June 2017
Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2016:
Updates Under Consideration for C02 Emissions
This memo discusses C02 emission calculation revisions being considered for multiple segments of
natural gas and petroleum systems in the 2018 Inventory of U.S. Greenhouse Gas Emissions and Sinks
(GHGI). The EPA is considering C02 methodological revisions for sources and segments that already rely
on a subpart W-based CH4 emission calculation methodology or where the CH4 calculation methodology
was otherwise recently revised. The subpart W methodology revisions are documented in the following
memos: the 2014 HF Completion and Workover memo,1 2015 HF Completion and Workover memo,2
2016 Transmission memo,3 2016 Production memo,4 2017 Production memo,5 and 2017 Processing
memo.6 These revisions will create consistency between CH4 and C02 calculation methodologies. In
addition, the EPA is considering updating the GHGI to include both the C02 emissions and the relatively
minor CH4 emissions from flare stacks reported under subpart W in the production and transmission and
storage segments.
The sources discussed in this memo include: production segment storage tanks, associated gas venting
and flaring, hydraulically fractured (HF) gas well completions and workovers, production segment
pneumatic controllers, production segment pneumatic pumps, liquids unloading, production segment
miscellaneous flaring, most sources in the gas processing segment, transmission station flares,
underground natural gas storage flares, LNG storage flares, LNG import flares, and transmission and
storage pneumatic controllers. The EPA is not considering revisions to the distribution segment C02
emissions calculation methodology, as discussed in Section 1.2.
1. Background and Current GHGI Methodology for COz Emissions
This section discusses the current GHGI methodology for calculating C02 emissions. Section 1.1
describes a C02-to-CH4 gas content ratio methodology, which is the default approach used in all GHGI
segments. Section 1.2 describes the current GHGI methodology to calculate C02 emissions for certain
1	"Overview of Update to Methodology for Hydraulically Fractured Gas Well Completions and Workovers in the
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (2014 Inventory)/' available at
https://www.epa.gov/ghgemissions/natural-gas-and-petroleum-systems-ghg-inventory-updates-1990-2012-
inventory-published.
2	"Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2013: Revision to Hydraulically Fractured Gas Well
Completions and Workovers Estimate," available at https://www.epa.gov/ghgemissions/natural-gas-and-
petroleum-systems-ghg-inventory-updates-1990-2013-inventory-published.
3	"Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2014: Revisions to Natural Gas Transmission and
Storage Emissions," available at https://www.epa.gov/ghgemissions/natural-gas-and-petroleum-systems-ghg-
inventory-additional-information-1990-2014-ghg.
4	"Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2014: Revisions to Natural Gas and Petroleum
Production Emissions," available at https://www.epa.gov/ghgemissions/natural-gas-and-petroleum-systems-ghg-
inventory-additional-information-1990-2014-ghg.
5	"Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2015: Revisions to Natural Gas and Petroleum
Systems Production Emissions," available at https://www.epa.gov/ghgemissions/natural-gas-and-petroleum-
systems-ghg-inventory-additional-information-1990-2015-ghg.
6	"Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2015: Revisions to Natural Gas Systems Processing
Segment Emissions," available at https://www.epa.gov/ghgemissions/natural-gas-and-petroleum-systems-ghg-
inventory-additional-information-1990-2015-ghg.
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June 2017
sources that rely on emission source-specific methods. The current GHGI C02 EFs are documented in
Appendix A.
COz-to-CH# Gas Content Ratio Methodology
The current GHGI methodology to calculate C02 emission factors (EFs) for the majority of emission
sources relies on CH4 emission factors and an assumed ratio of C02-to-CH4 gas content. The C02 EF
calculation is shown in equation 1:
__	^ /CO, content \
C02 EF = CH4 EF * I	I	Equation 1
z	4	VCH4 content/	^
The default CH4 and C02 content values for sources in natural gas systems are from the 1996 GRI/EPA
study/ EIA,8 and GTI's Gas Resource Database9 and summarized in Table 1 below.
Table 1. Default Gas Content Values for Natural Gas Systems in the GHGI
Segment
CH4 Content
(vol%)
CO; Content
(vol%)
Production - North East region
78.8
3.04
Production - Mid Central region
0.79
Production - Gulf Coast region
2.17
Production - South West region
3.81
Production - Rocky Mountain region
7.58
Production - West Coast region
0.16
Processing - Before C02 removal
87.0
3.45
Processing - After CO2 removal
1.0
Transmission and Underground NG Storage
93.4
1.0
LNG Storage and LNG Import/Export
93.4
1.16
Distribution
93.4
1.0
For most of the petroleum production sources evaluated in this memo, the GHGI uses a ratio of C02 to
CH4 content is set at 0.017 based on the average flash gas C02 and CH4 content from API TankCalc runs.
The ratio of C02-to-CH4 gas content methodology is used to calculate venting and fugitive C02 EFs,
because the CH4 EFs that are referenced for this methodology represent venting and fugitive emissions,
which are predominantly CH4 with minimal C02 emissions. EPA does not use this methodology in the
GHGI to calculate C02 EFs for combustion sources such as flares, for which the inverse is true (C02 is
predominant, with minimal CH4 emissions).
7	Methane Emissions from the Natural Gas Industry, Volume 6: Vented and Combustion Source Summary,
Appendix A.
8	U.S. Energy Information Administration. Emissions of Greenhouse Gases in the United States: 1987-1992,
Appendix A. 1994.
9	GRI-01/0136 GTI's Gas Resource Database: Unconventional Natural Gas and Gas Composition Databases. Second
Edition. August, 2001.
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1.2 Emission Source-Specific CO2 Calculation Methodologies
The current GHGI uses emission source-specific methodologies to calculate C02 emissions from oil and
condensate tanks at production sites, AGR units at natural gas processing plants, and production and
processing flaring.
Qil..and...Cond^nMteJ^nks^LPm^^cMonSites
The current GHGI methodology to calculate C02 emissions for oil and condensate tanks uses C02 specific
EFs. The EFs were developed using API TankCalc software with varying API gravities. The oil tank EF is
the average from API TankCalc runs for oils with API gravity less than 45, and the condensate tank EF
considered data with API gravity greater than 45. Condensate tank EFs were determined for both
controlled and uncontrolled tanks; the controlled tank EF assumed a control efficiency of 80%. The
current GHGI calculates oil tank C02 emissions by applying the oil tank emission factor (EF) to 20% of
stripper well production and 100% of non-stripper oil well production. For gas production, the current
GHGI methodology estimates tank emissions by applying the condensate tank EF to condensate
production in each NEMS region.
The current GHGI C02 EF for AGR units at natural gas processing plants relies on gas C02 content only.
The difference in the default C02 content before and after C02 removal (3.45% -1.0% = 2.45% of
processing plant gas throughput) is assumed to be emitted.
Flaring
Flaring emissions from the production and processing segments are currently calculated under a single
line item in the production segment of natural gas systems. Therefore, flaring emissions are not
specifically attributed to the processing segment of natural gas systems or the production segment of
petroleum systems. The EF is based on data from ElA's 1996 greenhouse gas emissions inventory, which
estimated the amount of C02 released per BTU of natural gas combusted (0.055 g/BTU). The activity
data are annual EIA "Vented and Flared" gas volumes (MMcf), which are reported under Natural Gas
Gross Withdrawals and Production,10 combined with the estimated national average gas heating value
(averaging approximately 1,100 BTU/cf over the time series11). The EIA Vented and Flared data
represents a balancing factor amount that EIA calculates to reconcile reported upstream and
downstream gas volumes, and assumes is potentially emitted to the atmosphere during production or
processing operations; the current GHGI assumes it is all flared. Details on how much of the Vented and
Flared gas is potentially emitted during natural gas production, petroleum production, and processing
are not available, so the current GHGI assigns it all to natural gas production. Also, the EIA data do not
account for gas that is flared prior to metering.
Flaring emissions from the transmission and storage segment and distribution segment are not currently
calculated in the GHGI. Data are unavailable on flaring emissions in the distribution segment, but they
are likely to be insignificant. EPA is not considering revisions to the distribution segment C02 emissions
calculation methodology for the 2018 GHGI.
10	EIA Natural Gas Gross Withdrawals and Production, including the Vented and Flared category, is available at
https://www.eia.gov/dnav/ng/ng_prod_sum_a_EPGO_VGV_mmcf_m.htm
11	EIA Monthly Energy Review. Table A4 - Approximate Heat Content of Natural Gas (Btu per Cubic Feet).
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June 2017
2, Available Subpart W Data
Subpart W of the EPA's Greenhouse Gas Reporting Program (GHGRP) collects annual operating and
emissions data on numerous sources from onshore natural gas and petroleum systems and natural gas
processing facilities that meet a reporting threshold of 25,000 metric tons of C02 equivalent (MT C02e)
emissions. Onshore production facilities in subpart W are defined as a unique combination of operator
and basin of operation, a natural gas processing facility in subpart W is each unique processing plant, a
natural gas transmission compression facility in subpart W is each unique transmission compressor
station, an underground natural gas storage facility in subpart W is the collection of subsurface storage
and processes and above ground wellheads, an LNG storage facility in subpart W is the collection of
storage vessels and related equipment, and an LNG import and export facility in subpart W is the
collection of equipment that handles LNG received from or transported via ocean transportation.
Facilities in the above-mentioned industry segments that meet the subpart W reporting threshold have
been reporting since 2011; currently, five years of subpart W reporting data are publicly available,
covering reporting year (RY) 2011 through RY2015.12
Subpart W activity and emissions data are used in the current GHGI to calculate CH4 emissions for
several production, processing, and transmission and storage sources. C02 emissions data from subpart
W have not yet been incorporated into the GHGI. However, facilities use an identical reporting structure
for C02 and CH4. Therefore, where subpart W CH4 data have been used, the C02 data may be
incorporated in an identical manner. The 2014 HF Completion and Workover memo, 2016 Transmission
memo, 2016 Production memo, 2017 Production memo, and 2017 Processing memo discuss in greater
detail the subpart W data available for those sources.
EPA is also considering GHGI revisions to use subpart W data for C02 emission estimates from
miscellaneous production flaring, acid gas removal (AGR) vents, and transmission and storage station
flares—sources for which the emissions are not currently calculated with subpart W data in the GHGI.
Production segment flare emissions are only reported under the "flare stacks" emission source in
subpart W if the flare emissions originate from sources not otherwise covered by subpart W—this
emission source is referred to as "miscellaneous flaring" for purposes of this memo. Therefore, the
subpart W production flares data do not duplicate flaring emissions reported, for example, under
production tank flaring or associated gas flaring. It also ensures all production flaring emissions are
reported for facilities that meet the reporting threshold. Flare emissions are calculated using a
continuous flow measurement device or engineering calculations, the gas composition, and the flare
combustion efficiency. A default flare combustion efficiency of 98% may be applied, if manufacturer
data are not available.
Under subpart W, gas processing facilities calculate AGR unit C02 emissions using one of four methods:
(1) C02 CEMS; (2) a vent stream flow meter with C02 composition data; (3) calculation using an equation
with the inlet or outlet natural gas flow rate and measured inlet and outlet C02 composition data; or (4)
simulation software (e.g., AspenTech HYSYS or API 4679 AMINECalc). CH4 emissions for AGR units are
not reported in subpart W.
Transmission, underground natural gas storage, LNG storage, and LNG import stations report emissions
from all flaring under the "flare stacks" emission source as of RY2015. Prior to that, flare emissions
12 The GHGRP subpart W data used in the analyses discussed in this memo are those reported to the EPA as of
August 13, 2016.
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June 2017
reported under subpart W were included in the reported emissions for the specific source (e.g.,
reciprocating or centrifugal compressor). Flare emissions are calculated in subpart W using a continuous
flow measurement device or engineering calculations, the gas composition, and the flare combustion
efficiency. A default flare combustion efficiency of 98% may be applied, if manufacturer data are not
available.
3, Revisions Under Consideration
The EPA is considering revising C02 EFs for certain production, natural gas processing, and transmission
and storage segment sources to use subpart W data in the exact same manner as CH4 EFs are currently
calculated in the GHGI. For purposes of this memo, EPA calculated preliminary C02 EFs using data from
the same subpart W reporting years (RY) as were used when developing CH4 EFs for the 2017 GHGI. For
the 2018 GHGI, EPA will separately seek stakeholder feedback on potentially using data from other
subpart W years to recalculate both CH4 and C02 EFs.
In addition, EPA is considering updating the GHGI to incorporate subpart W data for C02 from AGR units,
and both the C02 emissions and the relatively minor CH4 emissions from flare stacks.
duction C(h Emission Factors
The EPA developed preliminary C02 EFs for associated gas venting and flaring, oil and condensate tanks,
gas well hydraulically fractured completions and workovers, pneumatic controllers, pneumatic pumps,
and liquids unloading in the natural gas and petroleum production segments. The CH4 EFs for these
sources were recently revised using subpart W data, and EPA applied the same methodology to
calculate C02 EFs. A brief summary of the existing methodology and the resulting C02 EFs are provided
below for each source.
The EPA is also considering a C02 emissions calculation methodology for miscellaneous production
flaring, which is described below.
Associated Gas Venting and Flaring
Based on the CH4 EF methodology documented in the 2017 Production memo, the EPA calculated oil
well associated gas venting and flaring C02 EFs using subpart W data for RY2011 through RY2015. EPA
divided the reported associated gas or venting emissions by the number of reported wells with
associated gas venting or flaring for each year to calculate EFs. Subpart W C02 data are presented in
Table 2, and the calculated C02 EFs are presented in Table 3.
Table 2. GHGRP Subpart W C02 Data for Associated Gas Venting and Flaring
Year
Associated Gas Venting
Associated Gas Flaring
#Venting
Wells
Venting CO;
Emissions (MMT)
#Flaring
Wells
Flaring CO;
Emissions (MMT)
2011
8,863
0.012
5,628
3.72
2012
8,554
0.016
7,259
6.88
2013
6,980
0.005
8,880
9.61
2014
7,264
0.013
12,189
11.05
2015
4,286
0.011
21,606
10.31
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June 2017
Table 3. GHGRP Subpart W-based Associated Gas Venting and Flaring C02 EFs (kg/well/yr)
Year
Venting EF
Flaring EF
2011
1,336
661,723
2012
1,902
948,057
2013
773
1,081,842
2014
1,754
906,608
2015
2,675
477,254
Based on the CH4 EF methodology documented in the 2017 Production memo, the EPA calculated oil
and condensate tank C02 EFs for several tank categories, using RY2015 subpart W data: large tanks with
flaring; large tanks with a vapor recovery unit (VRU); large tanks without controls; small tanks with
flaring; small tanks without flaring; and malfunctioning separator dump valves. EPA applied several steps
described in the 2017 Production memo to apportion the reported subpart W data to each of the
categories. EPA then summed the emissions and divided by the throughput for each tank category.
Table 4 presents the resulting C02 EFs.
Table 4. GHGRP Subpart W-based Oil and Condensate Tank C02 EFs (kg/bbl/yr)
Tank Category
Oil Tanks EF
Condensate Tanks EF
Large Tanks with Flaring
7.16
8.44
Large Tanks with VRU
0.040
0.12
Large Tanks without Controls
0.016
0.020
Small Tanks with Flaring
0.26
1.95
Small Tanks without Flares
0.078
0.28
Malfunctioning Dump Valves
0.013
8.28E-05
HF Gas Well Completions arid Workovers
Based on the CH4 EF methodology documented in the 2014 HF Completion and Workover memo and
2015 HF Completion and Workover memo, the EPA calculated C02 EFs for four categories of HF gas well
completions and workovers, using RY2011-RY2013 subpart W data: HF gas well completions and
workovers that vent; flared HF gas well completions and workovers; HF gas well completions and
workovers with reduced emissions completions (RECs); and HF gas well completions and workovers with
RECs that flare. Average emissions per completion and workover were calculated for each category by
summing the emissions in each category and dividing by the number of completions and workovers in
each category using facility-level records that could be assigned to a single unambiguous category. Table
5 presents the subpart W activity and emissions data for those HF gas well completions and workovers
that could be assigned to a specific category, along with the calculated C02 EFs.
Table 5. GHGRP Subpart W Activity and Emissions Data and Calculated EFs for HF Gas Well
Completions and Workovers
Category
# of Events
CO; Emissions
mt)
CO; EF
(kg/event)
2011
2012
2013
2011
2012
2013
HF Completions and Workovers
that Vent
3,901
2,370
1,308
11,700
2,681
7,214
2,849
Flared HF Completions and
Workovers
1,171
538
422
1,203,235
363,631
192,235
825,481
HF Completions and Workovers
with RECs
2,224
1,283
1,566
3,745
151
995
964
HF Completions and Workovers
with RECs that flare
818
968
1,129
485,313
387,280
460,691
457,387
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June 2017
Pneumatic Controllers
Based on the CH4 EF methodology documented in the 2016 Production memo, the EPA calculated
pneumatic controller EFs for low, intermittent, and high bleed controllers using Subpart W RY2014 data.
EPA divided the reported emissions by the number of reported controllers for each controller type to
calculate EFs. All pneumatic controllers data were considered together, and thus pneumatic controller
EFs for natural gas and petroleum systems are identical. Table 6 presents the subpart W activity and
emissions data, along with the calculated C02 EFs.
Table 6. GHGRP Subpart W RY2014 Activity and Emissions Data and Calculated EFs for
Pneumatic Controllers
Controller Type
# Controllers
Total CO;
Emissions (mt)
CO; EF
(kg/controller/yr)
Low Bleed
200,337
2,391
12
Intermittent Bleed
572,407
98,393
172
High Bleed
29,567
10,013
339
Pneumatic Pumps
Based on the CH4 EF methodology documented in the 2016 Production memo, the EPA calculated a
pneumatic pump EF using Subpart W RY2014 data. EPA divided the reported emissions by the number of
reported pneumatic pumps to calculate the EF. All pneumatic pumps data were considered together,
and thus the EF for natural gas and petroleum systems is identical. Table 7 presents the subpart W
activity and emissions data, along with the calculated C02 EF.
Table 7. GHGRP Subpart W RY2014 Activity and Emissions Data and Calculated EF for
Pneumatic Pumps
# Pumps
Total CO;
Emissions (mt)
CO; EF
(kg/pump/yr)
79,885
11,650
146
Liquids Unloading
Based on the CH4 EF methodology documented in the 2017 Production memo, the EPA calculated liquids
unloading EFs using Subpart W RY2011-RY2015 data. Separate EFs were calculated for liquids unloading
activities that vent with and without plunger lifts. The EPA calculated an average EF by summing the
emissions reported in each category for RY2011-RY2015 and dividing by the total number of wells in
each category over those years. Table 8 presents the subpart W activity and emissions data, along with
the calculated C02 EFs.
Table 8. GHGRP Subpart W RY2011-RY2015 Activity and Emissions Data and Calculated
EFs for Liquids Unloading

With Plunger Lifts
Without Plunger Lifts
Year
CO; Emissions
# Wells
CO; Emissions
# Wells

(mt)
Vented
(mt)
Vented
2011
17,671
42,826
20,294
26,679
2012
18,869
34,136
26,300
25,262
2013
4,233
30,922
5,617
27,723
2014
2,430
26,859
5,113
23,068
2015
1,782
30,757
3,348
20,886
Total
44,985
165,500
60,673
123,618
EF (kg C02/well/yr)
272
491
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June 2017
Miscellaneous Production Flaring
The EPA is considering the use of subpart W RY 2015 miscellaneous production flaring (reported under
"flare stacks") emissions data to revise the GHGI and more fully account for flare emissions in the
production segment. Subpart W data for this source were not previously considered. The EPA calculated
the C02 and CH4 EFs using the following approach.
Miscellaneous production flaring emissions are not reported separately for gas and oil production.
Therefore, to use reported emissions data for separate natural gas and petroleum systems GHGI
estimates, the EPA calculated the fraction of wells that were gas and oil wells for each facility, using the
well counts reported in the Equipment Leaks section of subpart W for RY2015.13 The EPA then
apportioned each facility's reported miscellaneous flaring C02 and CH4 emissions by production type.
The EPA summed the facility-level C02 and CH4 emissions for each production type to estimate total
reported miscellaneous flaring C02 and CH4 emissions from natural gas and oil production. The EPA then
divided the reported C02 and CH4 emissions for natural gas and oil production by total reported gas
wells and oil wells, respectively. These emissions data, well counts, and calculated EFs are provided in
Table 9 and Table 10 below. To calculate national emissions, the EFs would be multiplied by the national
gas and oil well counts already estimated in the GHGI.
Table 9. GHGRP Subpart W RY2015 C02 Emissions and Activity Data and Calculated EFs
for Miscellaneous Production Flaring
Total CO;
Emissions
(mt)
Natu
CO: Emissions
(mt)
ral Gas Prodi
Total Gas
Wells
jction
CO; EF
(kg/well/yr)
0
CO; Emissions
(mt)
il Productio
Total Oil
Wells
n
CO; EF
(kg/well/yr)
3,779,110
1,299,672
307,737
4,223
2,479,438
219,433
11,299
Table 10. GHGRP Subpart W RY2015 CH4 Emissions and Activity Data and Calculated EFs for
Miscellaneous Production Flaring
Total CH4
Emissions
(mt)
Natur
CH4 Emissions
(mt)
al Gas Produc
Total Gas
Wells
tion
CH4 EF
(kg/well/yr)
(
CH4 Emissions
(mt)
)il Production
Total Oil
Wells
CH4 EF
(kg/well/yr)
14,058
5,443
307,737
17.7
8,614
219,433
39.3
3,2 Processing COz Emiss tclors
The EPA developed preliminary gas processing C02 EFs for the plant grouped emission sources
(reciprocating compressors, centrifugal compressors with wet seals, centrifugal compressors with dry
seals, dehydrators, flares, and plant fugitives), blowdowns and venting, and AGR vents. The CH4 EFs for
the grouped sources and blowdowns and venting were recently revised using subpart W data, and the
EPA applied the same methodology to calculate C02 EFs. While AGR vent emissions are not currently
calculated from subpart W data (as CH4 emissions are not reported for this source), the EPA has
calculated a subpart W-based EF and determined the corresponding activity data for this source.
Based on the CH4 EF methodology documented in the 2017 Processing memo, the EPA calculated the
plant grouped source C02 EFs using subpart W RY2015 data (the purpose of the plant grouped EF is
13RY2015 is the first year in which total oil and gas well counts are reported. However, six facilities did not report
these data. Therefore, for these six facilities, the EPA determined the fraction of sub-basins applicable to gas
production (i.e., sub-basins with high permeability gas, shale gas, coal seam, or other tight reservoir rock formation
types) and oil production (i.e., sub-basins with the oil formation type).
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June 2017
discussed in Section 3.4). Subpart W data and calculated C02 EFs for the plant grouped sources are
presented in Table 11.
Table 11. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EFs
for Gas Processing Plant Grouped Sources
Emission Source
CO;
Emissions
(mt)
Activity Count (plants
or compressors)
CO; EF
(kg/compressor/yr
or kg/plant/yr)
Reciprocating compressors
7,818
2,662
compressors
2,937
Centrifugal compressors with wet seals
1,259
264
compressors
4,768
Centrifugal compressors with dry seals
20
214
compressors
400
Dehydrators
7,433
467
plants
15,916
Flares
4,503,224
467
plants
9,642,878
Plant fugitives
2,291
467
plants
4,906
Plant Grouped Sources
4,522,046
467
plants
9,683,181
Based on the CH4 EF methodology documented in the 2017 Processing memo, the EPA also calculated
the blowdown and venting C02 EF using subpart W RY2015 data. Subpart W data and the calculated C02
EF for blowdowns and venting are presented in Table 12.
Table 12. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EF for
Gas Processing Blowdown and Venting
C02 Emissions
(mt)
Activity Count
(plants)
CO; EF
(kg/plant/yr)
11,084
467
23,733
For AGR vent emissions, the existing CH4 EF methodology does not rely on subpart W, but the EPA is
considering applying a similar methodology as the other processing sources to develop C02 EFs and
activity data from subpart W data. The EPA summed the reported AGR vent emissions for gas processing
plants and divided by the total reported count of plants for each RY from 2011 to 2015 to calculate C02
EFs. Note, the current GHGI methodologies for gas processing segment sources that use subpart W-
based CH4 EFs rely on RY2015 only. To calculate national C02 emissions, the C02 EF would be multiplied
by the number of gas plants each year. Subpart W data and the calculated C02 EFs for AGR vents are
presented in Table 13.
Table 13. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EF for
Gas Processing AGR Vents
Year
CO; Emissions
(mt)
Activity Count
(plants)
CO; EF
(kg/plant/yr)
2011
16,093,040
374
43,029,519
2012
15,692,240
403
38,938,561
2013
13,201,139
438
30,139,587
2014
12,559,555
479
26,220,366
2015
10,048,285
467
21,516,669
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3,3 Transmission and Storage CO2 Emission Factors
Based on the CH4 EF methodology documented in the 2016 Transmission memo, the EPA calculated
transmission station and storage station pneumatic controller C02 EFs for low, intermittent, and high
bleed controllers using Subpart W RY2011 - RY2015 data. The EPA divided the reported emissions by the
number of reported controllers for each controller type to calculate EFs. Table 14 and Table 15 present
the subpart W activity and emissions data, along with the calculated C02 EFs.
Table 14. GHGRP Subpart W Activity and Emissions Data and Calculated EFs for Transmission
Station Pneumatic Controllers
Controller Type
Data Element
2011
2012
2013
2014
2015
High Bleed
Total Count
2,203
1,114
1,158
1,173
1,483
CO2 Emissions (mt)
203
106
106
107
120
CO2 EF (kg/controller/yr)
92
95
91
91
81
Intermittent Bleed
Total Count
8,343
9,114
9,903
11,141
10,857
CO2 Emissions (mt)
673
736
747
134
103
CO2 EF (kg/controller/yr)
81
81
75
12
10
Low Bleed
Total Count
644
880
857
1,078
1,032
CO2 Emissions (mt)
4.6
6.2
6.2
6.7
4.3
CO2 EF (kg/controller/yr)
7.1
7.0
7.3
6.2
4.2
Table 15. GHGRP Subpart W Activity and Emissions Data and Calculated EFs for Underground
Natural Gas Storage Station Pneumatic Controllers
Controller Type
Data Element
2011
2012
2013
2014
2015
High Bleed
Total Count
1,253
1,100
1,089
1,271
1,024
CO2 Emissions (mt)
116
118
116
117
64
CO2 EF (kg/controller/yr)
92
107
106
92
63
Intermittent Bleed
Total Count
1,391
1,539
1,601
2,045
2,098
CO2 Emissions (mt)
16
21
21
24
22
CO2 EF (kg/controller/yr)
12
13
13
12
10
Low Bleed
Total Count
250
319
366
319
320
CO2 Emissions (mt)
1.9
2.4
2.8
2.2
1.4
CO2 EF (kg/controller/yr)
7.5
7.4
7.6
7.0
4.4
Hares
The EPA is considering developing updated GHGI flare C02 EFs for transmission station, underground
natural gas storage, LNG storage, and LNG import stations using subpart W data. As discussed in Section
1.3, the GHGI C02 emissions calculation methodology does not calculate C02 emissions from flares.
Therefore, the EPA is considering supplementing the current methodology to calculate C02 emissions
with new line items for station flares.
The EPA divided the reported flare C02 and CH4 emissions by the number of reported stations for
RY2015 to calculate the EFs. Subpart W transmission station, underground natural gas storage, LNG
storage, and LNG import station flare data are presented in Table 16 through Table 19. The applicable
activity data to calculate national emissions are the national number of stations, which are already
calculated in the GHGI.
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Table 16. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EFs
for Transmission Station Flares
Total #
Stations
# Stations
With Flares
# Flares
Total CO;
Emissions (mt)
CO; EF
(kg/station/yr)
Total CH4
Emissions (mt)
CH4 EF
(kg/station/yr)
521
16
24
28,511
54,723
124
238
Table 17. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EFs
for Underground Natural Gas Storage Flares
Total #
Stations
# Stations
With Flares
# Flares
Total CO;
Emissions (mt)
CO; EF
(kg/station/yr)
Total CH4
Emissions (mt)
CH4 EF
(kg/station/yr)
53
8
21
3,576
67,479
34
650
Table 18. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EFs
for LNG Storage Flares
Total #
Stations
# Stations
With Flares
# Flares
Total CO;
Emissions (mt)
CO; EF
(kg/station/yr)
Total CH4
Emissions (mt)
CH4 EF
(kg/station/yr)
7
2
2
259
37,042
1.9
266
Table 19. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EFs
for LNG Import Flares
Total #
Stations
# Stations
With Flares
# Flares
Total CO;
Emissions (mt)
CO; EF
(kg/station/yr)
Total CH4
Emissions (mt)
CH4 EF
(kg/station/yr)
7
2
3
77,420
11,059,970
268
38,238
3,4 Time Series Considerations
For the production segment sources discussed in Section 3.1, the EPA would apply the same
methodology to calculate C02 over the time series as used for calculating CH4 emissions over the time
series.14 For oil and condensate tanks, the EPA applies category-specific EFs for every year of the time
series; for associated gas venting and flaring, the EPA applies the subpart W 2011 EFs for years prior to
2011 and year-specific subpart W EFs are applied for 2011 and forward; for liquids unloading, the
average 2011-2015 EFs developed from subpart W data are applied to each year of the time series; for
pneumatic controllers and pumps, category-specific EFs are applied for each year of the time series; and
for HF gas well completions and workovers, category-specific EFs are applied for each year of the time
series. EPA will separately seek stakeholder feedback on considerations for time series calculations for
both CH4 and C02 emissions in the 2018 GHGI.
For the production miscellaneous flaring time series, the current GHGI flare emission estimate
(representing both production and processing), fluctuates based on activity data (ElA's estimated annual
vented and flared volumes). Assessment of subpart W C02 data over the time series for this source
indicates that miscellaneous flaring emissions per well do not show a clear trend. See Requests for
Stakeholder Feedback section for more information. In a revised approach to use subpart W-based C02
EFs (kg/well), the EF could be held constant for each year and flare emission estimates would fluctuate
with active gas or oil well count over the time series.
14 Additional details on current time series calculations for production segment sources are provided in the 2014
HF Completion and Workover memo, 2015 HF Completion and Workover memo, 2016 Production memo, and
2017 Production memo.
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For certain processing sources discussed in Section 3.1, the EPA would apply the same methodology to
calculate C02 over the time series as used for calculating CH4 emissions over the time series.15 For plant
grouped emission sources and blowdowns and venting, GRI/EPA 1996 EFs are used for 1990 through
1992; EFs calculated from subpart W are used for 2011 forward; and EFs for 1993 through 2010 are
developed through linear interpolation. For AGR vents, the EPA is considering adopting a similar
methodology as the other processing sources (maintain the current GRI/EPA 1996 EFs for 1990 through
1992, apply the subpart W-based EFs for 2011 forward, and develop EFs for 1993 through 2010 using
linear interpolation).
For transmission and storage flares, the EPA is evaluating the prevalence of flares over the 1990-2016
time series. The EPA is considering applying a subpart W-based EF (kg/station) for all years of the time
series. However, few transmission and storage stations reported flares for RY2015 (see Table 16 through
Table 19). Therefore, the EPA might alternatively assume that flares did not operate in 1990 (i.e., an EF
of 0), apply the subpart W-based EF for 2011 forward, and apply linear interpolation from 1991 through
2010.
4, National Emissions Estimates
The EPA calculated national C02 emissions using each of the subpart W-based approaches discussed in
Section 3 in conjunction with activity data for year 2015 from the 2017 GHGI. These emissions are
compared against 2015 emissions from the 2017 GHGI in Table 20 and Table 21.
Table 20. Natural Gas Systems Estimated Year 2015 National C02 Emissions (mt) Using
Subpart W-based EFs Compared to 2017 GHGI



Production
18,585,048
4,855,904
Tanks
30,426
1,108,346
Large Tanks w/Flares

1,059,701
Large Tanks w/VRU

2,840
Large Tanks w/o Control

632
Small Tanks w/Flares

35,173
Small Tanks w/o Flares

9,984
Malfunctioning Separator Dump Valves

15
Miscellaneous Flaring (a)
17,628,522
1,860,355
Gas HF Completions/Workovers
91,965
1,129,883
Non-REC with Venting

397
Non-REC with Flaring

281,489
REC with Venting

3,203
REC with Flaring

844,794
Liquids Unloading
39,485
9,282
w/Plunger Lifts
13,780
4,169
w/o Plunger Lifts
25,705
5,112
Pneumatic Controllers
119,970
79,608
Low-Bleed

1,842
Intermittent Bleed

71,177
15 Additional details on current time series calculations are provided in the 2017 Processing memo.
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High-Bleed

6,589
Pneumatic Pumps
14,021
7,770
Other Production Sources (b)
660,659
660,659
Processing
23,712,956
20,826,478
AGR Vents
23,643,456
14,351,618
Plant Grouped Sources
63,662
6,458,775
Blowdowns/Venting
5,586
15,830
Pneumatics
250
255
Transmission & Storage
38,694
250,095
Transmission Flares
0
100,357
Underground Storage Flares
0
23,542
LNG Storage Flares
0
2,603
LNG Import Flares
0
85,162
Pneumatic Controllers
1,649
1,386
Other Transmission & Storage Sources (b)
37,045
37,045
Distribution (b)
13,988
13,988


a. Also represents flaring from petroleum production and gas processing.
b. Set 2018 GHGI value equal to 2017 GHGI value.
Table 21. Petroleum Systems Estimated Year 2015 National C02 Emissions (mt) Using
Subpart W-based EFs Compared to Current GHGI



Production
640,443
44,233,703
Tanks
519,934
8,643,876
Large Tanks w/Flares

8,576,672
Large Tanks w/VRU

17,229
Large Tanks w/o Control

5,928
Small Tanks w/Flares

10,581
Small Tanks w/o Flares

8,271
Malfunctioning Separator Dump Valves

25,194
Miscellaneous Flaring
incl. w/NG
6,864,989
Associated Gas (a)
826
28,582,015
Flaring

28,550,273
Venting

31,742
Pneumatic Controllers
87,576
109,857
Low-Bleed
2,697
2,252
Intermittent Bleed
74,341
100,265
High-Bleed
10,538
7,339
Pneumatic Pumps
10,779
11,639
Other Production Sources (b)
21,327
21,327
Refining (b)
2,926,666
2,926,666



a. 2017 GHGI is estimate for stripper well venting.
b. Set 2018 GHGI value equal to 2017 GHGI value.
The C02 revisions under consideration will result in an overall shift of C02 emissions from Natural Gas
systems to Petroleum systems. This is due to the availability of industry segment-specific and emission
source-specific data in subpart W, whereas previous data sources were not as granular. The current
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GHGI accounts for all onshore production and gas processing flaring emissions under a single line item in
the production segment of natural gas systems. Using the revised approach, these flaring emissions
would be specifically calculated for natural gas production, petroleum production, and gas processing
(within the plant grouped emission sources). The shift in C02 emissions from Natural Gas systems to
Petroleum systems is also due to the inclusion of associated gas flaring as a specific line item under
Petroleum systems; this is the largest source of C02 emissions for the revisions under consideration.
5. Requests for Stakeholder Feedback
1.	EPA seeks stakeholder feedback on the general approach of using subpart W reported C02
emissions data to revise the current C02 emissions calculation methodology (described in
Section 1) in the GHGI.
2.	EPA seeks feedback on using consistent calculation methodologies for both CH4 and C02, when
GHGI relies on subpart W data. Are there sources where the CH4 and C02 methodologies based
on subpart W should differ?
3.	Section 3.1 discusses considerations for developing EFs and associated activity data for
miscellaneous production flaring that facilitate scaling reported subpart W data to a national
level. The EPA has presented a preliminary approach that develops an EF in units of emissions
per well. National active well counts would be paired with such EF to calculate emissions in the
GHGI. The EPA seeks feedback on this approach, or suggestions of other approaches that would
facilitate scaling to a national level and time series population.
4.	For sources discussed in this memo that do not currently estimate CH4 emissions using subpart
W, EPA is considering which year(s) of subpart W data to use in developing the C02 emissions
methodologies. For miscellaneous production flaring, the EPA reviewed reported emissions and
activity data for RY2011 - RY2014. However, wellhead counts for RY2011 - RY2014 are only
reported by those facilities that calculated equipment leak emissions using Methodology 1, and
as such, are not comprehensive. At the time of the 2016 Production memo, 83% of reporting
facilities for RY2011, 85% of RY2012 reporting facilities, 93% of RY2013 facilities, and 98% of
RY2014 reporting facilities reported wellhead counts under Methodology 1. In addition, facilities
only reported total wellheads and did not report gas and oil wellhead counts separately for
RY2011 - RY2014. The EPA calculated the C02 EFs under consideration using RY2015 only,
because well counts from all reporting facilities are reported. However, the EPA requests
feedback on whether it is appropriate to consider data from prior reporting years, which have
more uncertainty due to incomplete coverage, in order to show a trend over the time series.
Table 22 provides the reported subpart W emissions and activity data for RY2011-RY2015.
Table 22. GHGRP Subpart W Emissions and Activity Data for Miscellaneous Production
Flaring
Year
CO: Emissions
(mt)
# Flares
# Wells (a)
CO; EF
(kg/well)
2011
2,252,297
13,509
371,604
6,061
2012
3,616,326
16,356
398,137
9,083
2013
4,596,329
21,098
415,355
11,066
2014
4,841,116
22,155
502,391
9,636
2015
3,779,110
20,293
527,170
7,169
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a. Total gas and oil wellheads. Wellhead counts for RY2011 through RY2014 are
available from those onshore production facilities that calculated equipment leak
emissions using Methodology 1.
For transmission and storage segment flares, the EPA relies on RY2015 data for the revisions
under consideration, because all flaring emissions are reported under the flare stacks source.
Whereas, for RY2011 - RY2014, flare emissions are reported under flare stacks and each
individual emission source.
5. Section 3.4 discusses time series considerations for transmission and storage flares. The EPA is
considering applying a subpart W-based EF (kg/station) for all years of the time series. However,
few transmission and storage stations reported flares for RY2015 (see Table 16 through Table
19). Therefore, EPA might alternatively assume that flares did not operate in 1990 (i.e., an EF of
0), apply the subpart W-based EF for 2011 forward, and apply linear interpolation from 1991
through 2010. The EPA seeks feedback on these approaches, or suggestions of other approaches
to time series population.
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Appendix A - Current GHGI COz Emlssic :tors
All EFs are presented in the same units as the EFs under consideration; kg/[unit].
Natural Gas & Petroleum Production
Stripper Wells (for Associated Gas Venting)
2.47
kg/well
Condensate Tank Vents - Without Control Devices
0.18
kg/bbl
Condensate Tank Vents - With Control Devices
0.037
kg/bbl
Oil Tanks
0.18
kg/bbl
HF Gas Well Completions and Workovers
18,367a
kg/event
Pneumatic Controllers, all bleed types (Natural Gas)
144a
kg/controller
Low Bleed Pneumatic Controllers (Petroleum)
8.8
kg/controller
Intermittent Bleed Pneumatic Controllers (Petroleum)
83.9
kg/controller
High Bleed Pneumatic Controllers (Petroleum)
238.9
kg/controller
Pneumatic Pumps (Natural Gas)
168.4a
kg/pump
Pneumatic Pumps (Petroleum)
82.8
kg/pump
Liquids Unloading with Plunger Lifts
613a
kg/well
Liquids Unloading without Plunger Lifts
678a
kg/well
Onshore Production & Processing - Flaring Emissions
40,624
kg/well
Natural Gas Processing
Reciprocating compressors - before C02 removal
4,764
kg/compressor
Reciprocating compressors - after C02 removal
1,058
kg/compressor
Centrifugal compressors with wet seals - before C02 removal
21,859
kg/compressor
Centrifugal compressors with wet seals - after C02 removal
4,854
kg/compressor
Centrifugal compressors with dry seals - before C02 removal
10,719
kg/compressor
Centrifugal compressors with dry seals - after C02 removal
2,380
kg/compressor
Plant fugitives - before C02 removal
3,364
kg/plant
Plant fugitives - after C02 removal
747
kg/plant
Kimray pumps
859
kg/plant
Dehydrator vents
5,291
kg/plant
Plant Grouped Sources
95,303
kg/plant
AGR vents
35,394,396
kg/plant
Blowdowns and venting
8,363
kg/plant
Transmission
High Bleed Pneumatic Controllers
84.43
kg/controller
Intermittent Bleed Pneumatic Controllers
10.95
kg/controller
Low Bleed Pneumatic Controllers
6.22
kg/controller
Underground NG Storage
High Bleed Pneumatic Controllers
82.21
kg/controller
Intermittent Bleed Pneumatic Controllers
10.74
kg/controller
Low Bleed Pneumatic Controllers
6.34
kg/controller
a. Average EF based on data from all NEMS regions.
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