of any size that use
desiccant, you must calculate emissions from the amount of gas vented
from the vessel when it is depressurized for the desiccant refilling
process using Equation W-6 of this section. From volumetric natural gas
emissions, calculate both CH4 and CO2 volumetric
and mass emissions using the procedures in paragraphs (u) and (v) of
this section. Desiccant dehydrator emissions covered in this paragraph
do not have to be calculated separately using the method specified in
paragraph (i) of this section for blowdown vent stacks.
* * * * *
    (4) Emissions vented directly to atmosphere from dehydrators routed
to a vapor recovery system, flare, or regenerator firebox/fire tubes.
If the dehydrator(s) has a vapor recovery system, routes emissions to a
flare, or routes emissions to a regenerator firebox/fire tubes and you
use Calculation Method 1 or Calculation Method 2 in paragraph (e)(1) or
(2) of this section, calculate annual emissions vented directly to
atmosphere from the dehydrator(s) during periods of time when emissions
were not routed to the vapor recovery system, flare, or regenerator
firebox/fire tubes as specified in paragraphs (e)(4)(i) and (ii) of
this section. If the dehydrator(s) has a vapor recovery system or
routes emissions to a flare and you use Calculation Method 3 in
paragraph (e)(3) of this section, calculate annual emissions vented
directly to atmosphere from the dehydrator(s) during periods of time
when emissions were not routed to the vapor recovery system or flare as
specified in paragraph (e)(4)(iii) of this section.
    (i) When emissions from dehydrator(s) are calculated using
Calculation Method 1 or 2, calculate maximum potential annual vented
emissions as specified in paragraph

(e)(1) or (2) of this section, and calculate an average hourly vented
emissions rate by dividing the maximum potential annual vented
emissions by the number of hours that the dehydrator was in operation.
    (ii) To calculate total emissions vented directly to atmosphere
during periods when the dehydrator was not routing emissions to a vapor
recovery system, flare, or regenerator firebox/fire tubes for
dehydrator(s) with emissions calculated using Calculation Method 1 or
2, multiply the average hourly vented emissions rate determined in
paragraph (e)(4)(i) of this section by the number of hours that the
dehydrator vented directly to the atmosphere. Determine the number of
hours that the dehydrator vented directly to atmosphere by subtracting
the hours that the dehydrator was connected to a vapor recovery system,
flare, or regenerator firebox/fire tubes (based on engineering estimate
and best available data) from the total operating hours for the
dehydrator in the calendar year. You must take into account periods
with reduced capture efficiency of the vapor recovery system, flare, or
regenerator firebox/fire tubes. If emissions are routed to a flare but
the flare is unlit, calculate emissions in accordance with the
methodology specified in paragraph (n) of this section and report
emissions from the flare as specified in Sec.  98.236(n).
    (iii) When emissions from dehydrator(s) are calculated using
Calculation Method 3, calculate total annual emissions vented directly
to atmosphere from the dehydrator(s) during periods of time when
emissions were not routed to the vapor recovery system, flare, or
regenerator firebox/fire tubes by determining of the number of
depressurization events (including portions of an event) that vented to
atmosphere based on engineering estimate and best available data. You
must take into account periods with reduced capture efficiency of the
vapor recovery system or flare. If emissions are routed to a flare but
the flare is unlit, calculate emissions in accordance with the
methodology specified in paragraph (n) of this section and report
emissions from the flare as specified in Sec.  98.236(n).
    (5) Combustion emissions from routing to regenerator firebox/fire
tubes. If any dehydrator emissions are routed to a regenerator firebox/
fire tubes, calculate emissions from these devices attributable to
dehydrator flash tank vents or still vents as specified in paragraphs
(e)(5)(i) through (iii) of this section. If you operate a CEMS to
monitor the emissions from the regenerator firebox/fire tubes,
calculate emissions as specified in paragraph (e)(5)(iv) of this
section.
    (i) Determine the volume of the total emissions that is routed to a
regenerator firebox/fire tubes as specified in paragraph (e)(5)(i)(A)
or (B) of this section.
    (A) Measure the flow from the dehydrator(s) to the regenerator
firebox/fire tubes using a continuous flow measurement device. If you
continuously measure flow to the regenerator firebox/fire tubes, you
must use the measured volumes to calculate emissions from the
regenerator firebox/fire tubes.
    (B) Using engineering estimates based on best available data,
determine the volume of the total emissions estimated in paragraph
(e)(1), (2), or (3) of this section, as applicable, that is routed to
the regenerator firebox/fire tubes.
    (ii) Determine composition of the gas routed to a regenerator
firebox/fire tubes as specified in paragraph (e)(5)(ii)(A) or (B) of
this section.
    (A) Use the appropriate vent emissions as determined in paragraph
(e)(1) or (2) of this section.
    (B) Measure the composition of the gas from the dehydrator(s) to
the regenerator firebox/fire tubes using a continuous composition
analyzer. If you continuously measure gas composition, then those
measured data must be used to calculate dehydrator emissions from the
regenerator firebox/fire tubes.
    (iii) Determine GHG volumetric emissions at actual conditions from
the regenerator firebox/fire tubes using Equations W-39A, W-39B, and W-
40 in paragraph (z)(3) of this section. Calculate GHG volumetric
emissions at standard conditions using calculations in paragraph (t) of
this section. Calculate both GHG mass emissions from volumetric
emissions using calculations in paragraph (v) of this section.
    (iv) If you operate and maintain a CEMS that has both a
CO2 concentration monitor and volumetric flow rate monitor
for the combustion gases from the regenerator firebox/fire tubes, you
must calculate only CO2 emissions for the regenerator
firebox/fire tubes. You must follow the Tier 4 Calculation Method and
all associated calculation, quality assurance, reporting, and
recordkeeping requirements for Tier 4 in subpart C of this part
(General Stationary Fuel Combustion Sources). If a CEMS is used to
calculate emissions from a regenerator firebox/fire tubes, the
requirements specified in paragraphs (e)(5)(ii) and (iii) of this
section are not required.
    (f) Well venting for liquids unloadings. Calculate annual
volumetric natural gas emissions from well venting for liquids
unloading when the well is unloaded to the atmosphere or a control
device using one of the calculation methods described in paragraph
(f)(1), (2), or (3) of this section. Once every 3 consecutive calendar
years or on a more frequent basis, you must use Calculation Method 1 to
calculate emissions from well venting for liquids unloading for each
well. Calculate annual CH4 and CO2 volumetric and
mass emissions using the method described in paragraph (f)(4) of this
section.
    (1) Calculation Method 1. Calculate emissions from manual and
automated unloadings at wells with plunger lifts and wells without
plunger lifts separately. For at least one well of each unique well
tubing diameter group and pressure group combination in each sub-basin
category (see Sec.  98.238 for the definitions of tubing diameter
group, pressure group, and sub-basin category), where gas wells are
vented to the atmosphere to expel liquids accumulated in the tubing,
install a recording flow meter on the vent line used to vent gas from
the well (e.g., on the vent line off the wellhead separator or
atmospheric storage tank) according to methods set forth in Sec.
98.234(b). Calculate the total emissions from well venting to the
atmosphere for liquids unloading using Equation W-7A of this section.
Equation W-7A must be used for each unloading type combination
(automated plunger lift unloadings, manual plunger lift unloadings,
automated unloadings without plunger lifts and manual unloadings
without plunger lifts) for any tubing diameter group and pressure group
combination in each sub-basin.
[GRAPHIC] [TIFF OMITTED] TP01AU23.011

Where:

Ea = Annual natural gas emissions for each well of the
same tubing diameter group and pressure group combination in the
sub-basin at actual conditions, a, in

cubic feet. Calculate emissions from wells with automated plunger
lift unloadings, wells with manual plunger lift unloadings, wells
with automated unloadings without plunger lifts and wells with
manual unloadings without plunger lifts separately.
FR = Average flow rate in cubic feet per hour for all measured wells
of the same tubing diameter group and pressure group combination in
a sub-basin, over the duration of the liquids unloading, under
actual conditions as determined in paragraph (f)(1)(i) of this
section.
Tp = Cumulative amount of time in hours of venting for
each well, p, of the same tubing diameter group and pressure group
combination in a sub-basin during the year. If the available venting
data do not contain a record of the date of the venting events and
data are not available to provide the venting hours for the specific
time period of January 1 to December 31, you may calculate an
annualized vent time, Tp, using Equation W-7B of this section.

[GRAPHIC] [TIFF OMITTED] TP01AU23.012

Where:

HRp = Cumulative amount of time in hours of venting for
each well, p, during the monitoring period.
MPp = Time period, in days, of the monitoring period for
each well, p. A minimum of 300 days in a calendar year are required.
The next period of data collection must start immediately following
the end of data collection for the previous reporting year.
Dp = Time period, in days during which the well, p, was
in production (365 if the well was in production for the entire
year).

    (i) Determine the well vent average flow rate (``FR'' in Equation
W-7A of this section) as specified in paragraphs (f)(1)(i)(A) through
(C) of this section for at least one well in a unique well tubing
diameter group and pressure group combination in each sub-basin
category. Calculate emissions from wells with automated plunger lift
unloadings, wells with manual plunger lift unloadings, wells with
automated unloadings without plunger lifts and wells with manual
unloadings without plunger lifts separately.
    (A) Calculate the average flow rate per hour of venting for each
unique tubing diameter group and pressure group combination in each
sub-basin category by dividing the recorded total annual flow by the
recorded time (in hours) for all measured liquid unloading events with
venting to the atmosphere or a control device.
    (B) Apply the average hourly flow rate calculated under paragraph
(f)(1)(i)(A) of this section to each well in the same pressure group
that have the same tubing diameter group, for the number of hours of
each well is vented.
    (C) If using Calculation Method 1 more frequently than once every 3
years, you must calculate a new average flow rate each calendar year
that you use Calculation Method 1. For a new producing sub-basin
category, calculate an average flow rate beginning in the first year of
production.
    (ii) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
    (2) Calculation Method 2. Calculate the total emissions for each
well from manual and automated well venting to the atmosphere for
liquids unloading without plunger lift assist using Equation W-8 of
this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.013

Where:

Es = Annual natural gas emissions for each well at
standard conditions, s, in cubic feet per year
Np = Total number of unloading events in the monitoring
period per well, p.
0.37 x 10-\3\ = {3.14 (pi)/4{time} /{14.7*144{time}
(psia converted to pounds per square feet).
CDp = Casing internal diameter for well, p, in inches.
WDp = Well depth from either the top of the well or the
lowest packer to the bottom of the well, for well, p, in feet.
    SPp = For well, p, shut-in pressure or surface
pressure for wells with tubing production, or casing pressure for
each well with no packers, in pounds per square inch absolute
(psia). If casing pressure is not available for the well, you may
determine the casing pressure by multiplying the tubing pressure of
the well with a ratio of casing pressure to tubing pressure from a
well in the same sub-basin for which the casing pressure is known.
The tubing pressure must be measured during gas flow to a flow-line.
The shut-in pressure, surface pressure, or casing pressure must be
determined just prior to liquids unloading when the well production
is impeded by liquids loading or closed to the flow-line by surface
valves.
SFRp = Average flow-line rate of gas for well, p, at
standard conditions in cubic feet per hour. Use Equation W-33 of
this section to calculate the average flow-line rate at standard
conditions.
HRp,q = Hours that well, p, was left open to the
atmosphere during each unloading event, q.
1.0 = Hours for average well to blowdown casing volume at shut-in
pressure.
q = Unloading event.
Zp,q = If HRp,q is less than 1.0 then
Zp,q is equal to 0. If HRp,q is greater than
or equal to 1.0 then Zp,q is equal to 1.

    (3) Calculation Method 3. Calculate the total emissions for each
sub-basin from well venting to the atmosphere for liquids unloading
with plunger lift assist using Equation W-9 of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.014

Where:

Es = Annual natural gas emissions for each well at
standard conditions, s, in cubic feet per year.
Np = Total number of unloading events in the monitoring
period per well, p.
0.37 x 10-\3\ = {3.14 (pi)/4{time} /{14.7*144{time}
(psia converted to pounds per square feet).
TDp = Tubing internal diameter for well, p, in inches.
WDp = Tubing depth to plunger bumper for well, p, in
feet.
SPp = Flow-line pressure for well p in pounds per square
inch absolute (psia), using engineering estimate based on best
available data.
SFRp = Average flow-line rate of gas for well, p, at
standard conditions in cubic feet per hour. Use Equation W-33 of
this section to calculate the average flow-line rate at standard
conditions.
HRp,q = Hours that well, p, was left open to the
atmosphere during each unloading event, q.
0.5 = Hours for average well to blowdown tubing volume at flow-line
pressure.
q = Unloading event.
Zp,q = If HRp,q is less than 0.5 then
Zp,q is equal to 0. If HRp,q is greater than
or equal to 0.5 then Zp,q is equal to 1.

    (4) Volumetric and mass emissions. Calculate CH4 and
CO2 volumetric and mass emissions from volumetric natural
gas emissions using calculations in paragraphs (u) and (v) of this
section.
* * * * *
    (g) Well venting during completions and workovers with hydraulic
fracturing. Calculate annual volumetric natural gas emissions from gas
well and oil well venting during completions and workovers involving
hydraulic fracturing using Equation W-10A or Equation W-10B of this
section. Equation W-10A applies to well venting when the gas flowback
rate is measured from a specified number of example completions or
workovers in a sub-basin and well type combination and Equation W-10B
applies when the gas flowback vent or flare volume is measured for each
completion or workover in a sub-basin and well type combination.
Completion and workover activities are separated into two periods, an
initial period when flowback is routed to open pits or tanks and a
subsequent period when gas content is sufficient to route the flowback
to a separator or when the gas content is sufficient to allow
measurement by the devices specified in paragraph (g)(1) of this
section, regardless of whether a separator is actually utilized. If you
elect to use Equation W-10A, you must follow the procedures specified
in paragraph (g)(1) of this section. If you elect to use Equation W-
10B, you must use a recording flow meter installed on the vent line,
downstream of a separator and ahead of a flare or vent, to measure the
gas flowback. For either equation, emissions must be calculated
separately for completions and workovers, for each sub-basin, and for
each well type combination identified in paragraph (g)(2) of this
section. You must calculate CH4 and CO2
volumetric and mass emissions as specified in paragraph (g)(3) of this
section. If emissions from well venting during completions and
workovers with hydraulic fracturing are routed to a flare, you must
calculate CH4, CO2, and N2O annual
emissions as specified in paragraph (n) of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.015

[GRAPHIC] [TIFF OMITTED] TP01AU23.016

Where:

Es,n = Annual volumetric natural gas emissions in
standard cubic feet from gas venting during well completions or
workovers following hydraulic fracturing for each well.
CW = Total number of completions or workovers using hydraulic
fracturing for each well, p.
Tp,s,cw = Cumulative amount of time of flowback, after
sufficient quantities of gas are present to enable separation, where
gas vented or flared for each completion or workover, in hours, for
each well, p, during the reporting year. This may include non-
contiguous periods of venting or flaring.
Tp,i,cw = Cumulative amount of time of flowback to open
tanks/pits, from when gas is first detected until sufficient
quantities of gas are present to enable separation, for each
completion or workover, in hours, for each well, p, during the
reporting year. This may include non-contiguous periods of routing
to open tanks/pits but does not include periods when the oil well
ceases to produce fluids to the surface.
FRMs = Ratio of average gas flowback, during the period
when sufficient quantities of gas are present to enable separation,
of well completions and workovers from hydraulic fracturing to 30-
day production rate for the sub-basin and well type combination,
calculated using procedures specified in paragraph (g)(1)(iii) of
this section.
FRMi = Ratio of initial gas flowback rate during well
completions and workovers from hydraulic fracturing to 30-day gas
production rate for the sub-basin and well type combination,
calculated using procedures specified in paragraph (g)(1)(iv) of
this section, for the period of flow to open tanks/pits.
PRs,p,cw = Average gas production flow rate during the
first 30 days of production after each completion of a newly drilled
well or well workover using hydraulic fracturing in standard cubic
feet per hour of each well p, that was measured in the sub-basin and
well type combination. If applicable, PRs,p,cw may be
calculated for oil wells using procedures specified in paragraph
(g)(1)(vii) of this section.
EnFs,p,cw = Volume of N2 injected gas in cubic
feet at standard conditions that was injected into the reservoir
during an energized fracture job or during flowback during each
completion or workover for each well, p, as determined by using an
appropriate meter according to methods described in Sec.  98.234(b),
or by using receipts of gas purchases that are used for the
energized fracture job or injection during flowback. Convert to
standard conditions using paragraph (t) of this section. If the
fracture process did not inject gas into the reservoir or if the
injected gas is CO2 then EnFs,p,cw is 0.
FVs,p,cw = Flow volume of vented or flared gas for each
completion or workover at each well, p, in standard cubic feet
measured using a recording flow meter (digital or analog) on the
vent line to measure gas flowback during the separation period of
the completion or workover according to methods set forth in Sec.
98.234(b).
FRp,i,cw = Flow rate vented or flared of each completion
or workover for each well, p, in standard cubic feet per hour
measured using a recording flow meter (digital or analog) on the
vent line to measure the flowback, at the beginning of the period of
time when sufficient quantities of gas are present to enable
separation, of the completion or workover according to methods set
forth in Sec.  98.234(b).

    (1) If you elect to use Equation W-10A of this section on gas
wells, you must use Calculation Method 1 as specified in paragraph
(g)(1)(i) of this section to determine the value of FRMs and
FRMi. These values must be based on the flow rate for
flowback gases, once sufficient gas is present to enable separation.
The number of measurements or calculations required to estimate
FRMs and FRMi must be determined individually for
completions and workovers per sub-basin and well type combination as
follows: Complete measurements or calculations for at least one
completion or workover for less than or equal to 25 completions or
workovers for each well type combination within a sub-basin; complete
measurements or calculations for at least two completions or workovers
for 26 to 50 completions or workovers for each sub-basin and well type
combination; complete measurements or calculations for at least three
completions or workovers for 51 to 100 completions or workovers for
each sub-basin and well type combination; complete measurements or
calculations for at least four completions or workovers for 101 to 250
completions or workovers for each sub-basin and well type combination;
and complete measurements or calculations for at least five completions
or workovers for greater than 250 completions or workovers for each
sub-basin and well type combination.
* * * * *
    (iii) * * *

FRs,p = Measured average gas flowback rate from Calculation
Method 1 described in paragraph (g)(1)(i) of this section, during the
separation period in standard cubic feet per hour for well(s) p for
each sub-basin and well type combination. Convert measured
FRa values from actual conditions upstream of the
restriction orifice (FRa) to standard conditions
(FRs,p) for each well p using Equation W-33 in paragraph (t)
of this section. You may not use flow volume as used in Equation W-10B
of this section converted to a flow rate for this parameter.
* * * * *
N = Number of measured well completions or workovers using hydraulic
fracturing in a sub-basin and well type combination.

    (iv) * * *

FRi,p = Initial measured gas flowback rate from Calculation
Method 1 described in paragraph (g)(1)(i) of this section in standard
cubic feet per hour for well(s), p, for each sub-basin and well type
combination. Measured FRi,p values must be based on flow
conditions at the beginning of the separation period and must be
expressed at standard conditions.
* * * * *
N = Number of measured well completions or workovers using hydraulic
fracturing in a sub-basin and well type combination.
* * * * *
    (h) Gas well venting during completions and workovers without
hydraulic fracturing. Calculate annual volumetric natural gas emissions
from each gas well venting during workovers without hydraulic
fracturing using Equation W-13A of this section. Calculate annual
volumetric natural gas emissions from each gas well venting during
completions without hydraulic fracturing using Equation W-13B of this
section. You must convert annual volumetric natural gas emissions to
CH4 and CO2 volumetric and mass emissions as
specified in paragraph (h)(1) of this section. If emissions from gas
well venting during completions and workovers without hydraulic
fracturing are routed to a flare, you must calculate CH4,
CO2, and N2O annual emissions as specified in
paragraph (n) of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.017

[GRAPHIC] [TIFF OMITTED] TP01AU23.018

Where:

Es,wo = Annual volumetric natural gas emissions in
standard cubic feet from gas well venting during well workovers
without hydraulic fracturing.
Nwo = Number of workovers per well that do not involve
hydraulic fracturing in the reporting year.
EFwo = Emission factor for non-hydraulic fracture well
workover venting in standard cubic feet per workover. Use 3,114
standard cubic feet natural gas per well workover without hydraulic
fracturing.
Es,p = Annual volumetric natural gas emissions in
standard cubic feet from gas well venting during well completions
without hydraulic fracturing.
Vp = Average daily gas production rate in standard cubic
feet per hour for each well, p, undergoing completion without
hydraulic fracturing. This is the total annual gas production volume
divided by total number of hours the well produced to the flow-line.
For completed wells that have not established a production rate, you
may use the average flow rate from the first 30 days of production.
In the event that the well is completed less than 30 days from the
end of the calendar year, the first 30 days of the production
straddling the current and following calendar years shall be used.
Tp = Time that gas is vented to either the atmosphere or
a flare for each well, p, undergoing completion without hydraulic
fracturing, in hours during the year.
* * * * *
    (i) * * *
    (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 production, onshore petroleum and natural gas gathering and
boosting facilities, onshore natural gas transmission pipeline
facilities, and natural gas distribution 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 production, onshore petroleum and natural gas gathering
and boosting facilities, onshore natural gas transmission pipeline

facilities, and natural gas distribution 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 production, onshore
petroleum and natural gas gathering and boosting facilities, onshore
natural gas transmission pipeline facilities, and natural gas
distribution 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
production, onshore petroleum and natural gas gathering and boosting
facilities, onshore natural gas transmission pipeline facilities, and
natural gas distribution 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 production, onshore petroleum and
natural gas gathering and boosting facilities, onshore natural gas
transmission pipeline facilities, and natural gas distribution
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 petroleum and natural gas production, onshore
natural gas processing, onshore natural gas transmission compression,
underground natural gas storage, LNG storage, 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 and natural
gas distribution industry segments, 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) Hydrocarbon liquids and produced water storage tanks. Calculate
CH4, CO2, and N2O (when flared)
emissions from atmospheric pressure storage tanks receiving hydrocarbon
liquids or produced water from onshore petroleum and natural gas
production facilities, onshore petroleum and natural gas gathering and
boosting facilities (including stationary liquid storage not owned or
operated by the reporter), and onshore natural gas processing
facilities as specified in this paragraph (j). For wells, gas-liquid
separators, or onshore petroleum and natural gas gathering and boosting
or onshore natural gas processing 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, gas-liquid separators, or non-separator equipment
with annual average daily throughput of hydrocarbon liquids greater
than 0 barrels per day and less than 10 barrels per day, calculate
annual CH4 and CO2 emissions using Calculation
Method 1, 2, or 3 as specified in paragraphs (j)(1) through (3) of this
section. Annual average daily throughput of hydrocarbon liquids should
be calculated using the flow out of the separator, well, or non-
separator equipment determined over the actual days of operation. For
atmospheric pressure storage tanks receiving produced water, calculate
annual CH4 emissions using Calculation Method 1, 2, or 3 as
specified in paragraphs (j)(1) through (3) of this section. If you are
required to or elect to use the method in paragraph (j)(1) of this
section, you must use the results of the model to determine annual
CH4 and, if applicable, CO2 emissions. If you use
Calculation Method 1 or Calculation Method 2 for gas-liquid separators,
you must also calculate emissions that may have occurred due to dump
valves not closing properly using the method specified in paragraph
(j)(5) of this section. If emissions from atmospheric pressure storage
tanks are routed to a vapor recovery system, you must calculate
CH4 and CO2 annual emissions as specified in
paragraph (j)(4) of this section. If emissions from atmospheric
pressure storage tanks are routed to a flare, determine flared
emissions in accordance with the methodology specified in paragraph (n)
of this section and report emissions from the flare as specified in
Sec.  98.236(n). For atmospheric pressure storage tanks routing
emissions to a vapor recovery system or a flare, calculate annual
emissions vented directly to atmosphere as specified in paragraph
(j)(4) of this section.
    (1) Calculation Method 1. For atmospheric pressure storage tanks
receiving hydrocarbon liquids, calculate annual CH4 and
CO2 emissions using operating conditions in the well, last
gas-liquid separator, or last non-separator equipment before liquid
transfer to storage tanks. For atmospheric pressure storage tanks
receiving produced water, calculate annual CH4 emissions
using operating

conditions in the well, last gas-liquid separator, or last non-
separator equipment before liquid transfer to storage tanks. Calculate
flashing emissions with a software program, such as AspenTech
HYSYS[supreg], Bryan Research & Engineering ProMax[supreg], or, for
atmospheric pressure storage tanks receiving hydrocarbon liquids from
gas-liquid separator or non-separator equipment, 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 or produced water from
the well, separator, or non-separator equipment enter an atmospheric
pressure storage tank. If you elect to use ProMax[supreg], you must use
version 5.0 or above. A minimum of the parameters listed in paragraphs
(j)(1)(i) through (vii) of this section, as applicable, must be used to
characterize emissions. If paragraphs (j)(1)(i) through (vii) of this
section indicates that an applicable parameter must be measured,
collect measurements reflective of representative operating conditions
for the time period covered by the simulation. Determine all other
applicable parameters in paragraphs (j)(1)(i) through (vii) of this
section by engineering estimate and process knowledge based on best
available data and, if necessary, adjust parameters to represent the
operating conditions over the time period covered by the simulation.
Determine the number of simulations and associated time periods such
that the simulations cover the entire reporting year (i.e., if you
calculate emissions using one simulation, use representative parameters
for the operating conditions over the calendar year; if you use
periodic simulations to cover the calendar year, use parameters for the
operating conditions over each corresponding appropriate portion of the
calendar year).
    (i) Well, separator, or non-separator equipment temperature (must
be measured).
    (ii) Well, separator, or non-separator equipment pressure (must be
measured).
    (iii) For atmospheric pressure storage tanks receiving hydrocarbon
liquids, sales or stabilized hydrocarbon liquids API gravity (must be
measured).
    (iv) Sales or stabilized hydrocarbon liquids or produced water
production rate (must be measured).
    (v) Ambient air temperature.
    (vi) Ambient air pressure.
    (vii) Well, separator, or non-separator equipment hydrocarbon
liquids or produced water composition and Reid vapor pressure (must be
measured). Use an appropriate standard method published by a consensus-
based standards organization if such a method exists or you may use an
industry standard practice as specified in Sec.  98.234(b) to sample
and analyze hydrocarbon liquids or produced water composition and Reid
vapor pressure.
    (2) Calculation Method 2. For atmospheric pressure storage tanks
receiving hydrocarbon liquids, calculate annual CH4 and
CO2 emissions using the methods in paragraph (j)(2)(i) of
this section. For atmospheric pressure storage tanks receiving produced
water, calculate annual CH4 emissions using the methods in
paragraph (j)(2)(i) of this section.
    (i) Assume that all of the CH4 and, if applicable,
CO2 in solution at well, separator, or non-separator
equipment temperature and pressure is emitted from hydrocarbon liquids
or produced water sent to atmosphere pressure 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 hydrocarbon liquids or produced water composition at well,
separator, or non-separator pressure and temperature.
    (ii) [Reserved]
    (3) Calculation Method 3. Calculate CH4 and
CO2 emissions from atmospheric pressure storage tanks
receiving hydrocarbon liquids as specified in paragraph (j)(3)(i) of
this section. Calculate CH4 emissions from atmospheric
pressure storage tanks receiving produced water as specified in
paragraph (j)(3)(ii) of this section.
    (i) Calculate CH4 and CO2 emissions from
atmospheric pressure storage tanks receiving hydrocarbon liquids using
Equation W-15A of this section:
[GRAPHIC] [TIFF OMITTED] TP01AU23.019

Where:

Es,i = Annual total volumetric GHG emissions (either
CO2 or CH4) at standard conditions in cubic
feet.
EFi = Population emission factor for separators, wells,
or non-separator equipment in thousand standard cubic feet per
separator, well, or non-separator equipment per year, for crude oil
use 4.2 for CH4 and 2.8 for CO2 at 60 [deg]F
and 14.7 psia, and for gas condensate use 17.6 for CH4
and 2.8 for CO2 at 60 [deg]F and 14.7 psia.
Count = Total number of separators, wells, or non-separator
equipment with annual average daily throughput greater than 0
barrels per day and less than 10 barrels per day. Count only
separators, wells, or non-separator equipment that feed hydrocarbon
liquids directly to the atmospheric pressure storage tank for which
you elect to use this Calculation Method 3.
1,000 = Conversion from thousand standard cubic feet to standard
cubic feet.

    (ii) Calculate CH4 emissions from atmospheric pressure storage
tanks receiving produced water using Equation W-15B of this section:
[GRAPHIC] [TIFF OMITTED] TP01AU23.020

Where:

MassCH4 = Annual total CH4 emissions in metric
tons.
EFCH4 = Population emission factor for produced water in
metric tons CH4 per thousand barrels produced water per
year. For produced water streams from separators, wells, or non-
separator equipment with pressure less than or equal to 50 psi, use
0.0015. For produced water streams from separators, wells, or non-
separator equipment with pressure greater than 50 but less than or
equal to 250 psi, use 0.0142. For produced water streams from
separators, wells, or non-separator equipment with pressure greater
than 250 psi, use 0.0508. Pressure should be representative of
separators, wells, or non-separator equipment that feed produced
water directly to the atmosphere pressure storage tank.
FR = Annual flow rate of produced water to atmospheric pressure
storage tanks, in barrels.
0.001 = Conversion from barrels to thousand barrels.

    (4) Routing to vapor recovery systems or flares. If the atmospheric
pressure storage tank receiving your hydrocarbon liquids or produced
water has a vapor recovery system or routes emissions to

a flare, calculate annual emissions vented directly to atmosphere from
the storage tank during periods of time when emissions were not routed
to the vapor recovery system or flare as specified in paragraph
(j)(4)(i) of this section. Determine recovered mass as specified in
paragraph (j)(4)(ii) of this section.
    (i) For an atmospheric pressure storage tank that routes any
emissions to a vapor recovery system or a flare, calculate vented
emissions as specified in paragraphs (j)(4)(i)(A) through (E) of this
section.
    (A) Calculate maximum potential vented emissions as specified in
paragraph (j)(1), (2), or (3) of this section, and calculate an average
hourly vented emissions rate by dividing the maximum potential vented
emissions by the number of hours that the tank was in operation.
    (B) To calculate vented emissions during periods when the tank was
not routing emissions to a vapor recovery system or a flare, multiply
the average hourly vented emissions rate determined in paragraph
(j)(4)(i)(A) of this section by the number of hours that the tank
vented directly to the atmosphere. Determine the number of hours that
the tank vented directly to atmosphere by subtracting the hours that
the tank was connected to a vapor recovery system or flare (based on
engineering estimate and best available data) from the total operating
hours for the tank in the calendar year. If emissions are routed to a
flare but the flare is unlit, calculate emissions in accordance with
the methodology specified in paragraph (n) of this section and report
emissions from the flare as specified in Sec.  98.236(n).
    (C) During periods when a thief hatch is open or not properly
seated and emissions from the tank are routed to a vapor recovery
system or a flare, assume the capture efficiency of the vapor recovery
system or a flare is 0 percent. To calculate vented emissions during
such periods, multiply the average hourly vented emissions rate
determined in paragraph (j)(4)(i)(A) of this section by the number of
hours that the thief hatch is open or not properly seated. Determine
the number of hours that the thief hatch is open or not properly seated
as specified in paragraph (j)(7) of this section.
    (D) Calculate vented emissions not captured by the vapor recovery
system or a flare due to causes other than open or not properly seated
thief hatches based on best available data.
    (E) Calculate total emissions vented directly to atmosphere as the
sum of the emissions calculated as specified in paragraphs (j)(4)(i)(B)
through (D) of this section.
    (ii) 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 mass recovered
as specified in paragraphs (j)(4)(i)(C) and (D) of this section.
    (5) Gas-liquid separator dump valves. 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 that did not close properly during the calendar year by
using Equation W-16 of this section. Determine the total time a dump
valve did not close properly in the calendar year (Tdv) as
specified in paragraph (j)(5)(i) of this section.
[GRAPHIC] [TIFF OMITTED] TP01AU23.021

Where:

Es,i,dv = Annual volumetric GHG emissions (either
CO2 or CH4) at standard conditions in cubic
feet from atmospheric pressure storage tanks that resulted from the
dump valve on an associated gas-liquid separator that did not close
properly.
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.
Es,i = Annual volumetric GHG emissions (either
CO2 or CH4) as determined in paragraphs (j)(1)
and (2) and, if applicable, (j)(4) of this section, in standard
cubic feet per year, from atmospheric pressure storage tanks with
dump valves on an associated gas-liquid separator that did not close
properly.
8,760 = Conversion to hourly emissions.
Tdv = Total time a dump valve did not close properly in
the calendar year as determined in paragraph (j)(5)(i) of this
section, in hours.

    (i) You must perform a visual inspection of each gas-liquid
separator liquid dump valve to determine if the valve is stuck in an
open or partially open position, in accordance with paragraph
(j)(5)(i)(A) and (B) of this section.
    (A) Visual inspections must be conducted at least once in a
calendar year.
    (B) If stuck gas-liquid separator liquid dump valve is identified,
the dump valve must be counted as being open since the beginning of the
calendar year, or from the previous visual inspection that did not
identify the dump valve as being stuck in the open position in the same
calendar year. If the dump valve is fixed following visual inspection,
the time period for which the dump valve was stuck open will end upon
being repaired. If a stuck dump valve is identified and not repaired,
the time period for which the dump valve was stuck open must be counted
as having occurred through the rest of the calendar year.
    (ii) [Reserved]
    (6) Mass emissions. Calculate both CH4 and
CO2 mass emissions from natural gas volumetric emissions
using calculations in paragraph (v) of this section.
    (7) Thief hatches. If a thief hatch sensor is operating on a
controlled atmospheric pressure storage tank, you must use data
obtained from the thief hatch sensor to determine periods when the
thief hatch is open or not properly seated. An applicable operating
thief hatch sensor must be capable of transmitting and logging data
whenever a thief hatch is open or not properly seated, as well as when
the thief hatch is subsequently closed. If a thief hatch sensor is not
operating, you must perform a visual inspection of each thief hatch on
a controlled atmospheric pressure storage tank in accordance with
paragraph (j)(7)(i) through (iii) of this section.
    (i) For thief hatches on atmospheric pressure storage tanks subject
to the fugitive emissions standards for well sites, centralized
production facilities, and compressor stations in Sec.  60.5397b of
this chapter, or an applicable approved state plan or applicable
Federal plan in part 62 of this chapter, visual inspections must be
conducted at least as frequent as the required visual, audible, or
olfactory fugitive emissions components surveys described in Sec.
60.5397b or the applicable approved state plan or applicable Federal
plan in

part 62. If the time between required visual, audible, or olfactory
fugitive emissions components surveys described in Sec.  60.5397b or
the applicable approved state plan or applicable Federal plan in part
62 is greater than one year, visual inspections must be conducted at
least annually.
    (ii) For thief hatches on atmospheric pressure storage tanks not
subject to the fugitive emissions standards for well sites, centralized
production facilities, and compressor stations in Sec.  60.5397b of
this chapter, or an applicable approved state plan or applicable
Federal plan in part 62 of this chapter, visual inspections must be
conducted at least once in a calendar year.
    (iii) If one visual inspection is conducted in the calendar year,
assume the thief hatch was open for the entire calendar year. If
multiple visual inspections are conducted in the calendar year, assume
a thief hatch found open in the first visual inspection was open since
the beginning of the year until the date of the visual inspection;
assume a thief hatch found open in the last visual inspection of the
year was open from the preceding visual inspection through the end of
the year; assume a thief hatch found open in a visual inspection
between the first and last visual inspections of the year was open
since the preceding visual inspection until the date of the visual
inspection.
    (k) Condensate storage tanks. For vent stacks connected to one or
more condensate storage tanks, either water or hydrocarbon, without
vapor recovery, flares, or other controls, in onshore natural gas
transmission compression or underground natural gas storage, calculate
CH4 and CO2 annual emissions from compressor
scrubber dump valve leakage as specified in paragraphs (k)(1) through
(4) of this section.
* * * * *
    (l) Well testing venting and flaring. Calculate CH4 and
CO2 annual emissions from well testing venting as specified
in paragraphs (l)(1) through (5) of this section. If emissions from
well testing venting are routed to a flare, you must calculate
CH4, CO2, and N2O annual emissions as
specified in paragraph (n) of this section.
* * * * *
    (3) Estimate venting emissions using Equation W-17A (for oil wells)
or Equation W-17B (for gas wells) of this section for each well tested
during the reporting year.
[GRAPHIC] [TIFF OMITTED] TP01AU23.022

[GRAPHIC] [TIFF OMITTED] TP01AU23.023

Where:

Ea,n = Annual volumetric natural gas emissions from well
testing for each well being tested in cubic feet under actual
conditions.
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil for
each well being tested; oil here refers to hydrocarbon liquids
produced of all API gravities.
FR = Average annual flow rate in barrels of oil per day for the oil
well being tested.
PR = Average annual production rate in actual cubic feet per day for
the gas well being tested.
D = Number of days during the calendar year that the well is tested.
* * * * *
    (m) Associated gas venting and flaring. Calculate CH4
and CO2 annual emissions from associated gas venting not in
conjunction with well testing (refer to paragraph (l) of this section)
as specified in paragraphs (m)(1) through (4) of this section. If
emissions from associated gas venting are routed to a flare, you must
calculate CH4, CO2, and N2O annual
emissions as specified in paragraph (n) of this section.
* * * * *
    (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.
[GRAPHIC] [TIFF OMITTED] TP01AU23.024

Where:

Es,n,p = Annual volumetric natural gas emissions at each
well from associated gas venting at standard conditions, in cubic
feet.
GORp = Gas to oil ratio, for well p, in standard cubic
feet of gas per barrel of oil; oil here refers to hydrocarbon
liquids produced of all API gravities.
Vp = Volume of oil produced, for well p, in barrels in
the calendar year only during time periods in which associated gas
was vented or flared.
SGp = Volume of associated gas sent to sales or volume of
associated gas used for other purposes at the facility site,
including powering engines, separators, safety systems and/or
combustion equipment and not flared or vented, for well p, in
standard cubic feet of gas in the calendar year only during time
periods in which associated gas was vented or flared.
* * * * *
    (n) Flare stack emissions. Except as specified in paragraph (n)(9)
of this section, calculate CO2, CH4, and
N2O emissions from each flare stack as specified in
paragraphs (n)(1) through (8) of this section. For each flare,
disaggregate the total flared emissions to applicable source types as
specified in paragraph (n)(10) of this section.
    (1) Flow measurement. Measure total flow to the flare as specified
in either paragraph (n)(1)(i) or (ii) of this section.
    (i) Use a continuous parameter monitoring system for measuring the
flow of gas to the flare downstream of any sweep, purge, or auxiliary
gas addition. You may use direct flow meters or other parameter
monitoring systems combined with engineering calculations, such as line
pressure and burner nozzle dimensions, to satisfy this requirement. The
continuous parameter monitoring system must measure data values at
least once every hour.
    (ii) Use a continuous parameter monitoring system for measuring the
flow of gas from each source that routes gas to the flare, including
purge gas, sweep gas, and auxiliary fuel. You may use direct flow
meters or other parameter monitoring systems combined with engineering

calculations, such as line pressure and burner nozzle dimensions, to
satisfy this requirement. If the emission streams for multiple sources
are routed to a manifold before being combined with other emission
streams, you may conduct the measurement in the manifold instead of
from each source that is routed to the manifold.
    (2) Pilot. Continuously monitor for the presence of a pilot flame
or combustion flame as specified in paragraph (n)(2)(i) of this section
or visually inspect for the presence of a pilot flame or combustion
flame as specified in paragraph (n)(2)(ii) of this section. If you
continuously monitor, then periods when the flare are unlit must be
determined based on those data.
    (i) At least once every five minutes monitor for the presence of a
pilot flame or combustion flame using a device (including, but not
limited to, a thermocouple, ultraviolet beam sensor, or infrared
sensor) capable of detecting that the pilot or combustion flame is
present at all times. Continuous monitoring systems used for the
presence of a pilot flame or combustion flame are not subject to a
minimum accuracy requirement beyond being able to detect the presence
or absence of a flame and are exempt from the calibration requirements
of this part 98. Track the length of time over all periods when the
flare is unlit. Use the measured flow during these time periods, as
determined from measurements obtained under paragraph (n)(1) of this
section, to calculate the fraction of the total annual volume that is
routed to the flare when it is unlit. If the monitoring device is out
of service for more than one week, then visually inspect for the
presence of a pilot flame or combustion flame at least once per week
for the first 4 weeks that a monitoring device is out of service or
until a repaired or new device is operational, whichever period is
shorter. If the continuous monitoring device is out of service for less
than one week, then at least one visual inspection must be conducted
during the outage. If a flame is not detected during a weekly visual
inspection, assume the pilot has been unlit since the previous
inspection or the last time the continuous monitoring device detected a
flame, and assume that the pilot remains unlit until a subsequent
inspection or continuous monitoring device detects a flame. If the
monitoring device outage lasts more than 4 weeks, then you may switch
to conducting inspections at least once per month in accordance with
paragraph (n)(2)(ii) of this section.
    (ii) At least once per month visually inspect for the presence of a
pilot flame or combustion flame. If a flame is not detected, assume the
pilot has been unlit since the previous inspection and that it remains
unlit until a subsequent inspection detects a flame. Use the sum of the
measured flows, as determined from measurements obtained under
paragraph (n)(1) of this section, during all time periods when the
pilot was determined to be unlit, to calculate the fraction of the
total annual volume that is routed to the flare when it is unlit.
    (3) Gas composition. Determine the composition of the inlet gas to
the flare as specified in either paragraph (n)(3)(i), (ii), (iii), or
(iv) of this section.
    (i) Use a continuous gas composition analyzer on the inlet gas to
the flare burner downstream of any purge, sweep, or auxiliary fuel
addition to determine the annual average mole fractions of methane,
ethane, propane, butane, pentanes plus, and CO2.
    (ii) Take samples of the inlet gas to the flare burner downstream
of any purge, sweep, or auxiliary fuel addition at least once every
quarter in which gas is routed to the flare and analyze for methane,
ethane, propane, butane, pentanes plus, and CO2
constituents, Determine the annual average concentration of each
constituent as the flow-weighted annual average of all measurements for
that constituent during the year.
    (iii) Use a continuous gas composition analyzer on the emissions
streams from each emission source that routes gas to the flare. Also
take samples of purge gas, sweep gas, and auxiliary fuel at least
annually, and analyze for methane ethane, propane, butane, pentanes
plus, and CO2. If the emission streams for multiple sources
are routed to a manifold before being combined with other emission
streams, you may measure gas composition in the manifold instead of
from each source that is routed to the manifold. Determine the flow-
weighted annual average concentration of each constituent.
    (iv) Take samples of the emission streams from each source that
routes gas to the flare at least once every quarter in which gas is
routed to the flare and analyze for methane, ethane, propane, butane,
pentanes plus, and CO2. Also take samples of purge gas,
sweep gas, and auxiliary fuel at least annually, and analyze for
methane, ethane, propane, butane, pentanes plus, and CO2. If
the emission streams for multiple sources are routed to a manifold
before being combined with other emission streams, you may measure gas
composition in the manifold instead of from each source that is routed
to the manifold. Determine the annual average concentration of each
constituent in each stream as the flow-weighted average of all
measurements for that constituent during the year.
    (4) Combustion efficiency. Use the applicable default combustion
efficiency specified in paragraphs (n)(4)(i) through (iii) of this
section. If you change the Tier with which you comply during a year,
then use the applicable default combustion efficiencies in paragraphs
(n)(4)(i) through (iii) of this section for portions of the year during
which the different monitoring methodologies were used, and calculate a
time-weighted average combustion efficiency to report for the flare.
    (i) Tier 1. If you monitor the flare as specified in Sec.  63.670
and Sec.  63.671 of this chapter, then use a default combustion
efficiency of 98 percent. The alternative means of emissions limitation
specified in Sec.  63.670(r) of this chapter do not apply for the
purposes of this paragraph (n). References to deviations in Sec.
63.670(b) of this chapter do not apply for the purposes of this
paragraph (n). References to refineries or refinery process units in
Sec.  63.670 of this chapter mean facilities in any of the industry
segments specified in Sec.  98.230 for the purposes of this paragraph
(n). Reporting requirements in Sec.  63.670(q) of this chapter mean
recordkeeping requirements for the purposes of this paragraph (n).
    (ii) Tier 2. If you are required to monitor the flare as specified
in Sec.  60.5417b(d)(1)(viii) of this chapter, or you elect to
implement the flare monitoring requirements in Sec.
60.5417b(d)(1)(viii) of this chapter, then use a default combustion
efficiency of 95 percent. The exemptions from monitoring gas flow in
Sec.  60.5417b(d)(1)(viii)(D)(1) through (4) of this chapter do not
apply for the purposes of this paragraph (n).
    (iii) Tier 3. If you do not monitor the flare as specified in
either paragraph (n)(4)(i) or (ii) of this section, then use a default
combustion efficiency of 92 percent.
    (5) Calculate CH4 and CO2 emissions.
Calculate GHG volumetric emissions from flaring at standard conditions
using Equations W-19 and W-20 of this section and as specified in
paragraphs (n)(5)(i) through (iv) of this section.

[GRAPHIC] [TIFF OMITTED] TP01AU23.025

[GRAPHIC] [TIFF OMITTED] TP01AU23.026

Where:

Es,CH4 = Annual CH4 emissions from
flare stack in cubic feet, at standard conditions.
Es,CO2 = Annual CO2 emissions from
flare stack in cubic feet, at standard conditions.
Vs = Volume of gas sent to flare in standard cubic feet,
during the year as determined in paragraph (n)(1) of this section.
[eta] = Flare combustion efficiency, expressed as fraction of gas
combusted by a burning flare.
XCH4 = Annual average mole fraction of CH4 in
the feed gas to the flare or in each of the streams routed to the
flare as determined in paragraph (n)(3) of this section.
XCO2 = Annual average mole fraction of CO2 in
the feed gas to the flare or in each of the streams routed to the
flare as determined in paragraph (n)(3) of this section.
ZU = Fraction of the feed gas sent to an un-lit flare
determined from both the total time the flare was unlit as
determined by monitoring the pilot flame or combustion flame as
specified in paragraph (n)(2) of this section and the volume of gas
routed to the flare during periods when the flare was unlit as
determined by the flow measurement required by paragraph (n)(1) of
this section.
ZL = Fraction of the feed gas sent to a burning flare
(equal to 1-ZU).
Yj = Annual average mole fraction of hydrocarbon
constituents j (such as methane, ethane, propane, butane, and
pentanes-plus) in the feed gas to the flare or in each of the
streams routed to the flare as determined in paragraph (n)(3) of
this section.
Rj = Number of carbon atoms in the hydrocarbon
constituent j in the feed gas to the flare: 1 for methane, 2 for
ethane, 3 for propane, 4 for butane, and 5 for pentanes-plus).

    (i) If you measure the gas flow at the flare inlet as specified in
paragraph (n)(1)(i) of this section and you measure gas composition for
the inlet gas to the flare as specified in paragraph (n)(3)(i) or (ii)
of this section, then use those data in Equations W-19 and W-20 to
calculate total emissions from the flare.
    (ii) If you measure the flow from each source as specified in
paragraph (n)(1)(ii) of this section and you measure gas composition
for the inlet gas to the flare as specified in paragraph (n)(3)(i) or
(ii) of this section, then sum the flows for each stream to calculate
the total annual gas flow to the flare. Use that total annual flow with
the annual average concentration of each constituent as calculated in
paragraph (n)(3)(i) or (ii) of this section in Equations W-19 and W-20
to calculate total emissions from the flare.
    (iii) If you measure the flow from each source as specified in
paragraph (n)(1)(ii) of this section and you measure gas composition
for the emission stream from each source as specified in paragraph
(n)(3)(iii) or (iv) of this section, then calculate total emissions
from the flare as specified in either paragraph (n)(5)(iii)(A) or (B)
of this section.
    (A) Use each set of stream-specific flow and annual average
concentration data in Equations W-19 and W-20 to calculate stream-
specific flared emissions for each stream, and then sum the results
from each stream-specific calculation to calculate the total emissions
from the flare.
    (B) Sum the flows from each source to calculate the total gas flow
into the flare and use the source-specific flows and source-specific
annual average concentrations to determine flow-weighted annual average
concentrations of CO2 and hydrocarbon constituents in the
combined gas stream into the flare. Use the calculated total gas flow
and the calculated flow-weighted annual average concentrations for the
inlet gas stream to the flare in Equations W-19 and W-20 to calculate
the total emissions from the flare.
    (iv) You may not combine measurement of the inlet gas flow to the
flare as specified in paragraph (n)(1)(i) of this section with
measurement of the gas composition of the streams from each source as
specified in paragraph (n)(3)(iii) or (iv) of this section.
    (6) Convert volume at actual conditions to volume at standard
conditions. Convert GHG volumetric emissions to standard conditions
using calculations in paragraph (t) of this section.
    (7) Convert volumetric emissions to mass emissions. Calculate both
CH4 and CO2 mass emissions from volumetric
emissions using calculation in paragraph (v) of this section.
    (8) Calculate N2O emissions. Calculate N2O emissions