Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2015: Revisions to Natural Gas and Petroleum Systems Production Emissions April 2017

April 2017
Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2015:
Revisions to Natural Gas and Petroleum Systems Production
Emissions
This memo describes revisions to emission sources in the natural gas and petroleum systems production
segments for the 2017 Inventory of U.S. Greenhouse Gas Emissions and Sinks (GHGI), including revisions
to condensate tanks, oil tanks, and oil well associated gas (sections 1-4), well counts (section 5),
equipment counts (section 6), liquids unloading (section 7), and gathering and boosting (G&B) station
episodic events (section 8).
Many of the updates described in this memo use data from the EPA's Greenhouse Gas Reporting
Program (GHGRP). Subpart W of the GHGRP 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
t. Previous GHGI Methodology for Production Tanks and Oil Well
Venting and Flaring
The previous (2016 and earlier) GHGI methodology for tank emissions and oil well venting and flaring
emissions is depicted in Figure 1 below. The previous GHGI calculated tank emissions from oil
production by applying an oil tank emission factor (EF) to 20% of stripper well production and 100% of
non-stripper oil well production, and applied a well venting EF (e.g., casinghead gas emissions) to the
remainder of stripper well production (80%). For gas production, the previous GHGI methodology
estimated 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.
The methane (CH4) EFs for both condensate and oil tanks were based on throughput (units of standard
cubic feet per barrel of production, scf/bbl). These previous GHGI CH4 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.
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.
2 API. April, 2000. API PUBL4697: Production Tank Emissions Model (E&P Tank).
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------- April 2017 Production from non-stripper oil wells ££ inn- Production from oil stripper wells Lease condensate production I —fiA &q I 1 r U".'000 I Crude Oil Storage Tanks Venting: 7.39 scf/bbl Flaring: 0.003 scf/hbl

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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) in previous GHGIs for each emission source were unique to the
source category: for condensate tanks, the activity data were condensate production as reported by the
Department of Energy's Energy Information Administration (El A), and for oil tanks and stripper well
venting, the activity data were 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 was subdivided to account for condensate stored in controlled versus
uncontrolled tanks; the previous GHGI methodology assumes that 50% of condensate throughput goes
to controlled tanks and 50% goes to uncontrolled tanks. Crude oil production was subdivided into
production from non-stripper and stripper wells. The oil tank activity data included 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 included the remaining 80% of stripper well crude oil production.
The previous 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 were addressed with the final 2017 GHGI revisions.
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
3ICF. October 1999. "Estimates of Methane Emissions from the U.S. Oil Industry."
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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
CH.i 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
CHi 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
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 used in the development of the 2017 GHGI methodology for condensate and
oil tanks and related sources. As discussed above, RY2015 provides a level of granularity and several
data elements that are not available in previous RYs. The revisions considered for the 2017 GHGI were
therefore generally developed using RY2015 data to apply to previous years.
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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
previous 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, 2017 Revisions to Production Segment Tank Emissions
Based on stakeholder feedback, EPA implemented a throughput-based approach to calculate tank
emissions in the final 2017 GHGI. National condensate and oil production data (obtained from EIA) were
coupled with subpart W-based AFs (percent of production sent to tanks, and percent of total throughput
sent to each tank category), then combined with subpart W-based tank category-specific EFs (scf/bbl).
This approach is similar to the previous GHGI methodology which is on a throughput basis. The tank
basis option which was considered but not implemented in the final 2017 GHGI is discussed in Appendix
B of this memo.
Activity Factor Development
Activity factors were developed for each of the large and small tank categories in subpart W. The EPA
conducted the following steps to calculate activity factors:
Step 1: Apportion the reported tank throughput and tank count 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. The result of this step is total throughput and tank counts for the categories of large
condensate tanks, small condensate tanks, large oil tanks, and small oil tanks.
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), using the
number of tanks reported in each category and assuming that throughput for each facility is equivalent
for each tank within a sub-basin (for large tanks) or basin (for small tanks). Throughput is not reported at
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the same level of detail as tank counts. It 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.
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
1,250 (100%)
92 (100%)
1,340 (100%)
2,998 (100%)
Tanks with Flaring
744 (59%)
25 (28%)
1,039 (78%)
Tanks with VRU
270 (22%)
n/a
Tanks without Controls
236 (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
Tank Category
Condensate Tank Throughput
Oil Tank Throughput
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%
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%
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.
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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 a throughput-based EF to all large tank throughput (see the
following Large Tank EF Development section).
n/a - Not applicable.
To scale the subpart W-based estimates to the national level using the throughput-based approach, an
estimate of the fraction of oil production and the fraction of condensate production that is sent to tanks
in subpart W is needed, so that they may be applied to national oil production and national condensate
production. The estimates of 2015 subpart W condensate and oil production sent to tanks, 236 MMbbl
and 1,342 MMbbl respectively were developed as described in Step 1 above. Subpart W facilities report
their total liquids production (condensate and oil production). Total liquids production reported in 2015
was 2,437 MMbbl. 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.
Data are unavailable in subpart W to develop separate estimates of total condensate production or total
oil production. The EPA considered several approaches to develop oil- and condensate-specific fractions
of total liquids production sent to tanks.
EPA first considered applying the total percent of liquids production sent to tanks from subpart W to
both condensate and oil calculations. In this case, the 1,578 MMbbl of subpart W tank throughput
(including condensate and oil) was divided by the total subpart W reported liquids production (2,437
MMbbl) to obtain a value of 65%. However, applying the 65% value to national condensate production
results in a national condensate tank throughput value less than that reported under subpart W.
EPA then compared the total condensate tank throughput reported in subpart W (236 MMbbl) to
national condensate production (297 MMbbl), to consider the results if it were assumed that all
condensate production nationally is reported to subpart W. This results in a calculated value of 79% of
condensate production sent to tanks. Assigning the remaining subpart W-reported liquids production
(2,437-297=2,140 MMbbl) as oil results in 63% of oil production sent to tanks. At the other end of the
range, it could instead be assumed that all condensate production in subpart W is sent to tanks (100%).
Assigning the remaining subpart W liquids production to oil tanks (2,437-236= 2,201 MMbbl) results in
an estimate of 61% of subpart W oil production sent to tanks.
For the final 2017 GHGI, the EPA used the calculated values of 79% of condensate production sent to
tanks, and 63% of oil production sent to tanks. Table 6 presents the condensate and oil production data
from subpart W and national data from EIA, along with the calculated activity factors representing the
percent of condensate and oil production assumed to be sent to tanks.
Table 6. Subpart W RY2015 and National Condensate and Oil Production (MMbbl)

Subpart W
Subpart W Total Production

% of Throughput
Sent to Tanks
Parameter
Tank
(and estimated condensate
EIA Year 2015

Throughput
and oil production)

Total
1,578
2,437
3,739
-
Condensate Production
236
297
297
79%
Oil Production
1,342
2,140
3,442
63%
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The EPA developed national AD by applying the throughput allocation data in Table 5 to national
throughput calculated as the condensate and oil production reported by EIA multiplied by the
appropriate percentage in the last column of Table 6.
The data used in the tanks revision (subpart W onshore production data) includes activities and
equipment at well pad production sites and not at G&B stations. As discussed in Section 1, the 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). The 2017 GHGI methodology for well pad production site tanks, by including an
activity factor that takes into account the fraction of the national liquids production that is managed
directly by such tanks, avoids double counting of tank emissions when considered collectively with
gathering station tanks.
3,2 Large Tank EF Development
Using the subpart W large production storage tank data, as assigned to gas or oil production and the
appropriate control categories per Section 3.1 above, the EPA then calculated EFs specific to gas and oil
production by dividing the summed reported emissions by summed throughput for each tank category.
EPA also calculated 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 (used for the 2017 GHGI) compared to the 2016 GHGI EFs. Subpart W
data allows the EPA to calculate more granular EFs than are used in the 2016 GHGI. The previous GHGI
also did not distinguish between large and small tanks.
Table 7. Throughput-based CH4 EFs (scf/bbl) for Large Tanks, By Tank Category
Tank Category
Condensate Tank EF
Oil Tank EF
2017 GHGI (a)
2016
GHGI (b)
2017 GHGI (a)
2016
GHGI (b)
Tanks with Flaring
0.28
4.4 or
60.6 (c)
0.35
7.39
Tanks with VRU
0.21
0.47
Tanks without Controls
8.7
21.9 or
302.8 (c)
7.9
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.
3,3 Small Tank EF Development
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The EPA calculated EFs specific to gas and oil production by dividing the summed reported emissions by
throughput for each tank category. For small tanks, emissions are reported for only two categories:
tanks with flares and without flares. 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.
Table 8 shows the resulting EFs used in the 2017 GHGI compared to the 2016 GHGI EFs.
Table 8. Throughput-based CH4 EFs (scf/bbl) for Small Tanks, By Tank Category
Tank Category
Condensate Tank EF
Oil Tank EF
2017 GHGI (a)
2016 GHGI (b)
2017 GHGI (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.
3,4 Time Series Considerations
There are differences between the subpart W and previous 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 previous GHGI assumption
for the natural gas production segment (considering both large and small tanks). The previous 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 previous GHGI data.
The previous 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 previous 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 previous 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 and both 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 CO;e)
Venting CH4
(mt CO;e) (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%
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RY
Flaring CH4
(mt CO;e)
Venting CH4
(mt CO;e) (a)
# Large Tanks
(b)
% of Large Tanks
w/Controls
2014
125,739
1,328,849
128,191
66%
2015
143,014
1,046,472
145,061
69%
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.
The EPA revised the GHGI time series (1990-2015) to create consistency between estimates in early and
more recent years.
For condensate tank emissions in the 2017 GHGI, the fraction of condensate production sent to tanks
(79%) was held constant throughout the 1990-2015 time series. The percentages of condensate
production sent to tanks that was sent to large tanks (77.1%) and small tanks (22.9%) were also held
constant throughout the 1990-2015 time series. The 2015 fraction of throughput in each 2015 control
category was applied to for the years 2011 to 2015. For large tanks, it was assumed that in 1990, 50% of
condensate to large tanks went to tanks without controls, 50% went to tanks with flares, and that 0%
went to tanks with VRUs. The previous GHGI applied an assumption that 50% of condensate went to
uncontrolled tanks and 50% to controlled tanks (VRU or flares). For small tanks, it was assumed that in
1990 all throughput was sent to tanks in the uncontrolled category. This assumption was applied
because of the relatively limited use of controls at small tanks in the 2015 subpart W data. For both
large and small tanks, EPA linearly interpolated from 1990 to 2011 for each control category. Category-
specific emission factors developed from 2015 subpart W data were applied for every year of the time
series.
For petroleum tank emissions in the 2017 GHGI, the fraction of petroleum production sent to tanks
(62.7%) was held constant throughout the 1990-2015 time series. The percentages of petroleum
production sent to tanks that was sent to large tanks (93.2%) and small tanks (6.8%) were also held
constant throughout the 1990-2015 time series. The 2015 fraction of tank throughput in each control
category was applied to for the years 2011 to 2015. For 1990, it was assumed that all throughput was
sent to tanks in the uncontrolled categories. EPA then linearly interpolated from 1990 to 2011 for each
category. Category-specific emission factors developed from 2015 subpart W data were applied for
every year of the time series.
For both condensate and petroleum tank emissions in the 2017 GHGI, EPA also developed an emission
factor for malfunctioning dump values. In the subpart W, only large tanks report malfunctioning dump
valves. EPA has applied the emission factor to all throughput in the large tank categories for each year of
the time series. In future GHGIs, for years 2015 and forward, the EPA will 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
will be reflected in the GHGI.
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4. 2017 Revision to Oil Well Associated Gas Venting and Flaring
Emissions
This section discusses the EPA's approach 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 were
approximately an order of magnitude higher than 2016 GHGI estimates for stripper well venting, the
emissions source category in the GHGI that best corresponds to the subpart W category of associated
gas venting and flaring. The previous GHGI methodology did 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.
In the 2017 GHGI, the EPA used subpart W data to update the GHGI as described below.
Table summarizes data collected under subpart W for associated gas venting and flaring.
Table 10. 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 CO;e)
# Flaring
Wells
Flaring CH4
Reported
Emissions
(MMT CO:e)
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 2016 GHGI for 2011-2014.Figures 3
and below illustrate associated gas venting and flaring emissions reported under subpart W for RY2011-
RY2015, for certain basins. The majority of emissions is attributed to activities in the Gulf Coast,
Anadarko, Williston, and Permian Basins.
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3.50
3.00
2.50
O
u
2.00
o
| 1.50
E
x
u
1.00
0.50
0.00











-•-Subpart W Venting




-•-Subpart W Flaring
-•-GHGI Venting


























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
1.6
_ 1.4
(1)
O
u
1.2
£ 1
o
E 0.8
x
u
0.4
0.2
\
V






-*—220 - GULF COAST BASIN (LA TX)
¦•—360 - ANADARKO BASIN




—¦—395 - WILLISTON BASIN
-•—430 - PERMIAN BASIN




—-OTHER BASINS







0\



\ \







\ \



v<



	 '			 		

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. EPA developed AFs that allow this change to be reflected in the GHGI
for recent years.
First, we developed the total number of wells that either vent or flare associated gas from subpart W
data. The EPA summed the 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 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 was 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 11. 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%
Second, we developed the percent of wells reporting associated gas that vent and the percent that flare
using subpart W data for RY2011 through RY2015. We divided the number of wells that vent or flare by
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the total number of wells that vented or flared associated gas; see Table . This AF allows the GHGI to
reflect ongoing trends in the data.
Table 12. 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 G irelopment
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 . Table also presents the
2016 GHGI stripper well venting EF.
Table 13. 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
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, EPA considered but did
not use an approach involving extrapolating 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.
For the final 2017 GHGI, the EPA applied the subpart W-based percent of total oil wells that vent or flare
associated gas from 2015 (12%) over the entire time series. The EPA applied the 2011 split between
venting and flaring of associated gas to all prior years in the GHGI. To determine EFs for years prior to
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2011, the EPA applied the 2011 subpart W EFs. For 2011-2015, EPA used year-specific AD and EF from
subpart W.
The EPA continues to seek stakeholder feedback on potential approaches or data sources that could be
used to improve 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. 2017 Revision to Gas Well and Oil Well Counts
Drillinglnfo data on well counts have been used in the GHGI since the 2015 GHGI.4 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 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 presents the revised well counts used in the 2017 GHGI and the 2016 GHGI well counts,
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 14. Comparison of gas well and oil well counts for 2014 and 2015.
Well Type & Data Source
2014
2015
Gas Wells

2017 GHGI
433,941
421,893
2016 GHGI
456,140
N/A
EIA
565,951
555,364
World Oil
no data
502,987
Oil Wells
2017 GHGI
598,627
586,896
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.
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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Well Type & Data Source
2014
2015
2016 GHGI
898,268
N/A
EIA
no data
470,000
World Oil
no data
594,436
Total Gas and Oil Wells
2017 GHGI
1,032,568
1,008,789
2016 GHGI
1,354,408
N/A
EIA
N/A
1,025,364
World Oil
N/A
1,097,423
6. 2017 Revision to Equipment Counts
6.1 Previous GHGI Methodology ai ailable Subpart W Data
In the 2016 GHGI, the EPA used RY2014 GHGRP subpart W equipment count and well count data
included inthe equipment leaks reporting. 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 background is
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 below.
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 assessed the new subpart W data and developed updated AFs for the 2017 GHGI as
described below; the more detailed equipment counts and well counts data in subpart W allow the EPA
to more directly develop AFs.
6.2 Revised Equipment Activity Factors
For the 2017 GHGI EPA used reported RY2015 subpart W equipment count data (available under the
equipment leaks category). Table presents the reported equipment counts for RY2015 and compares
these data to RY2014 counts.
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Table 15. 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 16 presents the calculated AFs for each equipment type based
on RY2015 subpart W data, as compared to the 2016 GHGI.
Table 16. 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 , are
presented in Table 17.
Table 17. 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
297,301
Separators (Petro)
389,094
238,051
Heaters (NG)
99,038
89,574
Dehydrators (NG)
17,126
11,556
Meters/piping (NG)
523,885
372,084
Compressors (NG)
48,518
33,969
Heater-treaters (Petro)
113,661
140,124
Headers (Petro)
146,156
144,238
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a. Equipment counts are calculated using the revised 2014 national gas well (433,941)
and oil well (598,627) counts, as discussed in section 6.
In addition, for the 2017 GHGI, EPA used the latest subpart W data on equipment counts for other
production sources that previously used subpart W 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 to equipment counts in the 2017 GHGI, the EPA applied an approach over the time
series similar to that applied for the 2016 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
applied 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. The EPA then applied linear interpolation
between 1992 and 2011 to estimate equipment counts for each intermediate year.
Table 18. 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
7, 2017 Revision to Liquids Unloading
Previous GHGI Methodology ami 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.
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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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 assessed the subpart W data and developed revised EFs and
AFs for the 2017 GHGI.
7,2 rllGI Revisions for Liquids Unloading
For the 2017 GHGI, the EPA evaluated the reported RY2011-RY2015 subpart W liquids unloading data
and revised both the activity factors and the emission factors in the 2017 GHGI using this data.
Subpart W data used to develop activity data for the 2017 GHGI for liquids unloading include 2015 data
for the percent of wells that vent for liquids unloading, and 2011-2015 year-specific data from subpart
W for the split of wells venting with and without plunger lifts. Table 19 presents the number of wells
venting during liquids unloading (with and without plunger lifts) and their percent of the total gas well
population in subpart W, and compares this to the 2016 GHGI. The percent of wells that vent for liquids
unloading were determined from subpart W RY2015 data, because of the updated reporting
distinguishing between gas and oil wells.
Table 19. Subpart W and 2016 GHGI Liquids Unloading (LU) Activity Data
Data
Source
Year or
NEMS
Total #
Gas
Wells
# Gas Wells
venting for
LU
% of wells
venting for
LU
With Plunger Lifts (PL)
Without Plunger Lifts
# Wells
Vented
% of LU
Wells
# Wells
Vented
% of LU
wells
Subpart W
2011
(a)
69,505
N/A
42,826
62%
26,679
38%
2012
(a)
59,398
N/A
34,136
57%
25,262
43%
2013
(a)
58,645
N/A
30,922
53%
27,723
47%
2014
(a)
49,927
N/A
26,859
54%
23,068
46%
2015
307,737
51,643
16.8%
30,757
60%
20,886
40%
2016 GHGI
(data for
2014)
National
Total/
Average
456,140
60,389
13.2%
22,477
37%
37,912
63%
a. Only the count of total wells was reported for 2011-2014, not differentiated by gas and oil production.
For the 2017 GHGI, the EPA calculated an average EF to apply in the GHGI 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 presents the calculated subpart W liquids unloading EFs (with and without
plunger lifts) and compares this to the 2016 GHGI.
The previous GHGI applied 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 CH4/well for wells with plunger lifts. These EFs, particularly the Rocky Mountain EF for wells without
plunger lifts, resulted 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-
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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 20. 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 (used
in 2017 GHGI)
148,589
160,411
2016 GHGI (for 2014) (a)
Average
200,791
260,030
a. The 2016 GHGI was calculated on a regional basis. Regional emission factors range
from 2,856 to 1,127,406 scfy Cm/well for wells with plunger lifts, and 77,891 to
2,002,960 scfy ChU/well for wells without plunger lifts.
To calculate the 1990-2015 time series for liquids unloading, EPA developed an estimate of the percent
of wells conducting liquids unloading and the technologies used for unloading over that time period. The
previous GHGI methodology 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 from API/ANGA 2012. In the previous GHGI, for years 2010 and later,
the percent of wells in each category as presented in the API/ANGA survey was applied. The previous
GHGI assumed 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 in the previous GHGI.
In the final 2017 GHGI, the EPA retained 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 assumed 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 used 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 19, to calculate activity data for
2011 through 2015. The EPA applied 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
tused linear interpolation from the 1990 data points to the 2011 data points. For the EF revisions, the
EPA applied the average 2011-2015 EFs (148,589 scf CH4/well venting with plunger lift and 160,411 scf
CH4/well venting without plunger lift) developed from subpart W data to each year of the GHGI time
series.
8. Gathering and Boosting (G&B) Station Episodic Events
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In the previous GHGI, by using the subpart W onshore production data for the 2016 GHGI revisions, 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.
For the 2017 GHGI, 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.
In the 2017 GHGI, EPA added 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, using the Marchese analysis emission factor of 37 MT per station. For consistency
with G&B station-level emissions already presented in the 2016 GHGI, the 2012 emission factor was
applied to all time series years. See Table below.
Table 21. G&B Station Episodic Event CH4 Emission Estimates with Update Under Consideration
Parameter
1990
1995
2000
2005
2010
2014
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.
9, Januai *. 1 »* ^quest for Stakeholder Feedback
The EPA initially sought feedback on the questions below in the version of this memo released January
2017. The EPA discusses feedback received, and further planned improvements to the GHGI
methodology, in Chapters 3.5 and 3.6 of the Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2015 (April 2017). The EPA continues to welcome additional stakeholder feedback on these
questions for potential updates to future inventories.
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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
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
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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 , 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?
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.
11 https://www.epa.gov/sites/production/files/2015-12/documents/ng-inv-improvement-liquids-unloading-4-10-
2015.pdf
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Appendix A. Measurement Methodologies from Data Sources Considered for
Revisions
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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Appendix 1: Additional Detail on. Tank Basis Option
Based on stakeholder feedback, to calculate tank emissions, EPA implemented the throughput-based
approach described in Section 3.1 in the final 2017 GHGI. The EPA previously solicited stakeholder
feedback on the tank basis option described below, and included this approach in the public review
draft of the 2017 GHGI, but did not implement this approach in the final 2017 GHGI.
1.1 Activity Factor Development
For the tank-based approach that was considered, but not implemented in the final 2017 GHGI, 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 in subpart W to obtain total gas wellheads (307,737) and oil
wellheads (219,433) for all 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 average number of condensate or oil tanks per
gas or oil wellhead. Error! Reference source not found. Tables B-l and B-2Error! Reference source not
found, provide the reported subpart W tank counts for each category. Error! Reference source not
found. Table B-3 summarizes the calculated AFs (number of tanks per wellhead).
Table B-110. RY2015 Subpart W Condensate Tank Counts, By Tank Category

Condensate Tanks
Tank Category
Subpart W -
Subpart W -
Subpart W -

Large Tanks
Small Tanks
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%)
n/a - Not applicable.



Table 11. RY2015 Subpart W Oil Tank Counts, By Tank Category

Oil Tanks
Tank Category
Subpart W -
Subpart W -
Subpart W -

Large Tanks
Small Tanks
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.
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Table B-3. 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. Error! Reference source not found. Table B-4 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 B-4. 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%
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).
1.2 Emission Factor Development
For the tank-based approach that was considered, but not implemented in the final 2017 GHGI, 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 B.l.
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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 B-5Error! Reference source not found, shows the resulting EFs for each tank category, and Table
B-6Error! Reference source not found, presents the malfunctioning separator dump valve EF.
Table B-5. 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 B-6. 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 was 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.
1.3 Time Series Considerations
For the tank-based approach that was considered, but not implemented in the final 2017 GHGI, the EPA
considered 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 applying the
assumption that 50% of tanks are controlled, 50% of tanks are uncontrolled, and no tanks use VRU
(similar to the current GHGI approach) while maintaining the subpart W dump valve AF. The subpart W
AF for small condensate and small oil tanks could 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 could be estimated with linear interpolation between the two years. These assumptions
could then be used along with the total number of gas and oil wells for each year to estimate emissions.
The EPAalso considered 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 also considered applying the year-specific % of controlled tanks from
subpart W (as reported for tanks on well pads) for 2011-2015, and moving forward.
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1,4 Activity Factor Comparison Tank Basis and Throughput Basis
A consideration that EPA took into account when evaluating the throughput- and tank-based options
was the differences in activity factors to scale up subpart W data to a national level for each option.
Error! Reference source not found. Table B-7 presents throughput and well count data for RY2015
subpart W, the 2015 well counts (as discussed in section 6), and 2015 throughput from EIA for the
throughput and tank-based options, and calculates the percent of total throughput or well counts that
are reported under subpart W.
Table B-7. Overall Scale-up Factors based on Throughput or Tank Basis Options
Parameter
Condensate
Production
Oil Production
Throughput Basis Option
2015 National Throughput (MMbbl)
297
3,442
Estimated Production (MMbbl)
Reported for RY2015 under subpart
W
236-297
2,140-2,201
Estimated Percent of Total
Reported under subpart W
79-100%
62-64%
Tank Basis Option
2015 National Well Count
421,893
586,896
Count of Wells Reported for RY2015
under subpart W
307,737
219,433
Percent of Total Wells Reported
under subpart W
73%
37%
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