January 2017
Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2015:
Revisions Under Consideration for Natural Gas and Petroleum
Systems Production Emissions
This memo was posted and open for stakeholder feedback in January 2017. Many of the
updates discussed in the memos below were implemented in the 2017 Inventory. For
information on the revisions implemented in the 2017 Inventory, please see Inventory of
U.S. Greenhouse Gas Emissions and Sinks 1990-2015: Revisions to Natural Gas and
Petroleum Production Emissions, available at
https://www.epa.aov/ahaemissions/natural-aas-and-petroleum-svstems-aha-inventorv-
additional-in form a tion-1990-2015-aha.
This memo discusses updates under consideration for the natural gas and petroleum systems
production segments for the Inventory of U.S. Greenhouse Gas Emissions and Sinks (GHGI), including
potential updates using Greenhouse Gas Reporting Program data for condensate tanks, oil tanks,
stripper well venting, liquids unloading, and other sources, and use of the latest data from Drillinglnfo
for well counts. It also includes information on an update under consideration for episodic emissions
from gathering and boosting stations.
The EPA's Greenhouse Gas Reporting Program (GHGRP), subpart W, collects annual operating and
emissions data on sources including production storage tanks, associated gas venting and flaring, and
equipment that may leak (e.g., separators, heaters, dehydrators, and compressors) from onshore
natural gas and petroleum systems facilities who 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. Facilities 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 RY2015.1
This memorandum provides an overview of the current (2016) GHGI approach to estimate emissions
and activity from production tanks and oil well venting and flaring, and recommendations for revising
the approach to use subpart W data (see sections 1 through 4). This memorandum also examines new
GHGRP equipment count and well count data available for RY2015, along with the latest national well
count data, and presents options under consideration for updates to these activity data in the GHGI (see
sections 5 and 6). Then, this memorandum presents the current approach to estimate emissions and
activity for liquids unloading and options to update these data (see section 7). The memo discusses an
update under consideration for gathering and boosting stations (see section 8). Specific requests for
stakeholder feedback are solicited in section 9.
1. Current GHGI Methodology for Production Tanks and Oil Well
Venting and Flaring
The current GHGI methodology for tank emissions and oil well venting and flaring emissions is depicted
in Figure 1 below. The current GHGI calculates tank emissions from oil production by applying an oil tank
1 The GHGRP subpart W data used in the analyses discussed in this memorandum are those reported to the EPA as
of August 13, 2016.
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emission factor (EF) to 20% of stripper well production and 100% of non-stripper oil well production,
and applies a well venting EF (e.g., casinghead gas emissions) to the remainder of stripper well
production (80%). For gas production, the current GHGI estimates tank emissions by applying the
condensate tank EF to condensate production in each region, and well venting or flaring emissions are
not applicable. The specific methodologies for each are discussed in detail below.
Oil Production (GHGI Petroleum Systems)
Production from non-stripper oil wells

Production from oil stripper wells
Gas Production (GHGI Natural Gas Systems)
Lease condensate production

Crude Oil Storage Tanks
Venting: 7.39 scf/bbl
Flaring: 0.003 scf/bbl
9 9*00
0 0 0 0 0
Stripper Well Venting
Venting: 3.1 scf/bbl
Condensate Storage Tanks
Uncontrolled: 21.87-302.75 scf/bbl
Controlled: 4.37-60.55 scf/bbl
&
P
&
P
Figure 1. Current GHGI Calculation Methodology for Storage Tanks and Stripper Well Venting
The methane (CH4) EFs for both condensate and oil tanks are based on throughput (units of standard
cubic feet per barrel of production, scf/bbl). The current GHGI EFs were developed from default sample
runs available through E&P Tank2 (sometimes referred to as API TankCalc). These runs used data
sampled from tanks in various regions in the United States with hydrocarbon gravities from 17 to 64° API
and separator pressures and temperatures ranging from 4 to 870 psig and 40 to 180°F, respectively. The
EPA determined an uncontrolled methane emission rate and EF for each sample run
The EPA calculated the uncontrolled EF for condensate tanks by averaging the uncontrolled EFs from
tank sample runs that have hydrocarbon throughput with API gravity equal to or above 45. From this
data, the EPA then calculated a controlled condensate tank EF assuming 80% control efficiency.
Separately, measurement data were available for malfunctioning dump valve emissions in the
midcontinent and southwest NEMS regions; these data showed that measured tank emissions were
much higher than expected (e.g., when comparing to software emissions estimates) and the difference
was attributed to malfunctioning dump valves. For those regions, the condensate tank uncontrolled and
controlled EFs were adjusted to include the emissions from malfunctioning dump valves. The
malfunctioning dump valve factor was not applied to other NEMS regions.
2 API. April, 2000. API PUBL4697: Production Tank Emissions Model (E&P Tank).
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Similarly, the EPA calculated an uncontrolled EF for oil tanks by averaging the uncontrolled EFs from
tank sample runs that have hydrocarbon throughput with API gravity below 45. As was the case for
condensate tanks, limited regional data were available on malfunctioning dump valve emissions for oil
tanks. Petroleum emissions are not calculated at a regional level, and the emissions from malfunctioning
dump valves were incorporated into the oil tank EF for the United States. The EPA did not calculate a
separate EF for controlled oil tanks for the GHGI. However, the current GHGI does account for
combustion emissions from flares based on calculated oil tank emissions. Flared emissions from oil tanks
are calculated by multiplying the oil tank emissions by 2.2%, and then multiplying this volume by a CH4
EF of 20 scf per mcf of flared emissions. The flared emissions contribution is less than 0.05% of oil tank
emissions. Table 7 and Table 8 present the current GHGI EFs for oil and condensate tanks.
The 2016 GHGI estimates emissions for stripper well venting by applying a well venting EF to 80% of the
stripper well oil production, which is calculated based on the counts of stripper wells. The EPA
developed the stripper well venting EF with the following assumptions: the gas-to-oil ratio (GOR)
equaled five scf of gas per barrel of crude oil, a stripper well produces an average of 2.1 barrels per day,
and that 61.2% of the gas is CH4.3 This translated to CH4 emissions of 2,345 scfy per stripper well or 3.1
scf/bbl.
The associated activity data (throughput) for each emission source is unique to the source category: for
condensate tanks, the activity data are condensate production as reported by the Department of
Energy's Energy Information Administration (EIA), and for oil tanks and stripper well venting, the activity
data are based on crude oil production as reported by EIA, and stripper well counts and average stripper
well production from the Interstate Oil and Gas Compact Commission. The condensate production is
subdivided to account for condensate stored in controlled versus uncontrolled tanks; the current GHGI
methodology assumes that 50% of condensate throughput goes to controlled tanks and 50% goes to
uncontrolled tanks. Crude oil production is subdivided into production from non-stripper and stripper
wells. The oil tank activity data includes total crude oil production from all non-stripper wells and 20% of
the crude oil production from stripper wells, and the stripper well venting activity data includes the
remaining 80% of stripper well crude oil production.
The GHGI methodology described above accounts for the majority of emissions from condensate and oil
tanks in the production segment, whether located at well pad sites or natural gas gathering and
boosting (G&B) stations. The flashing loss component of a condensate tank EF developed by the
modeling described above is usually significant (compared to working and breathing losses), and drives
the order of magnitude of the EF. As such, it is important to note that flashing losses mainly occur during
the first transfer of pressurized field condensate to atmospheric conditions, which may happen at a well
pad or G&B station. As discussed in EPA's memorandum "Inventory of U.S. GHG Emissions and Sinks
1990-2014: Revision to Gathering and Boosting Station Emissions" (April 2016), revisions implemented
in the 2016 GHGI based on the 2015 Marchese et al. study introduced potential minor double counting
of some emissions from upstream tanks in natural gas systems since the new G&B facility-level EF
includes flashing losses from condensate tanks that receive pressurized field condensate, and such
losses were already accounted for by the nature of the existing GHGI methodology. These
considerations would be addressed in the updates under consideration and are discussed in the
requests for stakeholder feedback, in Section 8 below.
3ICF. October 1999. "Estimates of Methane Emissions from the U.S. Oil Industry."
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2. Available Subpart W Data for Production Tanks and Associated Gas
2.1 Production Tanks
Production storage tank data reported under subpart W are specific to onshore oil and gas production
operations, defined as "all equipment on a single well-pad or associated with a single well-pad." Subpart
W uses the term "production storage tanks" to refer to both condensate and oil tanks. However, certain
data reported at the sub-basin level can be used to classify production type as gas or oil (further
discussed below).
Production storage tank emission calculation and reporting requirements differ for tanks storing
hydrocarbon liquids from separators or wells with throughput greater than or equal to 10 barrels per
day (bbl/day) (herein referred to as large tanks) versus those tanks storing hydrocarbon liquids from
separators or wells with throughput less than 10 bbl/day (herein referred to as small tanks). The RY2015
subpart W data includes new data elements that were not reported in prior years (RY2011-2014). In
particular, the total number of tanks not on well pads (but associated with a single well-pad) were
included in the reported tank counts starting in RY2015. Note that emissions from all tanks, including
tanks that are not on well pads but are associated with a single well pad, were reported for all years
(RY2011-2015). Table 1 and Table 2 below summarize the relevant information available for large and
small production storage tanks for each reporting year and indicate whether the data are reported at a
basin-level or sub-basin level.
Table 1. Available Subpart W Data for Large Production Storage Tanks
Reporting
Year(s)
Throughput
(bbl/yr)
Tank Count
CH4 Emissions
Total
Vent to
Atmosphere
Flare
Control
Vapor
Recovery
Control
Venting
Tanks
Tanks with
Flaring
Tanks with
Vapor
Recovery
Malfunction
ing Dump
Valves (d)
2011-2014
Yes (a)
No (b)
No (b)
No (c)
No (c)
Yes
Yes
No
Yes
2015
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Reporting
Basis
Sub-Basin
Sub-Basin
Sub-Basin
Sub-Basin
Sub-Basin
Sub-Basin
Sub-Basin
Sub-Basin
Sub-Basin
a.	RY2014 reporting included data elements for RY2011-2013 that were previously deferred from reporting.
b.	The total count was reported for tanks on well pads, but not for tanks off well pads.
c.	For tanks not on well pads, a combined count of tanks that use a flare or vapor recovery were reported, but
the counts were not reported separately,
d. The total number of separators with malfunctioning dump valves is reported, but counts of tanks or wells
associated with the separators is not reported.
Table 2. Available Subpart W Data for Small Production Storage Tanks
Reporting
Year(s)
Throughput
(bbl/yr)
Tank Count
CH4 Emissions
Total
Vent to
Atmosphere
Flare
Control
Vapor
Recovery
Control
Venting
Tanks
Tanks with
Flaring
Tanks with
Vapor
Recovery
Malfunctioning
Dump Valves
2011-2014
Yes
No (a)
No
No
No
Yes
Yes
No
No
2015
Yes
Yes
No (b)
Yes
No (b)
No (b)
Yes
No (b)
No
Reporting
Basis
Basin
Sub-Basin
Sub-Basin
Sub-Basin
Sub-Basin
Sub-Basin
Sub-Basin
Sub-Basin
N/A
a.	The total count was reported for tanks on well pads, but not for tanks off well pads.
b.	The count of tanks that did not control emissions with flares is reported; this value comprises tanks that vent
directly to the atmosphere or use a vapor recovery system.
N/A- Not applicable
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Subpart W provides separate methodologies for reporters to calculate emissions from large and small
tanks. Emissions from large tanks in subpart W are calculated by applying one of two calculation
methodologies for RY2015. Reporters may use a software program, such as AspenTech HYSYS or API
E&P Tank, to calculate emissions or may assume that all CH4 in the liquid and gas is emitted from the
tank (based on applying certain assumptions for gas and liquid composition). Emissions from small tanks
in subpart W are calculated by multiplying a population EF by the number of separators or wells. The
small tank population EF was developed using GHGI condensate and oil tank EFs, coupled with an
average throughput of 2.2 bbl/day (based on GHGI stripper well data). The subpart W calculation
methodologies are summarized in Appendix A.
Section 3 presents analyses regarding how subpart W data might be used to revise the current GHGI
methodology for condensate and oil tanks and related sources for the 2017 GHGI. As discussed above,
RY2015 provides a level of granularity and several data elements that are not available in previous RYs.
The revisions under consideration for the 2017 GHGI may be developed using RY2015 data and applied
to previous years as appropriate.
2,2 Associated Gas
Associated gas venting or flaring is defined in subpart W as "the venting or flaring of natural gas which
originates at wellheads that also produce hydrocarbon liquids and occurs either in a discrete gaseous
phase at the wellhead or is released from the liquid hydrocarbon phase by separation. This does not
include venting or flaring resulting from activities that are reported elsewhere, including tank venting,
well completions, and well workovers." This generally refers to venting of gas from oil wells, when, for
example, a pipeline is not available to collect the gas for sales. Facilities calculate associated gas
emissions by determining the gas-to-oil ratio (GOR) for a well, and assuming that all gas is released
based on the liquid throughput. Facilities may also subtract the volume of associated gas that is sent to
sales from their estimate. Facilities report the number of wells that vent or flare associated gas, along
with the emissions from each activity. The data reported for RY2011-2015 are similar, except that data
are reported in more granularity for RY2015. Basin-level data are reported for RY2011-RY2014, while
sub-basin level data are reported starting in RY2015. Differences in the reporting-level do not affect the
analyses presented below, because data are currently evaluated at a national level. The subpart W
calculation methodologies are summarized in Appendix A.
The data collected under subpart W associated gas venting and flaring is most comparable to the
current GHGI methodology for "stripper well venting." A stripper well according to GHGI data sources is
defined as producing less than 10 barrels per day of oil, which is the same as the subpart W throughput
threshold definition for small tanks. However, associated gas data reported under subpart W may
include venting or flaring from non-stripper wells and/or stripper wells.
3, Revisions Under Consideration for Tanks
This section discusses two general options for calculating emission factors (EFs) and activity data (AD) for
the GHGI using subpart W data. To estimate GHGI emissions using subpart W data, activity factors (AFs)
can be developed and coupled with either national throughput or national wellhead count data to
generate national level AD, then combined with associated EFs. For the throughput basis option
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discussed in Section 3.1, national condensate and oil production data (e.g., obtained from EIA) would be
coupled with subpart W-based AFs (percent of total throughput for each tank category), then combined
with subpart W-based category-specific EFs (scf/bbl). This approach is similar to the current GHGI
methodology which is on a throughput basis. For the tank basis option discussed in Section 3.2, the
national gas and oil well counts (determined using Drillinglnfo) would be coupled with subpart W-based
AFs (number of tanks per wellhead for each tank category), then combined with subpart W-based
category-specific EFs (scf/tank). These options are discussed in greater detail in the following
subsections.
3.1 Throughput Basis Option
3.1.1 Activity Factor Development
To estimate national emissions, AD must be developed for each of the large and small tank categories.
The EPA conducted the following steps to calculate activity factors:
Step 1: Apportion the tanks data between gas and oil production using the subpart W formation type
that is part of the sub-basin ID. Data reported in sub-basins with high permeability gas, shale gas, coal
seam, or other tight reservoir rock formation types were assigned to gas production. Data reported in
sub-basins with the oil formation type were assigned to oil production.
Step 2: For each reporting facility/sub-basin combination, apportion the reported throughput data by
tank category (tanks that use a flare, a vapor recovery unit (VRU), or are uncontrolled). Note this step
assumes that throughput for each facility is equivalent for each tank within a sub-basin (for large tanks)
or basin (for small tanks), as throughput is only reported as a sub-basin total for large tanks or a basin
total for small tanks.
Step 3: Sum the reported subpart W throughput data for each tank category and divide by the total
reported subpart W tank throughput to calculate the percent of the total tank throughput that would be
used as AD for each tank category.
Table 3 and Table 4 present the reported RY2015 subpart W and 2016 GHGI year 2014 throughput for
each tank category, for condensate and oil tanks, respectively. Table 5 provides the resulting percent of
total tank throughput that is applicable to each tank category based on RY2015 subpart W data and
2016 GHGI year 2014 estimates.
Table 3. Subpart W RY2015 and 2016 GHGI Year 2014 Condensate Tank Throughput
(MMbbl) by Tank Category
Tank Category
Condensate Tank Throughput
Subpart W - Large
Tanks (a)
Subpart W - Small
Tanks (a)
Subpart W -
Total
GHGI
All Tanks
182 (100%)
54 (100%)
236 (100%)
277 (100%)
Tanks with Flaring
126 (69%)
18 (33%)
168 (71%)
139 (50%)
Tanks with VRU
24 (13%)
n/a
Tanks without Controls
32 (18%)
n/a
68 (29%)
139 (50%)
Tanks without Flares
n/a
36 (67%)
a. Based on RY2015 subpart W data.
n/a - Not applicable.
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Table 4. Subpart W RY2015 and 2016 GHGI Year 2014 Oil Tank Throughput (MMbbl) by Tank Category
Tank Category
Oil Tank Throughput
Subpart W - Large
Tanks (a)
Subpart W - Small
Tanks (a)
Subpart W -
Total
GHGI
All Tanks
1,249 (100%)
92 (100%)
1,340 (100%)
2,998 (100%)
Tanks with Flaring
743 (59%)
25 (28%)
1,039 (78%)
Tanks with VRU
270 (22%)
n/a
Tanks without Controls
235 (19%)
n/a
301 (22%)
Tanks without Flares
n/a
66 (72%)
a. Based on RY2015 subpart W data,
n/a - Not applicable.
Table 5. Overall Condensate and Oil Tank Throughput Allocation

Condensate Tank Throughput
Oil Tank Throughput
Tank Category
Subpart W
- Large
Tanks (a)
Subpart W
- Small
Tanks (a)
Subpart W
-Total (a)
2016
GHGI
Subpart W -
Large Tanks
(a)
Subpart W -
Small Tanks
(a)
Subpart W
-Total (a)
2016
GHGI
All Tanks
77%
23%
100%
100%
93%
7%
100%

Tanks with Flaring
53%
8%
71%
50%
55%
2%
78%

Tanks with VRU
10%
n/a
20%
n/a

Tanks without
Controls
14%
n/a
29% (b)
50%
18%
n/a
22%
100%
Tanks without
Flares
n/a
15%
n/a
5%

Malfunctioning
Dump Valves
(c)
n/a
(c)
n/a
(c)
n/a
(c)

a.	Based on RY2015 subpart W data.
b.	While the small tank category "tanks without flares" may include small tanks that use a VRU, for comparison
to the GHGI, this table assumes that this reported category of tanks is uncontrolled.
c.	The total throughput for large condensate tanks (i.e., 77% of throughput) and large oil tanks (i.e.,
93% of throughput) is applicable to malfunctioning dump valves due to the malfunctioning dump
valve EF methodology which applies an average per-tank EF to all large tanks (see the following
Large Tank EF Development section).
n/a - Not applicable.
Subpart W facilities report their total condensate and oil production in the "Facility Overview" reporting
section. In addition to condensate and oil production stored in tanks, this may include the production
that is not stored in tanks or is stored in tanks that are not applicable to onshore production.
Condensate and oil production are also not reported separately. The EPA assessed available data to
determine the total condensate and oil production from subpart W reporters that is appropriate for
scaling to the national level. We first applied the percent of condensate and oil production based on the
subpart W tank throughput data to the total subpart W production. However, the condensate
production exceeded the total condensate production from the 2016 GHGI, and therefore, this may
overestimate condensate production. Therefore, we set the total subpart W condensate production
equal to the total condensate production from the GHGI and calculated the total subpart W oil
production (see the column Modified Subpart W Total Production). The EPA then calculated the percent
of the total subpart W production that is applicable to tanks by dividing the subpart W tank throughput
by the modified subpart W total production data. Table 6 presents the condensate and oil production
data from subpart W and the GHGI, along with the calculated percent of production that is applicable to
tanks. Note that year 2014 data from the GHGI are used in this analysis; if the throughput-basis option is
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included in the 2017 GHGI, year 2015 data would be applied in this analysis (2015 data are not yet
available).
Table 6. Subpart W RY2015 and 2016 GHGI Year 2014 Condensate and Oil Production (MMbbl)
Parameter
Subpart W
Tank
Throughput
Subpart W Total
Production
2016 GHGI
(Year 2014)
Modified
Subpart W Total
Production
% of Total Subpart
W Throughput
Applicable to Tanks
Total
1,576
2,437
3,275
2,437
-
Condensate Production
236 (15%)
366 (15%) (a)
277 (8%)
277 (11%) (b)
85%
Oil Production
1,340 (85%)
2,072 (85%) (a)
2,998 (92%)
2,160 (89%) (c)
62%
a. Condensate and oil production were calculated by applying the subpart W tank throughput
percentages to the subpart W total production.
b.	Condensate production is set equal to the 2016 GHGI condensate production.
c.	Equals total production minus condensate production.
Under the throughput basis option, the EPA would develop national AD by applying the throughput
allocation data in Table 5 to the relevant condensate tank and oil tank throughput. The relevant
throughput would equal the condensate and oil production reported by EIA multiplied by the
appropriate percentage in the last column of Table 6.
The data that would be used in the tanks update under consideration is from subpart W onshore
production data, representing activities at well pad production sites and not G&B stations. This creates a
unique challenge for the throughput basis option, because the national throughput must be specific to
well pad production sites versus G&B stations as tank emissions from G&B stations are already included
in the G&B station emission factors. Please see the request for stakeholder feedback on this issue. As
discussed in Section 1 and EPA's memorandum "Inventory of U.S. GHG Emissions and Sinks 1990-2014:
Revision to Gathering and Boosting Station Emissions" (April 2016), the current GHGI methodology for
G&B stations accounts for CH4 losses from liquids that are routed directly to gathering segment tanks
(i.e., such condensate or oil volume does not result in significant well pad losses in the form of tank
emissions).
3.1.2 Large Tank EF Development
Using the subpart W large production storage tank data, as assigned to gas or oil production per Section
3.1.1 above, the EPA then conducted the following steps to calculate EFs:
Step 1: For each reporting facility/sub-basin combination, apportion the reported throughput data by
tank category (tanks that use a flare, a vapor recovery unit (VRU), or are uncontrolled). Note this step
assumes that throughput is equivalent for each tank within a sub-basin for a facility, as throughput is
only reported as a sub-basin total.
Step 2: Calculate EFs specific to gas and oil production by dividing the summed reported emissions by
summed throughput for each tank category.
Step 3: Calculate a separate malfunctioning dump valve EF by summing dump valve emissions and
dividing by the summed throughput. Note that the dump valve EF represents emissions from all large
tanks, regardless of reported tank category.
Table 7 shows the resulting EFs compared to the current GHGI EFs. Subpart W data allows the EPA to
calculate more granular EFs than are used in the current GHGI. The current GHGI also does not
distinguish between large and small tanks.
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Table 7. Throughput-based CH4 EFs (scf/bbl) for Large Tanks, By Tank Category

Condensate Tank EF
Oil TankEF
Tank Category
Subpart
2016
Subpart W
2016

W (a)
GHGI (b)
(a)
GHGI (b)
Tanks with Flaring
0.28
4.4 or
0.35

Tanks with VRU
0.21
60.6 (c)
0.47

Tanks without Controls
8.7
21.9 or
302.8 (c)
7.9
7.39
Malfunctioning Dump
Valves
0.016
(c)
0.15

Average for all Large Tanks
1.8(e)
56.3 (d)
2.0 (e)

a.	Based on RY2015 subpart W data.
b.	EFs are applied to all tanks without differentiating by size.
c.	The lower EF is applied to the North East, Rocky Mountain, West Coast, and Gulf
Coast NEMS regions. The higher EF, which includes malfunctioning dump valve
emissions, is applicable to the midcontinent and south west NEMS regions.
d.	Calculated as total emissions divided by throughput for year 2014.
e.	The subpart W average EF for "all tanks" equals the sum of total large tank
emissions divided by the total number of reported large tanks.
n/a - Not applicable.
3.1.3 Small Tank EF Development
Data for small production storage tanks reported under subpart W has certain limitations, compared to
large tanks (as shown in Table 2):
1.	Throughput data are reported at a basin level instead of the sub-basin level.
2.	Emissions are reported for only two categories: tanks with flares and without flares. Therefore,
the data for tanks without flares includes emissions from both uncontrolled tanks and tanks
equipped with a VRU. However, some activity data are available on VRUs, and based on analysis
of the data set, very few small tanks report controlling emissions with a VRU.
The EPA calculated EFs as the data allowed using the following steps:
Step 1: Assign the sub-basin level emissions and tank count data to either oil or gas production using the
same method discussed in section 3.1.1 above.
Step 2: For each reporting facility, apportion the reported throughput data by tank category (tanks that
do or do not use a flare). Note this step assumes that throughput is equivalent for each tank at a facility,
as throughput is only reported as a basin total.
Step 3: Calculate EFs specific to gas and oil production by dividing the summed reported emissions by
throughput for each tank category.
Table 8 shows the resulting EFs compared to the current GHGI EFs.
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Table 8. Throughput-based CH4 EFs (scf/bbl) for Small Tanks, By Tank Category
Tank Category
Condensate Tank EF
Oil TankEF
Subpart W
(a)
2016 GHGI
(b)
Subpart W
(a)
2016
GHGI (b)
Tanks with Flaring
0.34
4.4 or 60.6
(c)
0.09
7.39
Tanks without Flares
24.8
21.9 or
302.8 (c)
2.3
Average for all Small Tanks
16.6 (e)
56.3 (d)
1.7 (e)
a.	Based on RY2015 subpart W data.
b.	EFs are applied to all tanks without differentiating by size.
c.	The lower EF is applied to the North East, Rocky Mountain, West Coast, and Gulf
Coast NEMS regions. The higher EF is applicable to the Midcontinent and South
West NEMS regions.
d.	Calculated as total emissions divided by throughput for year 2014.
e.	The subpart W average EF for "all tanks" equals the sum of total small tank
emissions divided by the total reported condensate or oil throughput for small
tanks.
n/a - Not applicable.
3.1.4 Time Series Considerations
There are differences between the subpart W and current GHGI EFs and AFs presented in Table 5, Table
7, and Table 8. Of note, controlled subpart W condensate tanks (using a flare or VRU) and uncontrolled
subpart W condensate tanks have lower EFs compared to the current GHGI assumption for the natural
gas production segment (considering both large and small tanks). The GHGI controlled EF was calculated
by applying 80% control efficiency, whereas the subpart W data reflects a much higher control efficiency
of approximately 97%. A greater fraction of the condensate throughput is also stored in controlled tanks
based on subpart W data compared to the current GHGI data.
The current GHGI EF for oil tanks is similar to the subpart W EFs for large uncontrolled oil tanks and
small oil tanks without flares. However, the subpart W EFs for controlled large and small oil tanks are
lower than the current GHGI EF and these tanks compose a large percent of the population.
The emissions profile and the number of large tanks with controls is changing over the subpart W time
series, as presented in Table 9. The fraction of the condensate and oil throughput that is stored in
uncontrolled tanks is higher according to the current GHGI, as compared to subpart W data. Regulations
developed since the current GHGI AF and EF data were developed contribute to this increase in controls.
For example, a NESHAP for Oil and Natural Gas Production was promulgated in 1999 and an NSPS was
promulgated in 2012 that require control of emissions from certain tanks.
Table 9. Subpart W Large Tank Reported Emissions and Controls Information for RY2011-RY2015
RY
Flaring CH4
(mt C02e)
Venting CH4
(mt C02e) (a)
# Large Tanks
(b)
% of Large Tanks
w/Controls
2011
93,530
1,547,441
71,184
48%
2012
167,080
1,592,895
81,766
57%
2013
104,424
1,208,986
101,340
57%
2014
125,739
1,328,849
128,191
66%
2015
143,014
1,046,472
145,061
69%
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a.	Venting emissions include emissions from tanks that use a VRU.
b.	Does not include the count of tanks off well pads that are uncontrolled for RY2011-
RY2014 because these data are not reported.
The subpart W EFs and AFs are calculated on a category-specific basis that is more granular than the
current GHGI structure and data are not available to use such a granular structure in earlier years of the
time series. Therefore, the EPA might select a year to implement a transition between the two sets of
EFs and AFs; alternatively, the EPA might use the subpart W EFs across the entire time series and
establish new assumptions for AFs within each tank category for early years. The EPA is also considering
an option that maintains the current GHGI methodology to estimate tank emissions for 1992, and then
assumes a linear correlation between the 1992 and 2015 tank emissions for each year between. The EPA
may also apply the year-specific % of controlled tanks from subpart W for 2011-2015 (as reported for
tanks on well pads), and moving forward. The EPA requests stakeholder feedback on these options in
section 8. In future GHGIs, for years 2015 and forward, the EPA would be able to develop year-specific
EFs and AFs using subpart W data. Subpart W tanks data for future reporting years will also contain a
similar level of detail as RY2015, and as such, changes in the use of controls on tanks over time could be
reflected in the GHGI.
3.2 Tank Basis Option
3.2.1 Activity Factor Development
To use tank-based emission factors (scf/tank) in the GHGI, the EPA must develop national level tank
counts. To assess this option, similar to the approach used in the 2016 GHGI for other production
segment emission sources, the EPA developed AFs in units of tanks per wellhead using subpart W
equipment leak data. Subpart W reporting requirements for wellhead counts changed for RY2015
compared to previous years, and wellhead counts are now reported by all reporters, and by production
type (gas or oil). In prior reporting years, facilities reported total wellhead counts not differentiated by
production type, and they were only reported for one of multiple methodology options. The EPA's
activity factor methodology involved analysis and assumptions to allocate wellhead counts between
GHGI source categories.
The EPA summed the wellhead count data to obtain total gas wellheads (307,737) and oil wellheads
(219,433) for all subpart W reporters in RY2015; in addition to wells with tanks, this may include wells
that do not have tanks or that have tanks that are not applicable to onshore production (e.g., the tanks
are located at gathering and boosting sites). The EPA then divided the number of tanks in each category
by the total gas or oil wellhead values to calculate the number of condensate or oil tanks per gas or oil
wellhead. Table 10 and Table 11 provide the reported subpart W tank counts for each category. Table 12
summarizes the calculated AFs (number of tanks per wellhead).
Table 10. RY2015 Subpart W Condensate Tank Counts, By Tank Category
Tank Category
Condensate Tanks
Subpart W -
Large Tanks
Subpart W -
Small Tanks
Subpart W -
Total
All Tanks
27,094 (100%)
97,120 (100%)
124,214 (100%)
Tanks with Flaring
15,862 (59%)
15,715 (16%)
34,395 (28%)
Tanks with VRU
2,818 (10%)
n/a
Tanks without Controls
8,414 (31%)
n/a
89,819 (72%)
Tanks without Flares
n/a
81,405 (84%)
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n/a - Not applicable.
Table 11. RY2015 Subpart W Oil Tank Counts, By Tank Category
Tank Category
Oil Tanks
Subpart W -
Large Tanks
Subpart W -
Small Tanks
Subpart W -
Total
All Tanks
117,683 (100%)
46,535 (100%)
164,218 (100%)
Tanks with Flaring
69,590 (59%)
11,325 (24%)
92,693 (56%)
Tanks with VRU
11,778 (10%)
n/a
Tanks without Controls
36,315 (31%)
n/a
71,525 (44%)
Tanks without Flares
n/a
35,210 (76%)
n/a - Not applicable.
Table 12. Number of Tanks Per Wellhead, By Tank Category (a)
Tank Category
Condensate Tanks
Oil Tanks
Subpart W -
Large Tanks
Subpart W -
Small Tanks
Subpart W -
Large Tanks
Subpart W -
Small Tanks
Tanks with Flaring
0.052
0.051
0.32
0.052
Tanks with VRU
0.0092
n/a
0.054
n/a
Tanks without Controls
0.027
n/a
0.17
n/a
Tanks without Flares
n/a
0.26
n/a
0.16
All Tanks
0.088
0.316
0.54
0.21
0.404
0.75
a. Based on RY2015 subpart W data,
n/a - Not applicable.
The EPA analyzed emissions from malfunctioning dump valves in a different manner to develop an AF
(and EF) specific to separators with malfunctioning dump valves. The number of tanks associated with
the malfunctioning dump valves are not reported under subpart W, but the number of separators with
malfunctioning dump valves are. Here, the AF (and EF) are on a per-separator basis instead of a per-tank
basis. Note that malfunctioning dump valves are only reported under the subpart W methodology for
large tanks, so this estimate would not take into account any malfunctioning dump valve emissions at
small tanks. The total number of separators are reported with subpart W equipment leak data (counts
specific to gas and oil production are reported by each facility). The EPA summed the RY2015 subpart W
separator count data to obtain total separators at gas production sites (210,836) and total separators at
oil production sites (87,260) for all reporters. Table 13 presents the RY2015 subpart W data for
malfunctioning dump valves. The national total number of separators is already calculated in the GHGI,
and under this option, that value will be multiplied by the percent of separators with malfunctioning
dump valves to determine the total number of separators with malfunctioning dump valves for the
GHGI.
Table 13. RY2015 Subpart W Malfunctioning Dump Valve Data
Separators with Malfunctioning
Dump Valves
Condensate
Production
Oil
Production
Reported Count
137
1,243
Reported Percent of Total Separators
0.065%
1.4%
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While data are not available to determine the fraction of tanks that have separators with malfunctioning
dump valves, it is possible to develop an average emission factor for malfunctioning dump valves to be
applied to large tanks or all tanks (see next section).
3.2.2 Emission Factor Development
The EPA calculated EFs on a per-tank basis (scf/tank) and on a per-separator basis for malfunctioning
dump valves (scf/separator). The approach to calculating EFs is identical for large tanks and small tanks,
with the following steps:
Step 1: Assign reported sub-basin-level tank counts, separators with malfunctioning dump valve counts,
and emissions to gas or oil production using the methodology discussed in Section 3.1.1.
Step 2: Calculate EFs specific to each tank category (tanks with flaring, a VRU, and uncontrolled) by
dividing the summed emissions by the summed tank count.
Step 3: Calculate a malfunctioning dump valve EF by summing all reported dump valve emissions and
dividing by the total number of separators with malfunctioning dump valves.
Table 14 shows the resulting EFs for each tank category, and Table 15 presents the malfunctioning
separator dump valve EF.
Table 14. Tank-based CH4 EFs (scf/tank), By Tank Category (a)
Tank Category
Condensate Tanks
Oil Tanks
Subpart W EF
- Large Tanks
Subpart W EF
- Small Tanks
Subpart W EF
- Large Tanks
Subpart W EF
- Small Tanks
Tanks with Flaring
2,242
393
3,755
197
Tanks with VRU
1,774
n/a
10,854
n/a
Tanks without Controls
33,201
n/a
51,192
n/a
Tanks without Flares
n/a
10,951
n/a
4,236
Average for all Tanks (b)
11,915
9,242
20,739
3,253
a.	Based on RY2015 subpart W data.
b.	The average EF for "all tanks" equals the sum of total emissions divided by the total number of
reported tanks (calculated separately for large and small tanks).
Table 15. Malfunctioning Dump Valve EF (scf/separator with malfunctioning dump valves)
Category
Condensate
Production
Oil
Production
Malfunctioning Dump Valves
21,175
154,874
The malfunctioning dump valve EF may also be calculated in the same units as the other tank-based EFs
(scf/tank). Summing the malfunctioning dump valve emissions and dividing by the total number of large
tanks results in an average (to be applied to all applicable tanks (e.g. large tanks or all tanks))
malfunctioning dump valve CH4 EF of 107 scf/tank for condensate tanks and 1,636 scf/tank for oil tanks.
3.2.3 Time Series Considerations
The EPA is considering the following approach to estimate emissions over the time series. The EPA could
use the subpart W RY2015 EFs for all prior years in the GHGI. For large condensate and oil tanks, the EPA
could develop 1992 AFs by using the subpart W RY2015 AFs (number of tanks per wellhead) and
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applying the assumption that 50% of tanks are controlled, 50% of tanks are uncontrolled, and no tanks
use VRU (similarto the current GHGI approach) while maintaining the subpart W dump valve AF. The
subpart W AF for small condensate and small oil tanks would be maintained because most tanks are
currently uncontrolled in the subpart W data set (i.e., do not have flares). The large tank AF for each
year between 1992 and 2015 would be estimated with linear interpolation between the two years.
These assumptions would then be used along with the total number of gas and oil wells for each year to
estimate emissions. The EPA is also considering an option that maintains the current GHGI methodology
to estimate tank emissions for 1992, and then assumes a linear correlation between the 1992 and 2015
tank emissions for each year between. The EPA may also apply the year-specific % of controlled tanks
from subpart W (as reported for tanks on well pads) for 2011-2015, and moving forward. In future
GHGIs, the EPA would be able to develop year-specific EFs and AFs using subpart W data.
3.3 Activity Factor Comparison
A consideration when evaluating the throughput- and tank-based options are the differences in activity
factors. In particular, how the EPA uses the activity factors to scale up subpart W data to a national level
for each option. Table 16 presents throughput and well count data for RY2015 subpart W, the revised
2015 well counts (as discussed in section 6), and 2014 throughput from the 2016 GHGI for the
throughput and tank-based options, and calculates the percent of total throughput or well counts that
are reported under subpart W. Note that 2015 national throughput data are not yet available to put all
data on the same year 2015 basis, however, the relationship between subpart W RY2015 data and 2014
national throughput provides an approximate comparison.
Table 16. Overall Scale-up Factors based on Throughput or Tank Basis Options
Parameter
Condensate
Production
Oil Production
Throughput Basis Option
2014 National Throughput (MMbbl)
277
2,998
Production (MMbbl) Reported for
RY2015 under subpart W (a)
277
2,160
Percent of Total Reported under
subpart W (b)
100%
72%
Tank Basis Option
2015 National Well Count
440,496
607,559
Count of Wells Reported for RY2015
under subpart W
307,737
219,433
Percent of Total Reported under
subpart W
70%
36%
a.	Equals the Modified Subpart W Total Production in Table 6.
b.	Note that this is a comparison between the 2015 GHGRP data and the most recently
available national-level data (2014).
4. Revisions Under Consideration for Oil Well Associated Gas Venting
and Flaring Emissions
This section discusses options for calculating EFs and AFs for the 2017 GHGI using subpart W data for
associated gas venting and flaring. Although subpart W data do not cover all national activity and
emissions due to the reporting threshold, reported emissions from associated gas venting are
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approximately an order of magnitude higher than current GHGI estimates for stripper well venting;
stripper well venting is the emissions source category in the GHGI that best corresponds to the subpart
W category of associated gas venting and flaring. The current GHGI methodology does not directly
account for methane from venting or flaring of substantial associated gas volumes associated with
newer, high-producing oil wells that are likely captured in subpart W reporting—for example, shale oil
wells in the Bakken formation of North Dakota—so the subpart W data appear more consistent with
industry activities in recent years. The EPA is considering using subpart W data to update the GHGI.
Table 17 summarizes data collected under subpart W for associated gas venting and flaring.
Table 17. GHGRP Subpart W Data for Associated Gas Venting and Flaring
Year
Dataset Overview
Associated Gas Venting
Associated Gas Flaring
Total #
Reported
Wells
Total #
Reported Oil
Wells
# Venting
Wells
Venting CH4
Reported
Emissions
(MMT C02e)
# Flaring
Wells
Flaring CH4
Reported
Emissions
(MMT C02e)
2011
371,604
(a)
8,863
3.26
5,628
0.41
2012
398,052
(a)
8,554
2.87
7,259
0.62
2013
415,270
(a)
6,980
1.24
8,880
0.85
2014
502,391
(a)
7,264
0.62
12,189
1.03
2015
565,334
219,433
4,286
0.40
21,453
0.99
a. Only the count of total wells was reported for 2011-2014, not differentiated by gas and oil production.
Figure 2 below illustrates subpart W reported associated gas venting and flaring emissions during
RY2011-RY2015, along with stripper well venting emissions from the GHGI for 2011-2014.
2
1.8
220 - GULF COAST BASIN (LA TX)
360 - ANADARKO BASIN
395 - WILLISTON BASIN
1.6
•430- PERMIAN BASIN
1.4
OTHER BASINS
1.2
1
0.8
0.6
0.4
0.2
0
2011
2012
2013
2014
2015
Figure 3 and Figure 4 below illustrate associated gas venting and flaring emissions reported under
subpart W for RY2011-RY2015, for certain basins. The majority of emissions are attributed to activities
in the Gulf Coast, Anadarko, Williston, and Permian Basins.
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Subpart W Venting
Subpart W Flaring
GHGI Venting
2.00
1.50
0.00
2011
2012
2013
2014
2015
Figure 2. Subpart W Associated Gas Venting and Flaring Reported Emissions Compared to GHGI
Stripper Well Venting Emissions, Years 2011-2015
-•—220 - GULF COAST BASIN (LA TX)
¦*—360 - ANADARKO BASIN
-•—395 - WILLISTON BASIN
-*—430 - PERMIAN BASIN
-•—OTHER BASINS
0
2011
2012
2013
2014
2015
Figure 3. Subpart W Associated Gas Venting Reported Emissions, Years 2011-2015
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220 - GULF COAST BASIN (LA TX)
360 - ANADARKO BASIN
395 -WILLISTON BASIN
•430-PERMIAN BASIN
•OTHER BASINS
Figure 4. Subpart W Associated Gas Flaring Reported Emissions, Years 2011-2015
4.1 Associated Gas AF Development
Subpart W associated gas venting and flaring emissions, as presented in the preceding table and figures,
notably change from year-to-year. We are considering the development of AFs that allow this change to
be reflected in the GHGI. Two AFs were calculated to determine the number of wells that vent or flare
associated gas.
First, we developed the total number of wells that either vent or flare associated gas from subpart W
data. The EPA summed the well count data to obtain total oil wells for all subpart W reporters in
RY2015. RY2015 is the first year where all oil wells are reported by each reporter. In prior reporting
years, facilities reported total well counts not differentiated by production type (gas or oil), and they
were only reported for one of multiple methodology options. We then divided the total number of wells
that vented or flared associated gas for RY2015 by the total number of reported oil wells. Table 18
presents this information. While the percent of total oil wells that either vent or flare associated gas
may change from year-to-year, RY2015 is the only year with detailed data available to calculate such an
AF. This AF could be applied to all years with subpart W data (i.e., 2011-2015) and could be updated as
data from future reporting years becomes available.
Table 18. GHGRP Subpart W RY2015 Data for Oil Wells and Associated Gas Wells
Total Oil Wells
Total # Venting & Flaring Wells
% of Total that Vent or Flare
219,433
25,739
12%
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Second, we developed the percent of wells reporting associated gas that vent or flare using subpart W
data for RY2011 through RY2015. We divided the number of wells that vent or flare by the total number
of wells that vented or flared associated gas; see Table 19. This AF would allow the GHGI to reflect
ongoing trends in the data.
Table 19. GHGRP Subpart W Data and AF for Associated Gas Venting and Flaring
Year
Subpart W
Total # Venting
& Flaring Wells
Associated Gas Venting
Associated Gas Flaring
# Venting
Wells
% of Total that
Vent
# Flaring Wells
% of Total that
Flare
2011
14,491
8,863
61%
5,628
39%
2012
15,813
8,554
54%
7,259
46%
2013
15,860
6,980
44%
8,880
56%
2014
19,453
7,264
37%
12,189
63%
2015
25,739
4,286
17%
21,453
83%
4.2 Associated Gas EF Development
The EPA calculated associated gas venting and flaring EFs using subpart W data for RY2011 through
RY2015. We 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; see Table 20. Table 20 also presents
the current GHGI stripper well venting EF.
Table 20. GHGRP Subpart W Associated Gas Venting and Flaring CH4 EFs Compared to the GHGI
Stripper Well Venting EF (mscfy/well)
Year
Subpart W Venting EF
Subpart W Flaring EF
GHGI Venting EF
2011
765
151

2012
696
178

2013
369
198
2.35
2014
176
176

2015
193
95

4.3 Time Series Considerations
Populating the 2017 GHGI time series for associated gas venting and flaring with a revised methodology
based on subpart W data will present challenges. As illustrated above by Figure 2 and Figure 3, trends in
venting and flaring can vary significantly over time and by basin. In the GHGI years before subpart W
data are available, 1990 through 2010, there have likely been large fluctuations in national and basin
level venting and flaring, due to the dynamics of petroleum resource development.
To cover the time series in the 2017 GHGI for the revisions under consideration, a simplistic approach
would be to extrapolate from current GHGI estimates for 1992 base year emissions from stripper well
venting, to revised estimates in year 2011 that incorporate subpart W data for all associated gas venting
and flaring. This approach would not reflect fluctuations in national emissions over the time series.
Additionally, this approach might underestimate emissions in years before 2011 since the 1992 base
year estimate includes only emissions from stripper well venting.
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For years prior to 2011, the EPA is also considering other activity data and EF options that would not rely
on the current GHGI stripper well venting data. To determine activity data for years prior to 2011, the
EPA is considering applying the subpart W-based percent of total oil wells that vent or flare associated
gas from 2015 (12%) over the entire time series, assuming that all oil wells in the vent or flare category
(12%) vented associated gas in 1990, and interpolating the flaring percent (of the total wells that vent or
flare) between the 1990 (0%) and 2011 (39%) values. Alternatively, to reflect flaring occurring in earlier
years, the EPA is considering applying the 2011 split between venting and flaring of associated gas to all
prior years in the GHGI. To determine EFs for years prior to 2011, the EPA is considering applying the
2011 subpart W EFs or average associated gas venting and flaring EFs from subpart W (using 2011-2015
data).
In Section 8 below, the EPA seeks stakeholder feedback on potential approaches or data sources that
could be used to inform scale-up of reported subpart W data and to populate the time series for
associated gas venting and flaring. For example, it may be possible to reflect impacts of state
regulations in the time series.
5. Gas Well and Oil Well Counts
Current GHGI Data
The EPA revised the data source and methodology to estimate gas well and oil well counts for the 2015
GHGI, when Drillinglnfo was first used to determine gas well and oil well counts for each year. Prior to
the 2015 GHGI, well counts were determined from a variety of sources.4 The EPA continued to use
Drillinglnfo data forthe 2016 GHGI.
5,2 Well Counts Revision
In developing the latest gas and oil well counts for the 2017 GHGI, the EPA updated its methodology for
processing the Drillinglnfo dataset to take into account a recent revision to the Drillinglnfo dataset that
clarified information on certain well records. In the previous Drillinglnfo datasets, records for certain
individual wells in Texas had been assigned multiple different state well identification numbers over
time. These datasets include those used to calculate well counts in the 2015 and 2016 GHGI. The EPA's
data processing methodology for well counts (described in EPA's 2015 memo "Inventory of U.S.
Greenhouse Gas Emissions and Sinks 1990-2013: Revision to Well Counts Data," available at
https://www.epa.gov/sites/production/files/2015-12/documents/revision-data-source-well-counts-4-
10-2015.pdf) resulted in certain duplicate well records being counted as unique wells for the 2015 and
2016 GHGI.5 For the 2017 GHGI, the EPA has assessed the latest Drillinglnfo data, with the clarified
reporting of well identification numbers, and removed the duplicate records from the GHGI well counts.
The revision has a small impact on gas well counts and a larger impact on oil well counts. Table 21
presents the revised well counts that would be used in the 2017 GHGI and the 2016 GHGI well counts,
4 For more information, please see the memorandum, "Inventory of U.S. Greenhouse Gas Emissions and Sinks
1990-2013: Revision to Well Counts Data", available at https://www.epa.gov/sites/production/files/2015-
12/documents/revision-data-source-well-counts-4-10-2015.pdf.
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along with estimated well counts from EIA5,6 and World Oil.7,8 Note that gas well and oil well counts may
not match up between the datasets due to differing gas well and oil well definitions. For example, EIA
uses a lower GOR threshold for the split between oil and gas, which would lead to higher gas well counts
and lower oil well counts compared to the GHGI GOR threshold.
Table 21. Comparison of gas well and oil well counts for 2014 and 2015.
Well Type & Data Source
2014
2015
Gas Wells
2017 GHGI
452,870
440,496
2016 GHGI
456,140
N/A
EIA
565,951
555,364
World Oil
no data
502,987
Oil Wells
2017 GHGI
619,818
607,559
2016 GHGI
898,268
N/A
EIA
no data
470,000
World Oil
no data
594,436
Total Gas and Oil Wells
2017 GHGI
1,072,688
1,048,055
2016 GHGI
1,354,408
N/A
EIA
N/A
1,025,364
World Oil
N/A
1,097,423
6. Equipment Counts
6.1 Current GHGI Methodology and Available Subpart W Data
In the 2016 GHGI, the EPA revised the equipment counts per well used to estimate emissions for
onshore production equipment leaks. The updates used RY2014 GHGRP subpart W equipment count
and well count data reported under the equipment leaks. The GHGRP subpart W equipment leak
reporting includes data for wells, separators, meters/piping, compressors, in-line heaters, heater-
treaters, headers, and separators. In the RY2014 GHGRP dataset used in the 2016 GHGI, facilities
reported total equipment and well counts that were not differentiated by production type (i.e. oil versus
gas), and the counts were only reported for one of multiple methodology options. As a result, the EPA's
activity factor methodology required several assumptions to allocate the reported equipment counts
and well counts to natural gas (NG) vs. petroleum systems (Petro)) for the GHGI. The 2016 GHGI AF
revisions are documented in the memorandum, "Inventory of U.S. Greenhouse Gas Emissions and Sinks
1990-2014: Revisions to Natural Gas and Petroleum Production Emissions." The AFs applied in the 2016
GHGI are presented in Table 23 below.
5	EIA. October 2016. "Number of Producing Gas Wells." http://www.eia.gov/dnav/ng/ng_prod_wells_sl_a.htm
6	EIA. June 2016. "Stripper wells accounted for 10% of U.S. oil production in 2015."
http://www.eia.gov/todayinenergy/detail.php?id=26872
7	World Oil. February 2016. "Producing Gas Wells Hold Up Amid Commodities Rout."
http://www.worldoil.com/magazine/2016/february-2016/special-focus/producing-gas-wells-hold-up-amid-
commodities-rout
8	World Oil. February 2016. "Producing Oil Wells Tick Down as Price Begins to Hit."
http://www.worldoil.com/magazine/2016/february-2016/special-focus/producing-oil-wells-tick-down-as-price-
begins-to-hit
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Subpart W equipment leak reporting requirements changed for RY2015 compared to previous years,
and equipment counts and well counts are now provided by all reporters, and by production type (gas or
oil). The EPA has assessed the new subpart W data and is considering the development of updated AFs;
the more detailed equipment counts and well counts data in subpart W allow the EPA to more directly
develop AFs.
6.2 Revisions Under Consideration for Equipment Counts
The EPA evaluated the reported RY2015 subpart W equipment count data (available under the
equipment leaks category). Table 22 presents the reported equipment counts for RY2015, and compares
these data to RY2014 counts.
Table 22. Reported Subpart W Equipment Counts for RY2014 and RY2015

RY2014 Subpart W Count
RY2015 Subpart
Equipment Type
(Split by production type
W Count (for

for 2016 GHGI)
2017 GHGI)
Wells


Wells (NG)
223,192
307,737
Wells (Petro)
275,831
219,433
Separators


Separators (NG)
149,912
210,836
Separators (Petro)
119,479
87,260
Heaters (NG)
48,460
63,523
Dehydrators (NG)
8,380
8,195
Meters/piping (NG)
256,340
263,870
Compressors (NG)
23,740
24,090
Heater-treaters (Petro)
34,902
51,364
Headers (Petro)
44,880
52,872
The EPA calculated AFs for each equipment type by dividing the reported equipment count by the
number of reported gas or oil wells. Table 23 presents the calculated AFs for each equipment type based
on RY2015 subpart W data, as compared to the current GHGI.
Table 23. AF Calculation from Subpart W Data
Source Category & Major Equipment
2016 GHGI AF (Based
on Subpart W
RY2014 Data)
Subpart W
RY2015 Based
AF
NG: Separators/Well
0.67
0.69
NG: Dehydrators/Well
0.04
0.03
NG: Heaters/Well
0.22
0.21
NG: Meters/piping per well
1.15
0.86
NG: Compressors/Well
0.11
0.08
Petro: Separators/Well
0.43
0.40
Petro: Heater-treaters/Well
0.13
0.23
Petro: Headers/Well
0.16
0.24
The EPA's estimates of national equipment counts for 2014, after applying the AFs from Table 23, are
presented in Table 24.
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Table 24. Subpart W Production Segment Equipment Counts Applied to National Activity
Representation for Year 2014
Equipment / Source Category
2016 GHGI
2017 Update Using
RY2015 AF (a)
Separators


Separators (NG)
306,377
310,269
Separators (Petro)
389,094
246,478
Heaters (NG)
99,038
93,481
Dehydrators (NG)
17,126
12,060
Meters/piping (NG)
523,885
388,315
Compressors (NG)
48,518
35,451
Heater-treaters (Petro)
113,661
145,085
Headers (Petro)
146,156
149,344
a. Equipment counts are calculated using the revised national gas well (440,496) and
oil well (607,559) counts, as discussed in section 6.
In addition, the EPA will update the GHGI to use the latest GHGRP data on equipment counts for other
production sources that currently use GHGRP data, such as pneumatic controllers and pumps, using the
same approach as the 2016 GHGI. Well count data associated with these sources are not reported by
production type in 2015 (i.e. the same information for data relevant to the GHGI is available for 2015 as
for 2014 for these sources) so the method has not changed for these sources.
6.3 Time Series Considerations
For the revisions under consideration, the EPA is considering an approach over the time series similar to
that applied for the current GHGI and documented in "Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2014: Revisions to Natural Gas and Petroleum Production Emissions." The EPA would apply
the revised AFs developed from subpart W RY2015 data for 2011 and continuing forward, along with
total gas well and oil well counts specific to each year. We would then apply linear interpolation
between 1992 and 2011 to estimate equipment counts for each intermediate year. However, the EPA is
also considering an option where we would apply the revised subpart W AFs to 2015 and continuing
forward, and would then apply linear interpolation between 1992 and 2015 to estimate equipment
counts for each intermediate year.
Table 25. Reported Subpart W Equipment Counts for RY2011 - RY2015
Equipment / Source Category
RY11
RY12
RY13
RY14
RY15
Wells (NG & Petro)
371,604
398,052
415,270
502,391
527,170
Separators (NG & Petro)
201,642
221,669
234,482
270,144
298,096
Heaters (NG)
46,344
48,883
43,564
48,641
63,523
Dehydrators (NG)
8,030
9,547
7,965
8,401
8,195
Meters/piping (NG)
238,044
231,337
216,212
258,837
263,870
Compressors (NG)
22,034
20,655
20,912
23,299
24,090
Heater-treaters (Petro)
25,174
23,082
26,518
34,735
51,364
Headers (Petro)
32,767
29,678
31,843
45,368
52,872
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7. Liquids Unloading
7.1	Current GHGI Methodology and Available Subpart W Data
In the 2013 GHGI, data from a 2012 report published by the American Petroleum Institute (API) and
America's Natural Gas Alliance (ANGA) were incorporated to update estimates for liquids unloading,
after the EPA reviewed the data and compared it with preliminary subpart W data, which showed similar
emissions levels.9 The EPA developed regional activity factors and regional emission factors from the
API/ANGA report for gas well liquids unloading activities in natural gas systems.10 The EPA noted its
plans to revisit this estimate as additional subpart W data became available.
Liquids unloading data are reported under subpart W of the GHGRP, including the number of wells
vented, the number of unloading events, whether plunger lifts were used, and CH4 emissions. Well
counts are reported under the equipment leak reporting section of subpart W, and the 2015 reporting
year data distinguishes between oil and gas well counts, which improves the data available to develop
activity data for liquids unloading. The EPA has assessed the subpart W data and is considering the
development of revised EFs and AFs for the GHGI.
7.2	Revisions Under Consideration for Liquids Unloading
The EPA evaluated the reported RY2011-RY2015 subpart W liquids unloading data. Table 26 presents
the number of wells venting during liquids unloading (with and without plunger lifts) and their percent
of the total gas well population in GHGRP, and compares this to the 2016 GHGI. The percent of wells
that vent were determined from subpart W RY2015 data, because of the updated reporting
distinguishing between gas and oil wells.
Table 26. Subpart W and 2016 GHGI Liquids Unloading Activity Data
Data Source
YearorNEMS
Total # Gas
Wells
With Plunger Lifts
Without Plunger Lifts
# Wells
Vented
% of Wells
That Vented
# Wells
Vented
% of Wells That
Vented
Subpart W
2011
(a)
42,826

26,679

2012
(a)
34,136

25,262

2013
(a)
30,922

27,723

2014
(a)
26,859

23,068

2015
307,737
30,757
10.0%
20,886
6.8%
2016 GHGI
(data for 2014)
National Total/
Average
456,140
22,477
4.9%
37,912
8.3%
a. Only the count of total wells was reported for 2011-2014, not differentiated by gas and oil production.
9	API/ANGAA. September 2012. "Characterizing Pivotal Sources of Methane Emissions from Natural Gas
Production." http://www.api.Org/~/media/Files/News/2012/12-October/API-ANGA-Survey-Report.pdf
10	For more information, see the memo "Overview of Updates to the Natural Gas Sector Emissions Calculations for
the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011,"
https://www.epa.gov/ghgemissions/updates-2013-greenhouse-gas-inventory, and pages 3.68 to 3.69 of the 2013
GHGI, available at https://www.epa.gov/sites/production/files/2015-12/documents/us-ghg-inventory-2013-main-
text.pdf.
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The EPA calculated subpart W liquids unloading EFs for each year by summing the CH4 emissions and
dividing by the number of wells that vented for the categories for wells venting with plunger lifts and
wells venting without plunger lifts. The EPA then calculated an average EF by summing the emissions
reported in those categories for RY2011-RY2015 and dividing by the total number of wells that vented
during liquids unloading for RY2011-RY2015. Table 27 presents the calculated subpart W liquids
unloading EFs (with and without plunger lifts) and compares this to the 2016 GHGI.
The 2016 GHGI applies regional emission factors developed from API/ANGA for liquids unloading. The
API/ANGA data showed large regional differences in average emissions. For certain regions these EFs
are much higher than average national emissions. For example, the Rocky Mountain EF in the 2016 GHGI
is 2,002,960 scfy CH4/well for wells without plunger lifts and the Mid-Continent EF is 1,137,406 scfy CH-
4/well for wells with plunger lifts. These EFs, particularly the Rocky Mountain EF for wells without
plunger lifts, result in high emissions over the time series. The EPA reviewed the subpart W data to
determine if similar differences between regions were present. The subpart W EFs for five of the six
regions were all within a similar range of each other; this includes the Rocky Mountain and Mid-
Continent regions. The subpart W liquids unloading average emissions for wells with plunger lifts in the
West Coast region were higher than other regions. However, few liquids unloading events were
reported in the West Coast region and, therefore, this data would have minimal impact on the national
level EF and emissions calculated with this data.
Table 27. Subpart W and 2016 GHGI Liquids Unloading CH4 Average Emissions per Well (scfy CH4/well)
Data Source
YearorNEMS
With Plunger
Lifts
Without
Plunger Lifts
Subpart W
2011
205,387
149,023
2012
166,144
133,689
2013
162,485
160,865
2014
104,863
194,842
2015
74,236
168,647
Average
148,589
160,411
2016 GHGI (for 2014) (a)
Average
200,791
260,030
a. The 2016 GHGI is calculated on a regional basis. Regional emission factors range from
2,856 to 1,127,406 scfy CFU/well for wells with plunger lifts, and 77,891 to 2,002,960
scfy CH4/well for wells without plunger lifts.
7.3 Time Series Considerations
Calculating the full 1990-2015 time series for liquids unloading requires an estimate of the percent of
wells conducting liquids unloading and the technologies used for unloading over that time period. The
current GHGI used the total percentage of wells conducting liquids unloading in the API/ANGA study
(56%) for each year of the time series. The total percentage was developed by summing the percent of
wells that vent without plunger lifts, wells that vent with plunger lifts, and wells that use lift
technologies without venting. In the current GHGI, for years 2010 and later, the percent of wells in each
category as presented in the API/ANGA survey is applied. The current GHGI assumes that in 1990 all
wells conducting liquids unloading (56% of wells) vented without plungers. Interpolation between the
1990 data point and the API/ANGA percentages was then applied to develop estimates from 1990-2009.
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For the activity data revisions under consideration, the EPA is considering multiple options to determine
activity over the GHGI time series. The EPA could use the subpart W RY2015 AF for the percent of total
wells that vent during liquids unloading with and without plunger lifts, 16.8%, shown in Table 26 to
calculate activity data for 2015, and potentially 2011-2014 as well. The EPA could then apply the year-
specific fraction of wells that vent with plunger lifts (varies from 53-62%) and wells that vent without
plunger lifts (varies from 38-47%) for 2011-2015. The EPA could also retain the total percent of wells
requiring liquids unloading (56%) from the API/ANGA report (this information is not available in subpart
W) throughout the time series. Using the same approach as in the current GHGI, the EPA could assume
that in 1990, all wells conducting liquids unloading vent without plunger lifts (and that no wells vent
with plunger lifts or use non-emitting technologies). The EPA could then use linear interpolation from
the 1990 data points to the 2011 or 2015 data points (10% vent with plunger lifts, 6.8% vent without
plunger lifts, and 39% conduct liquids unloading without venting). For the EF revisions under
consideration, the EPA is considering applying the average subpart W EFs to each year of the GHGI time
series.
8. Gathering and Boosting (G&B) Station Episodic Events
As part of the 2016 GHGI revisions, by using the GHGRP onshore production data, the scope of activity
data for various production segment equipment fugitive sources—including heaters, separators,
dehydrators, and compressors—was revised to reflect activities only at well pads, and not equipment at
G&B stations (equipment at G&B stations were for the most part included in the updated G&B station
category). These activity data revisions impacted the calculated activity data for certain emission
sources in the "Blowdowns" category (vessel blowdowns, compressor blowdowns, and compressor
starts) which were not included in the G&B station estimate. The GHGI emission calculations for these
three blowdown sources directly rely on equipment counts; so as the equipment count methodology
was revised in the 2016 GHGI to reflect only well pad activities, emissions from these three blowdown
sources in the 2016 GHGI reflect only well pad activities, and do not account for activities at G&B
facilities. This impact was not identified in the supporting memoranda for the 2016 GHGI revisions.
The EPA revisited the current data sources and methodology to assess whether available data could
supplement current estimates to account for blowdown sources at G&B facilities. The 2015 Marchese
study, which the EPA used to develop the 2016 GHGI station-level emission factor, excluded episodic
events. The Marchese study did however estimate the impact of episodic emission events on G&B
facility model predictions using a separate Monte Carlo model. Episodic emissions events included in
their estimate included blowdowns of pressurized equipment, compressor engine starts utilizing gas-
pneumatic starters, pig launch and receive operations, and similar events. The Marchese analysis
resulted in CH4 emissions of 37 MT per G&B station. The Marchese study notes that their national
emission estimate for these sources is higher than the existing GHGI estimate for such sources in the
production segment, and that excluding these episodic G&B sources would most likely result in an
incomplete national emission estimate for G&B stations.
EPA is considering adding the emission source "G&B station episodic events" under the existing
"Blowdowns" category in the natural gas systems production segment to account for these emissions
from G&B stations. For consistency with G&B station-level emissions already presented in the 2016
GHGI, the 2012 emission factor would be applied to all time series years. See Table 28 below.
Table 28. G&B Station Episodic Event CH4 Emission Estimates with Update Under Consideration
Parameter
1990
1995
2000
2005
2010
2014
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Station Count
2,565
2,732
2,843
2,968
3,838
4,999
Emissions from Episodic Events
(mt cm)
94,905
101,084
105,191
109,816
142,006
184,963
Beginning in 2017, GHGRP subpart W data will be available for G&B facilities subject to reporting,
including calculated blowdown emissions from equipment with a physical volume of at least 50 cubic
feet. These data might be used in the 2018 GHGI to validate or replace Marchese estimates of episodic
event emissions at G&B stations.
Requests for Stakeholder Feedback
Tanks
1.	The EPA seeks feedback on the throughput-based and tank-based subpart W EF and AF data
approaches and the potential benefits and challenges of each approach.
2.	The EPA seeks stakeholder feedback on assumptions applied to determine the split between
condensate and oil production within the subpart W data for the throughput basis. Are other
options available to distinguish between condensate and oil production?
3.	The EPA requests stakeholder feedback on how to determine the appropriate national
condensate and oil tank throughput data for the throughput option to ensure that the
calculated national emissions for this source accurately reflect storage tank emissions at well
pad production sites (and not at gathering and boosting stations which are calculated
separately). Alternatively, the EPA requests feedback on if the differences between the total
subpart W production and the total subpart W tank throughput are partially due to G&B tanks
not reporting, and thus the issue is ultimately resolved by the subpart W data itself.
4.	For the throughput basis option, the EPA seeks feedback on the appropriate data source to use
for national condensate and oil production. EIA production data are currently used, however,
other sources, such as Drillinglnfo, are also available. Drillinglnfo is used to determine well
counts, and using the same data source could create better consistency in the GHGI.
5.	The EPA seeks feedback on how to best estimate emissions over the GHGI time series using a
throughput-based approach.
6.	The EPA seeks stakeholder feedback on developing activity data over the GHGI time series for
the tank basis option.
7.	Subpart W includes reporting of malfunctioning dump valves from large tanks but not from
small tanks. The EPA seeks stakeholder feedback on malfunction rates and emissions from small
tanks, including whether small tanks are more or less likely to have malfunctioning dump valves,
and whether it may be appropriate to apply the EFs and AD assumptions from large tanks to
small tanks.
8.	Recent studies have observed (but not quantified) very high emissions from tanks. However,
GHGRP data is showing lower, not higher emissions than the GHGI. The EPA seeks stakeholder
feedback on this apparent discrepancy.
Associated Gas Venting and Flaring
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9.	The EPA seeks stakeholder input on the use of subpart W data for associated gas venting and
flaring and on approaches for scaling subpart W data to national representation for use in the
GHGI.
10.	The EPA seeks stakeholder input on approaches for populating the GHGI time series using
subpart W data for associated gas venting and flaring. Are there specific factors that may lead to
higher or lower levels of venting and flaring in certain years?
Well Counts
11.	The EPA seeks stakeholder feedback on other available national data sets for well counts for
direct use in the GHGI or for validation of GHGI well counts.
12.	The EPA seeks feedback on whether and how to distinguish between stripper and non-stripper
oil wells in applying the subpart W data.
Equipment Counts
13.	The EPA seeks stakeholder input on which years to apply RY2015 data for estimating emissions.
For example, the revised subpart W AFs based on RY2015 could be applied to 2011 and on (with
interpolation from previous data point up to 2010), or for 2015 and on (with interpolation from
previous data point up to 2014). As shown in Table 25, in relation to the increasing wells counts
for each year, certain equipment counts are generally similar over the time series but other
equipment counts are dissimilar over the time series. Are there certain sources for which
subpart W data should be applied on a year-specific basis? The EPA is requesting feedback on
which approach is most appropriate to estimate emissions over the time series.
Liquids Unloading
14.	The EPA seeks stakeholder feedback on approaches for calculating liquids unloading emissions
and activity using subpart W data, including:
•	Use of national versus regional emission factors and activity factors
•	Use of all reporting years (as an average or for year-specific factors) versus only RY2015 for
emissions and or activity data
15.	The EPA seeks stakeholder feedback on data sources for emission factors for liquids unloading
including GHGRP and Allen et al.11
16.	The EPA seeks feedback on options to determine activity data over the GHGI time series.
Subpart W AFs could be applied to each year of the time series, or the current approach could
be retained to some extent for 1990-2010.
17.	The current GHGI approach assumes that the fraction of wells requiring liquids loading (56%)
remains constant over the time series and that only the fraction of wells in different categories
of unloading approaches (venting without plunger lifts, venting with plunger lifts, use of non-
emitting approaches) varies. The EPA seeks feedback on whether the fraction of wells with
liquids loading problems may change over time and if so how. Are other data sources available?
11 https://www.epa.gov/sites/production/files/2015-12/documents/ng-inv-improvement-liquids-unloading-4-10-
2015.pdf
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Gathering and Boosting Station Episodic Events
18. The EPA seeks stakeholder feedback on approaches for addressing this emission source in the
2017 GHGI including implementing a revision to include gathering and boosting station episodic
events based on Marchese et al. estimates and/or review and potentially include GHGRP
subpart W data for gathering and boosting facilities when available in late 2017.
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Appendix A. Measurement Methodologies for Emission Factor Updates under
Consideration
Emission Source
Measurement or Calculation
Type
# Sources
Location &
Representativeness
GHGRP Subpart W (RY2015)
Production Storage
Tanks:
-Large (>10 bbl/ day)
-Small (<10 bbl/day)
Large Tanks (facilities have
multiple options to calculate
emissions):
1.	Use software (e.g., AspenTech
HYSYS or API 4697 E&P Tank) to
calculate emissions
2.	Assume all CFU and CO2 at
separator conditions is emitted
3.	Determine composition of
produced oil and gas and assume
all Cm and CO2 is emitted
Small Tanks: Count the number of
wells (sending oil or condensate
direct to tanks) or separators with
throughput <10 bbl/day and apply
a population EF
For both large and small tanks: If
applicable, emissions are adjusted
downward by applying a flare
control efficiency of 98% or by
estimating the magnitude of
emissions recovered using a vapor
recovery system.
-2015 emissions data were
available for 144,777 large tanks, of
which we assigned 117,683 to oil
production and 27,094 to gas
production. Software was used to
calculate emissions for 118,793
large tanks.
-2015 emissions data were
available for 143,655 small tanks,
of which we assigned 46,535 to oil
production and 97,120 to gas
production.
-Tanks were assigned to oil and
gas production using the formation
type in sub-basin IDs.
Onshore production
facilities were
spread across the
United States, but
must exceed 25,000
mt CC>2e threshold
to report.
Associated Gas
Venting and Flaring
Facilities determine the gas-to-oil
ratio (GOR) for each well and
assume that all gas is emitted,
based on the liquid throughput.
Facilities also subtract the volume
of associated gas that is sent to
sales. If associated gas is flared,
the emissions are then adjusted
by applying a flare control
efficiency of 98%.
2015 emissions data were available
for 25,739 wells, of which 21,453
were controlled with a flare and
the remaining 4,286 vented directly
to the atmosphere.
Liquids Unloading
Facilities have 3 methods to select
from:
1. Measure flow rate of gas
vented during liquids unloading
along with duration (hours) of
liquids unloading events for each
well group (if the gas flow rate
during liquids unloading is
measured for at least one
unloading event for a unique well
tubing diameter group and
pressure group combination in a
sub-basin category)
2015 emissions were available for
30,757 wells with plunger lifts and
20,886 wells without plunger lifts.
Facilities applied an equation to
calculate emissions (methodology 2
or 3) for 49,121 wells (with and
without plunger lifts).
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2.	For wells without plunger lift
assist: Apply equation that uses
well depth, casing diameter, shut-
in pressure, and the average gas
flow rate to calculate emissions
3.	For wells with plunger lift assist:
Apply equation that uses well
depth, tubing diameter, shut-in
pressure, and the average gas
flow rate to calculate emissions


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