April 2020
Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2018:
Updates for Offshore Production Emissions
1 Background
This memorandum documents the updates implemented in EPA's 2020 Inventory of U.S. Greenhouse Gas
Emissions and Sinks (GHGI) for offshore production facilities in natural gas and petroleum systems. Additional
considerations for offshore production were previously discussed in memoranda released in September 2019
(Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2018: Updates Under Consideration for Offshore
Production Emissions) and April 2018 (Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2016:
Additional Revisions Considered for 2018 and Future GHGIs).1 All figures within this memo (i.e., Figure 1 through
Figure 19) are shown in Appendix A.
dustry Overview
Offshore oil and gas production facilities can include production structures and supporting structures. A
production structure can contain emission sources such as gas-oil separation, well unloading, equipment leaks,
gas dehydration, acid gas removal, liquid hydrocarbon storage, and gas compression. A portion of these
production structures have associated support structures such as caissons, wellhead protectors, and living
quarters. The production structure and any associated support structures form what is referred to as a complex
for the purposes of this memo. Certain data sources use the term "platform"—typically interchangeably with
"structure." For clarity, this memo uses a terminology convention of "structure" and "complex" when discussing
offshore production facilities.
Offshore production complexes operate in waters that are under federal government jurisdiction (federal waters)
or state government jurisdiction (state waters). Federal waters are referred to as the Outer Continental Shelf
(OCS), and include producing regions in the Gulf of Mexico (GOM), the Pacific Ocean (off the continental U.S.
western coast), and surrounding Alaska (including the Beaufort and Chukchi Seas, the Bering Sea, Cook Inlet and
the Gulf of Alaska)2. To this point, there has not been production in the OCS surrounding Alaska.3 State waters
consist of the 3 nautical mile area that extends off state coasts, but some areas (including Texas, Puerto Rico, and
the west coast of Florida) control the waters for as much as 9 or 12 nautical miles off their coasts. Offshore
facilities in state waters are located in the same three geographic areas as federal waters facilities; in the GOM
and off the coasts of California and Alaska.
An overview of offshore oil and gas production in federal and state waters is provided in Figure 1 for year 2017
(the most recent year with detailed emissions data available from data sources reviewed). The data sources for
Figure 1 include the Department of Interior (DOI)/Bureau of Ocean Energy Management (BOEM)4 for federal
waters production, and state agencies for state waters production (see Section 3.6 for the data source specific to
each state waters region). Offshore facilities in GOM federal waters produce the vast majority of both offshore oil
and gas.
1 Stakeholder materials including draft and final memoranda for the current 1990-2018 Inventory and previous Inventories are available at
https://www.epa.gov/ghgemissions/natural-gas-and-petroleum-systems.
2 https://www.boem.gov/Alaska-Region/
3 https://www.doi.gov/pressreleases/interior-approves-long-awaited-first-oil-production-facility-federal-waters-offshore
4 https://www.data.boem.gov/Production/OCSProduction/Default.aspx
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April 2020
2 Overview of Previous (2019) GHGI Methodology
The previous GHGI used emission factors (EFs) developed from year 2011 BOEM data across the entire time
series. The following sections summarize the data sources and methodology for the previous GHGI approach to
estimating vented and leak emissions (Section 2.1) and flaring emissions (Section 2.2).
2.1 Venti iak Emissions
To calculate vented and leak emissions from offshore production facilities in the previous GHGI, EPA used EFs
developed from BOEM's 2011 Gulfwide Emission Inventory (GEI), which relied on activity data from the 2011
Gulfwide Offshore Activity Data System (GOADS). Refer to Section 3.1 for more information on this data source.
EPA developed EFs for four offshore production facility categories: deepwater gas, deepwater oil, shallow water
gas, and shallow water oil. EPA calculated EFs on both a complex basis and a structure basis to compare and
consider the appropriateness of each. The methodology to calculate the EFs is documented in the memo
Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2013: Revision to Offshore Platform Emissions
Estimate (2015 Offshore Updates memo).5
Because the existing activity data in the previous GHGI were based on a count of structures, the previous GHGI
used structure-based EFs. Table 1 presents the previously used EFs in metric tons per year (mt/yr) for methane
(CH4) and carbon dioxide (C02) developed from the 2011 BOEM GEI. The complex-based EFs (considered but not
used) are presented in the second column, and the structure-based EFs (used in the previous GHGI) are presented
in the third column.
As seen in Table 1, when gas facilities are defined as producing more than 100 thousand cubic feet of gas per
barrel of hydrocarbon liquid (mcf/bbl), there are no deepwater gas facilities in the 2011 BOEM GEI dataset,
resulting in no EF for this facility group. EPA assigned the deepwater oil facility EF to deepwater gas facilities as a
surrogate. Note, the calculated C02 EFs exclude flaring emissions (which are calculated as explained in Section
2.2), but the CH4 EFs include CH4 emissions from flaring as well as combustion engine exhaust.
Table 1. Methodology for Previous GHGI—EFs Based on 2011 BOEM GEI
Complex EFJ
Structure EF
Pollutant/Facility Category
(mt/yr)
(mt/yr)
CH4
Deep Gas
_ b
_ b
Deep Oil
656
656
Shallow Gas
71
62
Shallow Oil
137
116
C02c
Deep Gas
_ b
_ b
Deep Oil
7.7
7.7
Shallow Gas
1.3
1.2
Shallow Oil
2.3
1.9
a - EFs considered for updates to the 2015 GHGI, but not ultimately used,
b - No available data to calculate. EPA assigned the deepwater oil facility EF to
deepwater gas facilities as a surrogate,
c - CO2 EFs exclude flaring emissions.
The activity data paired with the structure-based EFs was the number of offshore structures in federal waters of
the GOM that are existing in each year of the time series, in each category (deepwater gas, deepwater oil, shallow
5 https://www.epa.gov/sites/production/files/2015-12/documents/revision-offshoreplatforms-emissions-estimate-4-10-2015.pdf
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April 2020
water gas, and shallow water oil), based on a nationwide Department of Interior (DOI)/Mineral Management
Service (MMS) facility census. The MMS facility census had not been updated since 2010 (when the agency was
reorganized), so the previous GHGI used year 2010 activity as surrogate for all later time series years. Additionally,
the MMS data source did not differentiate between active and inactive structures, so all structures in the dataset
were considered active. The previous GHGI methodology also did not account for emissions from offshore
structures that are located in state waters or in federal Pacific waters.
ng Emissions
In the previous GHGI, EPA calculated C02 emissions from all offshore flaring activities as a single line item
appearing within the natural gas systems segment. As stated in Section 2.1, the minimal CH4 emissions from
flaring were included in the CH4 EFs calculated from the 2011 BOEM GEI data, shown in Table 1. The basis for the
C02 estimate was the total volume of gas vented and flared at offshore facilities in federal waters of the GOM and
the estimated percentage of this gas that was flared. These data were provided by DOI/MMS staff, based on
annual data collected in their Oil and Gas Operations Reports (OGOR) covering 1990 through 2008. Since 2009,
this data had not been available, so the previous GHGI used year 2008 values for all later time series years.
Information that would allow separation of these data into flaring from oil versus gas facilities was not available
from MMS, leading to the previous GHGI approach of reporting all offshore C02 flaring emissions under natural
gas systems. Similar to the vented and leak emissions methodology, the previous GHGI flaring emissions
methodology did not account for flaring at offshore facilities that are located in state waters or in federal Pacific
waters. Note, while flaring emissions are calculated for the BOEM GEI, the previous GHGI approach relied on the
volume of flared gas because it is more readily available across the time series, compared to BOEM GEI data which
are only available for certain years.
The previous GHGI offshore flaring C02 EF, applied to the quantity of gas flared, is from the Energy Information
Administration (EIA), and relies on the carbon content of natural gas. EIA provides a value of 54.7 kilograms of C02
per million BTU (kg/mmBTU) of flared natural gas.6 The previous GHGI methodology used this EF for all time series
years, with year-specific natural gas heat content (Btu/scf) from ElA's Monthly Energy Review publication.7 Note,
the flaring C02 EF from EIA (54.7 kg/mmBTU, equivalent to 120.6 Ib/mmBTU) is similar to the EF of 114.285
Ib/mmBTU that BOEM uses to calculate flaring C02 emissions for the GEI.
tble Data
EPA evaluated several data sources that provide emissions and/or activity data for offshore production sources.
The data sources included the BOEM GEI, BOEM OGOR data, the BOEM Platform Database, and the Greenhouse
Gas Reporting Program (GHGRP). Table 2 provides a general review of the information available from each source,
and Sections 3.1 through 3.5 discuss each source in detail. Section 3.6 discusses other data sources that were
evaluated, which are available from: the Oil and Gas Board of Alabama, the Louisiana Department of Wildlife and
Fisheries, the Louisiana Department of Natural Resources, the Texas General Lands Office, the Texas Railroad
Commission, the California State Lands Commission, the California Department of Conservation, and the Alaska
Oil and Gas Conservation Commission.
6 https://www.eia.gov/environment/emissions/co2_vol_mass.php
7 See Table A4, Approximate Heat Content of Natural gas (Btu per cubic foot), available at
https://www.eia.gov/totalenergy/data/monthly/pdf/secl3_5.pdf
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April 2020
Table 2. Data Sources with Emissions and/or Activity Data for Offshore Production
Parameter
Data Source
BOEM GEI
BOEM OGOR-A
BOEM OGOR-B
BOEM Platform
Database
EPA GHGRP
Summary
Triennial Gulfwide
emissions
inventory
Offshore oil and
gas production
data
Offshore vented
and flared gas
volumes
Offshore
structures, dates,
depths, etc.
Annual emissions
data from facilities
required to report
Geographic
coverage
Gulf only
Gulf and Pacific
Gulf only
Gulf and Pacific
All that meet or
exceed threshold
Federal vs. state
waters
Federal only
Federal only
Federal only
Federal only
All that meet or
exceed threshold
Estimation
frequency
Triennial (2000,
2005, 2008, 2011,
2014, 2017)
Monthly
Monthly
Monthly
Annual (2011 -
2018)
Pollutants
Criteria, criteria
precursors, GHG
n/a - activity (not
emissions)
n/a - flared
volumes data (not
emissions)
n/a - activity (not
emissions)
GHG
Emission sources
All
n/a - activity (not
emissions)
Flares and vents
n/a - activity (not
emissions)
Subpart W: Vented,
leak, flares
Subpart C:
Combustion
Facility definition
Structures and
complexes
Lease, Area/Block
Lease
Structures and
complexes
Complexes
Reporting
requirement
All active and
inactive facilities,
but some facilities
fail to report for
various reasons
All facilities
All facilities
All facilities
Only facilities with
> 25,000 mt C02e
emissions
i Gulfwide Emissions Inventory (GEI)
This section summarizes the scope and available data from the BOEM GEI publications and explains how EPA used
the data in the updated methodology for the 2020 GHGI.
3.1.1 Scope and Available Data
The BOEM GEI estimates criteria pollutant and GHG emissions from offshore oil and gas production sources in
GOM federal waters. The BOEM GEI does not account for emissions from sources in GOM state waters or off the
coasts of California and Alaska. All offshore facilities in GOM federal waters that are west of 87.5 degrees
longitude are required to report data to BOEM8, in order to comply with 30 CFR 550.304, and BOEM issues a
Notice to Lessees and Operators (NTL) which provides instructions for each GEI.9 BOEM collects monthly activity
data from OCS operators in the GOM via the Gulfwide Offshore Activities Data System (GOADS), then BOEM
calculates emission source-specific emissions. GEI studies are available for years 2000, 2005, 2008, 2011, 2014,
and 2017.10 Each GEI provides emissions and activity data for active offshore structures, and counts of inactive
structures. GHG emissions are estimated for the following emission sources on an active offshore structure: amine
units; boilers, heaters, and burners; combustion flares; drilling equipment (for drilling rigs attached to an offshore
structure); engines; equipment leaks (valves, flanges, connectors); glycol dehydrators; losses from flashing; mud
degassing; turbines; pneumatic pumps; pressure and level controllers; storage tanks; and cold vents. Each
emission source uses a documented methodology to calculate emissions, and most rely on equations or EFs that
8 All existing offshore production facilities in the GOM are located west of 87.5 degrees longitude.
9 The 2017 GEI NTL is available at https://www.boem.gov/BOEM-NTL-2016-N03/.
10 Each GEI study is available online: https://www.boem.gov/Gulfwide-Offshore-Activity-Data-System-GOADS/
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relate throughput (or other activity data) to emissions. Sources for methods and EFs include, among others, API
1996 for fugitive EFs, EIIP 1999 for equations for pneumatic pumps and controllers, and AP-42 for EFs for
engines.11 BOEM also recognizes a non-reporter population (i.e., active structures that are expected to report but
do not), and these non-reporters were evaluated in the 2014 and 2017 GEI studies. Table 3 provides a summary of
the BOEM GEI activity and emissions data. EPA grouped the BOEM GEI emissions into categories of vent and leak
(including engine exhaust CH4) emissions and flaring emissions.
Table 3. BOEM GEI Reporting Overview
Data
2000
2005
2008
2011
2014
2017
# Active & Inactive Structures
3,154
1,619
3,304
3,051
1,856
1,842
# Active Structures
2,873
1,585
3,026
2,544
1,651
1,194
# Non-Reporting Structures (estimate3)
NE
NE
583
538
250
250
# Active Complexes
2,529
1,407
2,614
2,205
1,397
995
Flared Volume (MMcf)
2,498
5,104
6,985
10,074
5,123
6,265
Vent and Leak Emissions
CH4 (mt)
510,014
194,294
383,073
245,838
204,420
167,567
CO2 (mt)
8,511
2,160
4,282
4,009
3,394
2,687
Flare Emissions
CH4 (mt)
144
296
401
332
301
2,888
CO2 (mt)
263b
9,785b
380,186
547,942
278,861
459,274
N2O (mt)
<1
0.2
7
10
5
8
NE - Not estimated.
a - The GEI estimated 85%-90% of all active offshore structures reported in the 2008, 2011, and 2014 GEIs.
b - The 2000 and 2005 BOEM GEIs calculated flaring CO2 emissions based on the calculation requirements
applicable to the GEI in those years (i.e., only flare pilot CO2 emissions were calculated). See the following paragraph
for information regarding flare emissions in early years.
The BOEM reporting requirements have changed across the GEIs, and certain years had unique circumstances that
affected reporting which EPA took into account when assessing data for incorporation into GHGI updates.
Important changes and circumstances include:
• Flare C02 emissions in early years
o Flare C02 emissions were not fully accounted for in the 2000 and 2005 GEIs, and only flare pilot
CO2 emissions are included—i.e., flare C02 emissions in these years are inconsistent with reported
flared gas volumes (which are reported via GOADS for these years), so EPA would need to apply
additional calculations to use such data for GHGI EFs.
• Minor source structure emissions in early years
o Minor source structures include caissons, wellhead protectors, living quarters, and "other"
unclassified structures.
o In years 2000 and 2005, offshore operators were not required to report any data for minor source
structures to GOADS.
o In years 2008 and 2011, offshore operators were required to identify minor source structures in
GOADS, but were not required to provide detailed activity data for the emission sources on the
structures. BOEM calculated emissions from minor source structures for the 2008 and 2011 GEIs
by applying default EFs to each type of minor source structure.
o Beginning in the 2014 GEI, minor source structures are treated the same as all other structures. As
such, operators reported all activity data for emission sources on minor source structures through
GOADS and the emissions were fully accounted for in the 2014 and 2017 GEIs.
11 Each GEI study documents the methodologies applied to each emission source. For example, see Section 4.2 in the 2014 GEI study for the
complete emission estimation procedures.
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April 2020
• 2005 GEI hurricane season impact
o There was a significant impact on offshore production operations in year 2005 due to a
particularly severe hurricane season,
o As a result, the number of structures and complexes reported was very low, and those that did
report showed particularly low levels of activity (and corresponding low calculated emissions),
o Therefore, as discussed in Section 4.1.1, EPA limited the application of year 2005 GEI data in the
GHGI (i.e., did not use year 2005 data as surrogate for surrounding years).
• Year 2000, first year of reporting
o There have been updates in GEI inventory calculation methods and operator understanding and
delivery of data since the first year of reporting underlying the year 2000 GEI (refer to the 2014
GEI report, Appendix B trends analysis discussion),
o Therefore, as discussed in Section 3.1.2, EPA excluded year 2000 GEI data from the GHGI updates.
3.1.2 Considerations for Use in 2020 GHGI Updates
The 2011 BOEM GEI is the basis of the previous GHGI EFs, but GEIs are available for years 2000, 2005, 2008, 2011,
2014, and 2017. In updating the 2020 GHGI, EPA calculated EFs using each year of the BOEM GEI data such that
trends are reflected over the time series. EPA updated the EF basis in two ways: (1) switched from a structure-
basis to a complex-basis; and (2) established EF subcategories for "major" versus "minor" complexes, instead of
the previous water depth subcategories. This section details these and other considerations for updating the 2020
GHGI.
3.1.2.1 Complex-Level EFs
EPA calculated EFs at the complex level from GEI data to emphasize the activity data unit most related to the
presence of production operations and likely correlated to emissions levels (i.e., a complex produces oil and gas
with possibly significant emissions, or is alternatively a collection of likely low-emitting supporting structures).
Multi-structure complexes that have a production structure and other supporting structures were considered as a
single unit. Complexes with one or more non-production structures were also considered a single unit, likely with
low emissions. This level of categorization then leads to consideration of "major" versus "minor" complexes as
discussed in Section 3.1.2.2.
3.1.2.2 Major versus Minor Complexes
EPA introduced new EF subcategories to differentiate major and minor complexes in order to represent
differences in complexity and processing capabilities (i.e., equipment types present) which are expected to
correlate with emissions. This approach replaced the previous subcategorization scheme based on water depth,
which more indirectly correlated with emissions (i.e., while deep water facilities tend to have higher per-facility
emissions than shallow water facilities, emissions are not a direct function of water depth).
To categorize GEI complexes as major versus minor, EPA crosswalked individual complexes between the GEI and
another BOEM data source, the BOEM Platform Database (discussed in Section 3.2). The BOEM Platform Database
designates all structures as "major" or "minor" structures.12 A major structure is defined as containing at least six
well completions or containing more than two pieces of production equipment; otherwise the structure is defined
as minor. Using this designation, EPA classified each existing complex in the BOEM Platform Database that has at
least one major structure as a major complex. EPA then matched the complex IDs in the BOEM GEI with the
complex IDs and their major or minor complex classifications from the BOEM Platform Database.
12 This is not to be confused with minor source structures in the GEI, as discussed in Section 3.1.1. It is likely that GEI minor source
structures are minor structures in BOEM's platform database (defined based on structure type), but not all minor structures in the BOEM
Platform Database are minor source structures in the GEI.
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April 2020
3,1,2,3 Facility Production Type Assignment
In reviewing the previous GHGI methodology for developing EFs from GEI data, EPA identified an opportunity to
improve estimates by utilizing more of the available GEI data. The previous GHGI methodology, as discussed in
Section 2, relied on matching lease IDs between BOEM GEI and year 2011 OGOR-A production data (see Section
3.3 for a detailed discussion of OGOR-A data) in order to assign a production type (oil or gas) for each complex.
However, not all BOEM GEI lease IDs could be matched to an OGOR lease ID, and thus certain complexes were
unmatched and could not be used in the EF calculations. This population was relatively small, but a methodology
that would allow EPA to use all BOEM GEI data is preferred.
In addition to lease IDs, BOEM GEI and OGOR-A also provide Area and Block IDs for each record. A Block is 3 miles
by 3 miles and an Area is comprised of multiple Blocks. The relationship between leases and Area/Blocks can vary
- leases can be part of a Block or can be in multiple Blocks. EPA calculated the gas-to-oil ratio (GOR) at the Area
and Area/Block-level and assigned each as oil or gas to gap-fill those complexes which could not be assigned at
the lease-level.
The previous GHGI oil versus gas assignments for each complex relied on year 2011 data, because the 2011 GEI is
the basis of the EFs. However, for the 2020 GHGI updates, EPA evaluated data from additional GEI years and
assigned production type for each complex based on data specific to that year, when possible. EPA used the
existing GHGI convention that defines entities with a GOR greater than 100 thousand cubic feet (mcf) of gas per
barrel (bbl) of hydrocarbon liquid as gas-producing, and defines entities with a GOR less than 100 mcf/bbl as oil-
producing. Certain leases did not have production in a given GEI year, but did have production in surrounding
years, and this information was used in the assignments.
EPA implemented a four-step process to assign production type for each complex in the GEI:
Step 1: Assign production type as oil versus gas based on year-specific lease-level production in OGOR-A
(similar to previous GHGI approach).
Step 2: For those complexes not assigned in Step 1 because the lease did not have production in the specific
GEI year, assign production type based on a nearest-year approach. The nearest-year approach looks
to Step 1 production type assignments for a given complex in the years surrounding a particular GEI.
For example, a complex in the 2008 GEI dataset that was not assigned a production type based on
year 2008 data would look to assignments for that complex in the following preferential order: year
2007, 2009, 2006, 2010, etc.
Step 3: For those complexes not assigned in Step 1 or 2, assign complex to oil versus gas based on year-
specific Area/Block-level production in OGOR-A.
Step 4: For those complexes not assigned in Steps 1-3, assign complex to oil versus gas based on year-
specific Area-level production in OGOR-A.
Table 4 summarizes the number of complexes that were assigned as oil or gas in each step for each GEI.
Table 4. Number of GEI Complexes Assigned to Oil versus Gas, by Data Processing Step
Data Processing Step
2005
2008
2011
2014
2017
# Assigned To
# Assigned To
# Assigned To
# Assigned To
# Assigned To
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Step 1: Year-Specific
Lease-Level Production
845
449
1,550
719
1,358
539
1,007
214
754
116
Step 2: Nearest-Year
Lease-Level Production
31
29
76
135
79
109
51
56
37
33
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April 2020
Data Processing Step
2005
2008
2011
2014
2017
# Assigned To
# Assigned To
# Assigned To
# Assigned To
# Assigned To
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Oil
Gas
Step 3: Area/Block-Level
Production
12
8
26
15
18
9
5
2
5
2
Step 4: Area-level
Production
23
10
73
20
84
9
57
5
44
2
Total Complexes
Assigned to Oil and Gas
911
496
1,725
889
1,539
666
1,120
277
840
153
3,1,2,4 Emission Factors
With the BOEM GEI complexes assigned to gas versus oil and major versus minor, according to the considerations
in the preceding subsections, EPA calculated EFs for each subcategory. A summary of the number of complexes
reporting to BOEM GEI under each subcategory is shown in Table 5. EPA calculated vent and leak EFs for the 2005,
2008, 2011, 2014, and 2017 GEIs on a complex basis for each subcategory, see Table 6. Vent and leak CH4 and C02
EFs are depicted in Figure 2 and Figure 3. Stakeholders were also interested in calculating EFs for each emission
source (see Section 5), and EFs for each vent and leak emission source are presented in Table 7 through Table 10,
for reference. Vent and leak emissions account for all emission sources reported to the GEI, except for flares. EPA
did not use flaring emissions from the GEI in the 2020 GHGI update, instead OGOR-B flaring volumes were applied
over the time series (see Section 3.4). Offshore operators were not required to report data for minor source
structures in the 2005 GEI (as discussed in Section 3.1.1) and there were fewer minor complexes that reported to
the 2005 GEI as a result (see Table 5). In addition, the 2005 minor complex EFs are higher than minor complex EFs
for other GEI years, because the 2005 GEI only includes the higher emitting minor complexes (compared to the
lower emitting minor source structures, which are included in other GEI years). Note, the 2000 BOEM GEI (i.e., the
first year of the GEI) was not considered for this analysis; see discussion in Section 3.1.1.
Table 5. Summary of BOEM GEI Complex Counts, by Subcategory
Oil/Gas
Complex
Major/ Minor
Complex
# Complexes
2005
2008
2011
2014
2017
Gas
Major
431
474
310
174
92
Oil
Major
798
858
737
667
550
Total
Major
1,229
1,332
1,047
841
642
Gas
Minor
65
409
349
103
61
Oil
Minor
111
853
791
451
290
Total
Minor
176
1,262
1,140
554
351
Total Used in EF Calcs
1,405
2,594
2,187
1,395
993
Total Reported to GEIJ
1,407
2,614
2,205
1,397
995
a - Sum of major and minor complexes does not equal total number of complexes reported to the GEI because
certain complexes could not be categorized. Section 3.1.2.2 discusses the categorization approach.
Table 6. Complex-Level Total Vent and Leak EFs (mt/yr) Calculated from BOEM GEI Data
Pollutant/Facility
Subcategory
2005 Complex
EF (mt/yr)
2008 Complex
EF (mt/yr)
2011 Complex
EF (mt/yr)
2014 Complex
EF (mt/yr)
2017 Complex
EF (mt/yr)
CH4
Gas / Major
89
262
123
116
192
Oil / Major
183
281
263
250
250
Gas / Minor
37
10
11
35
25
Oil / Minor
66
15
13
31
38
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Pollutant/Facility
Subcategory
2005 Complex
EF (mt/yr)
2008 Complex
EF (mt/yr)
2011 Complex
EF (mt/yr)
2014 Complex
EF (mt/yr)
2017 Complex
EF (mt/yr)
CO;
Gas / Major
0.7
2.9
2.0
1.4
6.2
Oil / Major
2.2
3.1
4.2
4.3
3.6
Gas / Minor
0.1
0.1
0.4
0.7
0.2
Oil / Minor
0.5
0.2
0.2
0.4
0.4
Table 7. Complex-Level Vent and Leak CH4 EFs by Emission Source for Major Sources (mt/yr) Calculated from
BOEM GEI Data
Facility
Subcategory
Emission Source
Complex CH4 EF (mt/yr)
2005
2008
2011
2014
2017
Gas / Major
Total
89
262
123
116
192
Gas / Major
Cold Vent
17.5
178.9
43.8
29.4
65.5
Gas / Major
Equipment Leaks
45.8
41.5
35.2
48.4
52.5
Gas / Major
Pneumatic Pump
7.5
11.8
18.3
22.9
43.4
Gas / Major
Losses from Flashing
0.8
2.2
1.3
1.3
0.5
Gas / Major
Pneumatic Controller
5.4
17.6
15.2
8.2
22.6
Gas / Major
Combustion
8.2
6.0
6.5
4.8
7.0
Gas / Major
Glycol Dehydrator Unit
3.5
3.7
2.3
0.5
0.1
Gas / Major
Storage Tank
-
0.07
0.07
0.08
0.18
Gas / Major
Mud Degassing
0.15
0.05
0.37
-
-
Gas / Major
Minor Surrogate
-
0.11
0.10
0.02
-
Gas / Major
Amine Gas Sweetening Unit
0.01
0.02
0.01
0.0003
0.03
Oil / Major
Total
183
281
263
250
250
Oil / Major
Cold Vent
65.0
133.2
137.3
103.2
101.8
Oil / Major
Equipment Leaks
65.6
66.9
56.5
77.6
71.5
Oil / Major
Pneumatic Pump
8.2
12.9
16.2
37.6
32.8
Oil / Major
Losses from Flashing
21.3
18.1
16.9
9.0
6.4
Oil / Major
Pneumatic Controller
3.6
21.0
12.8
8.4
20.1
Oil / Major
Combustion
13.3
9.5
12.8
10.8
15.5
Oil / Major
Glycol Dehydrator Unit
5.8
18.5
8.7
2.7
0.8
Oil / Major
Storage Tank
-
0.9
1.0
0.9
0.9
Oil / Major
Mud Degassing
0.2
0.2
0.4
0.2
0.1
Oil / Major
Minor Surrogate
-
0.1
0.1
0.01
-
Oil / Major
Amine Gas Sweetening Unit
0.0005
-
0.0005
0.0001
0.0003
means that emissions were not reported for a source.
Table 8. Complex-Level Vent and Leak C02 EFs by Emission Source for Major Sources (mt/yr) Calculated from
BOEM GEI Data
Facility
Subcategory
Emission Source
Complex CO; EF (mt/yr)
2005
2008
2011
2014
2017
Gas / Major
Total
0.7
2.9
2.0
1.4
6.2
Gas / Major
Cold Vent
0.36
2.24
1.20
0.84
3.35
Gas / Major
Equipment Leaks
-
-
-
-
-
Gas / Major
Pneumatic Pump
0.19
0.29
0.34
0.31
0.78
Gas / Major
Losses from Flashing
0.02
0.05
0.03
0.03
0.01
Gas / Major
Pneumatic Controller
0.13
0.36
0.43
0.20
0.85
Gas / Major
Combustion
-
-
-
-
-
-------
April 2020
Facility
Subcategory
Emission Source
Complex CO; EF (mt/yr)
2005
2008
2011
2014
2017
Gas / Major
Glycol Dehydrator Unit
-
-
-
-
-
Gas / Major
Storage Tank
-
-
-
-
-
Gas / Major
Mud Degassing
0.0005
0.0002
0.0013
-
-
Gas / Major
Minor Surrogate
-
-
-
-
-
Gas / Major
Amine Gas Sweetening Unit
-
-
-
0.01
1.20
Oil / Major
Total
2.2
3.1
4.2
4.3
3.6
Oil / Major
Cold Vent
1.55
2.10
2.70
1.75
2.36
Oil / Major
Equipment Leaks
-
-
-
-
-
Oil / Major
Pneumatic Pump
0.14
0.23
0.27
1.69
0.63
Oil / Major
Losses from Flashing
0.49
0.41
0.39
0.21
0.15
Oil / Major
Pneumatic Controller
0.08
0.38
0.85
0.69
0.43
Oil / Major
Combustion
-
-
-
-
-
Oil / Major
Glycol Dehydrator Unit
-
-
-
0.0003
-
Oil / Major
Storage Tank
-
-
-
-
-
Oil / Major
Mud Degassing
0.001
0.001
0.001
0.002
0.001
Oil / Major
Minor Surrogate
-
-
-
-
-
Oil / Major
Amine Gas Sweetening Unit
--
--
--
0.01
0.03
means that emissions were not reported for a source.
Table 9. Complex-Level Vent and Leak CH4 EFs by Emission Source for Minor Sources (mt/yr) Calculated from
BOEM GEI Data
Facility
Subcategory
Emission Source
Complex CH4 EF (mt/yr)
2005
2008
2011
2014
2017
Gas / Minor
Total
37
10
11
35
25
Gas / Minor
Cold Vent
9.7
1.1
5.3
2.7
5.6
Gas / Minor
Equipment Leaks
20.4
3.9
2.2
10.6
12.3
Gas / Minor
Pneumatic Pump
4.0
1.3
1.2
19.0
4.6
Gas / Minor
Losses from Flashing
-
0.2
-
0.04
-
Gas / Minor
Pneumatic Controller
1.8
3.1
1.5
2.4
1.2
Gas / Minor
Combustion
1.0
0.3
0.1
0.2
1.4
Gas / Minor
Glycol Dehydrator Unit
0.5
-
0.03
0.05
0.02
Gas / Minor
Storage Tank
-
0.009
0.001
0.001
-
Gas / Minor
Mud Degassing
0.04
0.01
0.01
-
-
Gas / Minor
Minor Surrogate
-
0.3
0.3
0.01
-
Gas / Minor
Amine Gas Sweetening Unit
-
-
-
-
-
Oil / Minor
Total
66
15
13
31
38
Oil / Minor
Cold Vent
27.1
4.4
6.9
10.0
5.5
Oil / Minor
Equipment Leaks
25.8
4.9
2.7
13.8
14.8
Oil / Minor
Pneumatic Pump
8.7
1.5
1.5
5.0
12.4
Oil / Minor
Losses from Flashing
0.04
2.7
0.05
0.3
0.3
Oil / Minor
Pneumatic Controller
2.1
1.1
0.6
0.9
2.9
Oil / Minor
Combustion
2.4
0.3
0.4
0.4
1.6
Oil / Minor
Glycol Dehydrator Unit
0.03
0.12
0.01
0.001
0.22
Oil / Minor
Storage Tank
-
0.01
0.01
0.004
0.02
Oil / Minor
Mud Degassing
0.30
0.02
0.05
0.05
-
Oil / Minor
Minor Surrogate
-
0.35
0.28
0.04
-
Oil / Minor
Amine Gas Sweetening Unit
--
--
--
--
--
10
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April 2020
means that emissions were not reported for a source.
Table 10. Complex-Level Vent and Leak C02 EFs by Emission Source for Minor Sources (mt/yr) Calculated from
BOEM GEI Data
Facility
Subcategory
Emission Source
Complex CO; EF (mt/yr)
2005
2008
2011
2014
2017
Gas / Minor
Total
0.1
0.1
0.4
0.7
0.2
Gas / Minor
Cold Vent
0.03
0.01
0.22
0.07
0.05
Gas / Minor
Equipment Leaks
-
-
-
-
-
Gas / Minor
Pneumatic Pump
0.05
0.03
0.09
0.63
0.10
Gas / Minor
Losses from Flashing
-
0.004
-
0.001
-
Gas / Minor
Pneumatic Controller
0.03
0.03
0.07
0.04
0.03
Gas / Minor
Combustion
-
-
-
-
-
Gas / Minor
Glycol Dehydrator Unit
-
-
-
-
-
Gas / Minor
Storage Tank
-
-
-
-
-
Gas / Minor
Mud Degassing
0.00014
0.00004
0.00003
-
-
Gas / Minor
Minor Surrogate
-
-
-
-
-
Gas / Minor
Amine Gas Sweetening Unit
-
-
-
-
-
Oil / Minor
Total
0.5
0.2
0.2
0.4
0.4
Oil / Minor
Cold Vent
0.26
0.09
0.14
0.24
0.12
Oil / Minor
Equipment Leaks
-
-
-
-
-
Oil / Minor
Pneumatic Pump
0.19
0.04
0.03
0.12
0.22
Oil / Minor
Losses from Flashing
0.001
0.061
0.001
0.008
0.008
Oil / Minor
Pneumatic Controller
0.05
0.02
0.01
0.02
0.09
Oil / Minor
Combustion
-
-
-
-
-
Oil / Minor
Glycol Dehydrator Unit
-
-
-
-
-
Oil / Minor
Storage Tank
-
-
-
-
-
Oil / Minor
Mud Degassing
0.0011
0.0001
0.0002
0.0005
-
Oil / Minor
Minor Surrogate
-
-
-
-
-
Oil / Minor
Amine Gas Sweetening Unit
--
--
--
--
--
means that emissions were not reported for a source.
A Platform Database
This section summarizes the scope and available data from the BOEM Platform Database13 and how EPA used the
data in the updated methodology for the 2020 GHGI.
3,2,1 Scope and Available Data
The BOEM Platform Database provides information on all offshore facilities in GOM federal waters. The
information includes complex and structure IDs, lease IDs, Area/Block IDs, install dates, removal dates, the
structure water depth, and a major/minor structure designation.14 There are 7,075 structures and 6,166
complexes in the database; the earliest install date is 1947 and the earliest removal date is 1973. EPA accessed
the BOEM Platform Database in March 2020 to conduct the analyses presented in this memo. A similar BOEM
dataset is available for facilities in the Pacific, and this information is discussed further in Section 3.6.2.
13 https://www.data.boem.gov/Platform/PlatformStructures/Default.aspx
14 A major structure is defined as containing at least 6 completions or containing more than 2 pieces of production equipment.
11
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April 2020
3,2,2 Considerations for Use in 2020 GHGI Updates
EPA evaluated the BOEM Platform Database to determine the number of active offshore complexes in GOM
federal waters, including major versus minor subcategorization (refer to Section 3.1.2.2), in each year of the time
series.
An important consideration when determining the number of "active" offshore complexes, versus the number of
"existing" offshore complexes, is the removal date. Based on current DOI/Bureau of Safety and Environmental
Enforcement (BSEE) regulations, structures must be removed as soon as possible, but no later than 5 years after
ceasing production (30 CFR 250.1703(c)). As a result, there can be a period of inactivity (no emissions) while an
offshore complex exists but is awaiting or undergoing removal. Because EFs are developed for active (emitting)
complexes, EPA aims to exclude inactive complexes from activity data estimates over the time series.
To ensure correct interpretation of the BOEM Platform Database, EPA queried the BOEM Platform Database by
various approaches to develop a reasonable assumption for expected decommissioning time (i.e., duration of
inactivity before recorded removal date). EPA considered decommissioning time periods ranging from two to four
years and found that assuming a three-year decommissioning period produced the most reasonable activity
estimates (based on comparing calculated activity from the BOEM Platform Database and GEI reported activity).
In other words, EPA considers that a structure or complex is active in year N only if its removal date is three or
more years after year N. Figure 11 depicts the major and minor complex counts over the time series, including the
split between oil and gas complexes (as discussed in Section 3.3.2 and Section 4.1.2)
A " liie met
This section summarizes the scope and available data from the BOEM OGOR-A dataset and how EPA used the data
in the updated methodology for the 2020 GHGI.
3.3.1 Scope and Available Data
BOEM publishes the Oil and Gas Operations Reports - Part A (OGOR-A), that present annual oil and gas
production information for each oil and gas lease in GOM federal waters. Two methods to download OGOR-A
data are available, and the information in each varies. The complete OGOR-A dataset, which includes production
from year 1947 to the present, provides data for each lease ID over this time period.15 The Area/Block IDs
associated with each lease ID are also available, but this information is only available to be downloaded for
individual years from 1996 to the present.16 The GOM federal waters oil and gas production available in OGOR-A
is from the offshore facilities whose emissions are estimated in the BOEM GEI. A similar BOEM dataset is available
for facilities in the Pacific, and this information is discussed further in Section 3.6.2.
3.3.2 Considerations for Use in 2020 GIIGI Updates
EPA used this dataset to assign production type and calculate annual production from all GOM federal water
complexes over the time series, as described below.
3,3,2,1 Production Type Assignment
EPA used data on production at the lease-level, Area/Block-level, and Area-level to assign GOM federal water
complexes as oil or gas production type (see Section 3.1.2.3). EPA used the complete OGOR-A dataset to analyze
lease-level production and the separate individual year OGOR-A downloads to analyze Area/Block-level and Area-
level production. EPA applied the existing GHGI methodology to designate each lease, Area/Block, and Area as
gas- or oil-production; entities with a GOR greater than 100 mcf/bbl are classified as gas-producing, and entities
with a GOR less than 100 mcf/bbl as oil-producing.
15 See "Production Data" at https://www.data.boem.gov/Main/RawData.aspx.
16 https://www.data.boem.gov/Main/OGOR-A.aspx
12
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April 2020
These production type assignments were used in two ways: (1) Matched to the IDs of the offshore complexes in
the BOEM GEI data in order to calculate EFs specific to oil and gas complexes (as detailed in Section 3.1.2.3); and
(2) Classify the production type fractions of total active GOM federal water complex counts determined from the
BOEM Platform Database (see Section 3.2) over the GHGI time series. Figure 4 presents the estimated
percentages of active GOM federal water oil versus gas complexes over the GHGI time series.
3.3.2.2 Annual Production
EPA used the complete OGOR-A dataset to determine oil and gas production from oil facilities versus gas facilities
over the time series. While OGOR-A production data are reported separately for offshore production from gas
wells versus oil wells, EPA used the existing GHGI convention to define each lease with a GOR greater than 100
mcf/bbl as gas-producing, and otherwise defined each lease as oil-producing. The resulting production from oil
facilities and gas facilities over the GHGI time series is presented in Figure 5. EPA used the ratio between GOM
OCS production and GOM state waters production17 to estimate offshore production emissions in GOM state
waters (see discussion in Section 4.2).
ig and Venting Volumes Dataset
This section summarizes the scope and available data from the BOEM OGOR-B dataset and how EPA used the data
in the updated methodology for the 2020 GHGI.
3,4,1 Scope and Available Data
BOEM publishes Oil and Gas Operations Reports - Part B (OGOR-B) that presents lease disposition data, including
codes indicating disposal types of flared or vented gas. OGOR-B data are specific to leases in GOM federal waters.
As discussed in Section 2.2, in the previous GHGI, C02 emissions from all offshore flaring activities were calculated
using OGOR-B activity data provided by MMS staff, because the OGOR-B data were not previously publicly
available. OGOR-B data are now available online,18 with limitations: the total combined volume of gas vented and
flared is available for all years from 1996 through present, but the separate volumes of gas vented and gas flared
have only been available since 2011 (when BOEM expanded reporting requirements).
The publicly available OGOR-B dataset also specifies the volumes of vented and flared gas by well production type
(gas versus oil), which facilitated EPA estimating flaring C02 emissions separately for natural gas and petroleum
systems. Note, while gas and oil wells are not likely defined in the same manner as the GHGI convention (using a
GOR threshold of 100 mcf/bbl), this production type designation still likely offers an improvement on the previous
methodology which did not separate flaring emissions between natural gas and petroleum systems.
To assess agreement between the previous GHGI basis and the newly available OGOR-B dataset, EPA compared
the total volume of gas vented and flared for overlapping years between the publicly available OGOR-B data and
data previously provided by MMS staff (years 1996-2008); EPA found that the volumes are very similar, within
±2% in each year—providing support for retaining previous GHGI data in early time series years. The fraction of
gas that is flared is not available for overlapping years across the two datasets and therefore could not be directly
compared; the data provided by MMS staff are available for 1990-2008, while the publicly available OGOR-B data
provide this from 2011 and forward.
The volumes of flared gas used in the previous GHGI (as provided by MMS staff) and the volumes of flared gas
reported in the publicly available OGOR-B data are compared in Table 11.
17 GOM State waters production is available in separate data sources, as discussed in Section 3.6.1.
18 https://www.data.boem.gov/Main/OGOR-B.aspx
13
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April 2020
Table 11. Comparison of Flared Gas Volumes for Offshore Production Facilities Between Previous GHGI and
OGOR-B
Year
Previous GHGI
OGOR-B
Flared &
Vented Gas
(MMcf)
% Gas
Flared
Flared &
Vented Gas
(MMcf)
% Gas
Flared
% of Flared & Vented
Gas: from Oil Wells /
from Gas Wells
Gas Flared
(MMcf)
% of Flared Gas:
from Oil Wells/
from Gas Wells
1990
13,610
28%
b
b
b
b
b
1991
13,017
28%
b
b
b
b
b
1992
11,193
24%
b
b
b
b
b
1993
11,230
24%
b
b
b
b
b
1994
11,516
24%
b
b
b
b
b
1995
12,537
26%
b
b
b
b
b
1996
14,343
28%
14,630
_ c
65%/35%
_ c
_ c
1997
15,440
33%
15,749
_ c
61%/39%
_ c
_ c
1998
16,280
32%
16,497
_ c
61%/39%
_ c
_ c
1999
14,057
28%
14,057
_ c
53%/47%
_ c
_ c
2000
12,975
26%
12,992
_ c
50% / 50%
_ c
_ c
2001
13,038
26%
13,060
_ c
53%/47%
_ c
_ c
2002
12,456
28%
12,470
_ c
57%/43%
_ c
_ c
2003
10,704
24%
10,704
_ c
54% / 46%
_ c
_ c
2004
10,485
26%
10,423
_ c
61%/39%
_ c
_ c
2005
9,941
30%
9,895
_ c
58%/42%
_ c
_ c
2006
8,418
29%
8,433
_ c
57%/43%
_ c
_ c
2007
8,586
31%
8,474
_ c
60%/40%
_ c
_ c
2008
11,747
51%
11,871
_ c
65%/35%
_ c
_ c
2009
_ a
_ a
10,396
_ c
68%/32%
_ c
_ c
2010
_ a
_ a
13,009
_ c
75%/25%
_ c
_ c
2011
_ a
_ a
11,182
63%
70%/30%
7,023
80% / 20%
2012
_ a
_ a
10,646
66%
75%/25%
7,021
85% /15%
2013
_ a
_ a
9,866
56%
73%/27%
5,555
87% /13%
2014
_ a
_ a
10,468
56%
75%/25%
5,899
86% /14%
2015
_ a
_ a
10,334
63%
81% /19%
6,528
91% / 9%
2016
_ a
_ a
9,654
67%
84% /16%
6,486
93%/7%
2017
_ a
_ a
10,163
64%
83% /17%
6,490
94%/6%
2018
_ a
_ a
10,674
66%
86% /14%
7,014
95%/5%
a - Data from MMS staff were provided for 1990-2008. Year 2008 data were used as surrogate for years 2009 forward
in the previous GHGI.
b - OGOR-B does not provide data prior to 1996.
b - OGOR-B does not provide separate vented and flared gas volumes prior to 2011.
3,4,2 Considerations for Use in 2020 GHGI Updates
EPA combined the data used in the previous GHGI (based on historical MMS data) and publicly available OGOR-B
datasets to calculate offshore flaring emissions in the updated GHGI. The previous GHGI assigned all offshore
flaring emissions to natural gas systems, and the OGOR-B data allowed for a portion of the flaring emissions to be
attributed to offshore oil production within petroleum systems in the 2020 GHGI updates.
EPA generally used the previous GHGI data for years 1990-2008 and OGOR-B data for subsequent years.
Combining the previous GHGI and OGOR-B datasets required two assumptions to estimate separate natural gas
and petroleum offshore flaring emissions over the time series. First, for years 1990 through 2010 (when the
percent of flared gas from gas versus oil complexes is not available), EPA applied the year 2011 values (80% of
14
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April 2020
flared gas is from oil complexes and 20% of flared gas is from gas complexes). Second, the volume of flared gas is
not directly available for years 2009 and 2010, and EPA linearly interpolated between the 2008 and 2011 volumes.
The resulting flared gas volumes are presented in Figure 6.
EPA also created a consistent approach to calculate flaring C02, CH4, and N20 emissions and used flared gas
volumes to estimate each. The previous GHGI included flaring CH4 emissions within the EFs shown in Table 1 and
did not calculate flaring N20 emissions. The flaring C02 EF is discussed in Section 2.2 (54.7 kg/mmBTU) and EPA
applied a CH4 EF of 0.057 kg/MMBtu and an N20 EF of 0.00091 kg/MMBtu to the flared gas volumes. The CH4 and
N20 EFs are used in the BOEM GEI calculation methodology. These EFs were adjusted each year using the natural
gas heat content, as discussed in Section 2.2.
OGOR-B data are specific to GOM offshore facilities in federal waters, therefore EPA applied other approaches to
estimate offshore flaring emissions for GOM state waters, Pacific, and Alaska regions (see Sections 4.2 and 4.3).
3.5 GHGRP
This section summarizes the scope and available data from EPA's GHGRP dataset and how EPA used the data in
the updated methodology for the 2020 GHGI.
3.5.1 Scope and Available Data
Offshore petroleum and natural gas production facilities (referred to as "offshore production facilities" in this
memo) are defined in the GHGRP as: Any platform structure, affixed temporarily or permanently to offshore
submerged lands, that houses equipment to extract hydrocarbons from the ocean or lake floor and that processes
and/or transfers such hydrocarbons to storage, transport vessels, or onshore. In addition, offshore production
includes secondary platform structures connected to the platform structure via walkways, storage tanks
associated with the platform structure and floating production and storage offloading equipment (FPSO). This
source category does not include reporting of emissions from offshore drilling and exploration that is not
conducted on production platforms. "Offshore" is defined as: Seaward of the terrestrial borders of the United
States, including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally
standing waters, and extending to the outer boundaries of the jurisdiction and control of the United States under
the Outer Continental Shelf Lands Act.
GHGRP subpart W requires offshore production facilities meeting the reporting threshold (25,000 mt C02e) to
report C02, CH4, and N20 emissions from equipment leaks, vented emission, and flare emission source types as
identified in the BOEM GEI data collection and emissions estimation study. Offshore production facilities under
BOEM jurisdiction report the same annual emissions as calculated and reported in the BOEM GEI; offshore
production facilities that are not under BOEM jurisdiction are still required to use the monitoring and calculation
methods used in the most recent BOEM GEI publication.
The BOEM GEI study is updated and published triennially (to coincide with the EPA and state agency onshore
criteria pollutant inventory process). For any calendar year that does not overlap with the most recent published
BOEM GEI study and/or methods, GHGRP reporters must employ the most recently published study estimates or
methods, then adjust emissions based on the operating time for the facility relative to operating time in the
previous reporting or calculation period.
For fuel combustion emissions, GHGRP offshore production facilities report C02, CH4, and N20 emissions using
methodologies specified in subpart C.
In addition to emissions data, GHGRP offshore production facilities annually report production volumes beginning
in RY2015, specifically: (1) total quantity of gas handled at the offshore facility in the calendar year, in thousand
15
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April 2020
standard cubic feet (mscf), including production volumes and volumes transferred via pipeline from another
location; and (2) total quantity of oil and condensate handled at the offshore facility in the calendar year, in
barrels (bbl), including production volumes and volumes transferred via pipeline from another location.
Table 12 provides an overview of the GHGRP offshore production and emissions reported for RY2015 through
RY2018.
Table 12. GHGRP Offshore Emissions and Production Reporting Overview
Data
2015
2016
2017
2018
# Facilities
133
137
141
142
Gas production (Bscf)
1,355
1,344
1,651
1,613
Oil/condensate production (MMbbl)
506
563
616
638
Subpart W Vent and Leak Emissions
Cm (mt)
69,269
71,917
61,248
70,291
CO2 (mt)
21,678
55,147
52,688
70,676
N2O (mt)
0
0
0
0
Subpart W Flare Emissions
CH4 (mt)
937
1,106
723
726
CO2 (mt)
459,434
457,617
355,880
376,010
N2O (mt)
12
11
6
6
Subpart C Emissions
CH4 (mt)
99
98
101
105
3,5,2 Considerations for Use in 2020 GHGI Updates
Due to the reporting threshold, GHGRP data generally reflect less than 10 percent of all U.S. offshore production
facilities, though coverage varies by region. Emission factors and assumptions based on GHGRP reporters may not
be representative of offshore production facilities that do not report to GHGRP.
Most GHGRP reported activity is centered in the GOM, with reporters also located in the Pacific (off the coast of
California) and Cook Inlet regions (southern Alaska).
Most of the offshore facilities reporting in RY2017 are located in federal waters. All reporting facilities in the
Pacific are in federal waters, and most (if not all) of the reporting facilities in the GOM are in federal waters; while
all reporting facilities in Alaska are located in state waters. While the GHGRP dataset coverage overlaps that of the
BOEM GEI (GOM federal waters), the GHGRP provides a unique source of emissions characterization data for the
Pacific and Alaska regions.
EPA calculated year-specific EFs on a production basis using available GHGRP data, including three levels
subcategorization: (1) region (GOM, Pacific, Alaska); (2) production type (gas, oil); and (3) emission type (vent/leak
(including engine exhaust CH4), and flare). To group GHGRP reporters by production type, EPA applied the
standard GHGI approach of assignment by calculating the production GOR in a given year and assigning facilities
with a GOR greater than 100 mcf/bbl as gas and otherwise as oil. Table 13 and Table 14 show the production-
based EFs calculated from GHGRP data for each region. Note, all offshore GHGRP facilities in the Pacific region
were categorized as oil facilities. EPA applied the Pacific and Alaska region EFs in the updated 2020 GHGI
calculation methodology, see further discussion in Section 4.3.
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Table 13. Year-specific EFs Calculated from GHGRP Data for Offshore Oil Facilities
Region/Emission
Type/Pollutant
2015
2016
2017
2018
GOM
Vent and Leak EFs (mt/MMbbl)
ch4
123
120
90
100
co2
1.6
1.6
1.9
1.1
Flare EFs (mt/MMbbl
ch4
1.7
1.6
0.7
0.7
CO2
818
709
471
485
n2o
0.02
0.02
0.01
0.01
Pacific
Vent and Leak EFs (mt/MMbbl)
ch4
421
283
309
409
CO2
124
3.0
3.1
4.7
Flare EFs (mt/MMbbl
ch4
0.7
0.6
0.8
0.7
CO2
1,188
623
821
685
n2o
0.01
0.01
0.01
0.01
Alaska
Vent and Leak EFs (mt/MMbbl)
cm
461
468
598
479
CO2
4.6
4.4
4.0
1.6
Flare EFs (mt/MMbbl
cm
8.2
6.4
3.0
6.4
CO2
7,647
6,004
5,919
6,035
n2o
0.1
0.1
0.1
0.1
Table 14. Year-specific EFs Calculated from GHGRP Data for Offshore Gas Facilities
Region/Emission
Type/Pollutant
2015
2016
2017
2018
GOM
Vent and Leak EFs (mt/Bcf)
cm
9.2
4.5
4.0
3.8
CO2
40
126
64
82
Flare EFs (mt/Bcf)
cm
0.1
0.5
0.3
0.3
CO2
29
82
57
50
n2o
0.0002
0.0003
0.0002
0.0002
Alaska
Vent and Leak EFs (mt/Bcf)
cm
20
34
25
29
CO2
0.10
0.01
0.00
0.02
Flare EFs (mt/Bcf)
cm
0.16
0.16
0.004
0.08
CO2
208
150
177
90
n2o
0.004
0.003
0.003
0.002
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April 2020
3.6 Oilier Activity Data
The above sections discuss the extensive data available mainly for offshore facilities in GOM federal waters. This
section discusses the activity data available for the other offshore production regions, including GOM state
waters, and federal and state waters in the Pacific and Alaska. EPA reviewed available activity data on the basis of
both offshore facility counts and production volumes and incorporated the production data into the updated
2020 GHGI methodology.
3.6.1 GOM State Waters Activity Data
Offshore production in GOM state waters occurs in coastal areas off the states of Alabama, Louisiana, and Texas.
The Oil and Gas Board of Alabama (AL OGB) provides a list of all wells for the state, including offshore.19 A map of
offshore facilities off of Louisiana is available from the Louisiana Department of Wildlife and Fisheries,20 and
detailed well data are available through the Department of Natural Resources' online database - Strategic Online
Natural Resource Information System (SONRIS).21 The Texas General Lands Office provides GIS files for offshore
facilities.22 These datasets may allow EPA to estimate the number of currently operating offshore facilities in GOM
state waters, but it did not appear possible to develop such facility counts over the entire GHGI time series and
EPA did not use these data in the 2020 GHGI updates.
EPA also reviewed the production data available for GOM state waters. Each state provides both oil and gas
production online, in various forms. The AL OGB considers all offshore production to be from gas wells (based on
the aforementioned offshore wells data, wherein all offshore data are labeled as "gas").23 The Louisiana
Department of Natural Resources and the Texas Railroad Commission report oil and gas production from gas wells
and oil wells separately.24,25 Note, while gas and oil wells in these datasets may not be defined in the same
manner as the GHGI convention (using a GOR threshold of 100 mcf/bbl), this production type designation offers
an improvement versus assigning all production (and hence emissions) to either natural gas or petroleum
systems, or making other assumptions to distinguish between natural gas and petroleum systems production.
Limited offshore gas production data for these states are also available from El A; however, the data are of
insufficient detail to fully assess GOM state waters oil production.26 Each of the state agency datasets provide
production data over most of the GHGI time series.
Figure 7 and Figure 8 present the offshore oil and gas production data for GOM state waters. EPA applied the
relationship between emissions and production for complexes in the OCS of the GOM to estimate emissions for
complexes in state waters of the GOM (see Section 4.2 for further discussion).
3.6.2 Pacific Federal and State Waters Activity Data
Offshore production occurs in federal and state waters off the coast of California (Pacific region). The California
State Lands Commission provides information on state water facility counts. There are nine offshore production
facilities in state waters; four offshore oil facilities and five artificial islands.27 Federal waters facilities are under
BOEM jurisdiction, and there are 23 active offshore facilities in federal waters of the Pacific based on the BOEM
Pacific Platform Database (analogous to the BOEM Platform Database covering GOM activity discussed in Section
19 https://www.gsa.state.al.us/ogb/wells
20 http://ldwf.maps.arcgis.com/apps/webappviewer/index.html?id=a71d6758535042dd969114fb6a356888
21 http://www.sonris.com/
22 http://www.glo.texas.gov/land/land-management/gis/
23 https://www.gsa.state.al.us/ogb/production
24 http://www.dnr.Iouisiana.gov/index.cfm?md=pagebuilder&tmp=home&pid=206
25 http://webapps.rrc.state.tx.us/PDQ/generalReportAction.do
26 http://www.eia.gov/dnav/ng/ng_prod_sum_a_epgO_fgw_mmcf_a.htm
27 https://www.slc.ca.gov/lnfo/Oil_Gas.html
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April 2020
3.2).28 Each of the active federal water facilities was installed prior to 1990 and consists of a single, major
structure; there is one federal water facility that was removed in 1994.
Pacific region state waters production data are available from annual reports published by the State Oil and Gas
Supervisor in the California Department of Conservation29 and Pacific region federal waters production data are
available from BOEM30 and El A.3132 For Pacific region federal waters production, EPA used EIA data for 1990-1995
and BOEM data for all subsequent years. EPA also assigned all Pacific federal waters and state waters production
to oil facilities (Petroleum Systems segment); data are not available for all years to distinguish between gas and oil
facility production, and for the years when this can be determined gas facilities account for a small percent of gas
production (from 0%-10%). Figure 9 shows the offshore oil production data for the Pacific region. EPA applied an
approach to estimate emissions for the Pacific region that relies on production data in conjunction with GHGRP-
based EFs (see Section 4.3 for further discussion).
3,6,3 Alaska State Waters Activity Data
At this time, offshore production occurs only in state waters off the coast of Alaska, as noted in Section 1.2. There
are two state waters offshore production regions—the Cook Inlet in the south and Beaufort Sea in the north. The
Alaska Oil and Gas Conservation Commission (AOGCC) provides information on state water offshore well counts
and production.33,34
Figure 10 shows the offshore oil and gas production data for Alaska. The AOGCC dataset includes onshore and
offshore; EPA estimated the offshore production by summing the production for the API well IDs that are noted as
being offshore within the AOGCC well dataset. EPA applied an approach to estimate offshore production
emissions for Alaska that uses production volumes as the activity data component in conjunction with GHGRP-
based EFs (see Section 4.3 for further discussion).
4 Updated Methodology and National Emissions Estimates for Offshore
Production in the 2020 GHGI
The subsections below discuss the EF and activity data updates implemented in the 2020 GHGI, organized by
region, and summarized in Table 15.
Table 15. Approaches for 2020 GHGI Updates, by Offshore Region
Region
Memo
Section
EF Basis
Activity Data Basis
GOM federal waters
4.1
BOEM GEI, complex-level emission source
EFs
BOEM Platform Database complex counts
GOM state waters
4.2
GOM federal waters production-based EFs
State-specific offshore production data
Pacific federal and state
(California) waters
4.3
GHGRP (facilities in Pacific region),
production-based EFs
Pacific federal and state offshore
production data
Alaska state waters
4.3
GHGRP (facilities in Alaska region),
production-based EFs
Alaska state offshore production data
28 https://www.data.boem.gov/Main/PacificPlatform.aspx
29 https://www.conservation.ca.gov/dog/pubs_stats/annual_reports/Pages/annual_reports.aspx
30 https://www.data.boem.gov/Main/PacificProduction.aspx
31 http://www.eia.gov/dnav/ng/ng_prod_sum_a_epgO_fgw_mmcf_a.htm
32 http://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm
33 http://aogweb.state.ak.us/DataMiner3/Forms/WellList.aspx
34 http://aogweb.state.ak.us/DataMiner3/Forms/Production.aspx
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There is a particular consideration for GHGI updates to offshore production emissions in state waters that applies
across regions. EPA understands near-shore offshore production might include minimal offshore processing
operations, with the production stream piped or shipped to centralized onshore facilities where most of the
production segment processing occurs. However, EPA identified very limited data characterizing emissions and
activity for such operations that likely fall within state waters. As described further within this section, EPA
therefore developed region-specific, production-based EFs from facilities in federal waters and/or reporting to
GHGRP (which likely have higher per-facility emissions than facilities in state waters or not reporting to GHGRP),
and applied such EFs to production in state waters. This effectively estimates emissions from state waters
operations by scaling based on production relative to that in federal waters and/or from GHGRP facilities (refer to
Figure 1 for production volumes by region in year 2017). EPA considered an alternative of using a complex-level EF
developed from these facilities but believes such an approach might overestimate emissions from state water
operations; additionally, state water production data are readily available, while state water active complex
counts are not.
ore Producl "' cleral Waters
This section summarizes the approach implemented in the 2020 GHGI for estimating emissions (EFs multiplied by
activity data) from offshore production in GOM Federal waters.
;fs
EPA applied year-specific, emission source EFs at the complex level (i.e., emissions per complex) developed from
the BOEM GEI dataset (see Table 6 through Table 8) to estimate vent and leak emissions (including engine exhaust
CH4) over the GHGI time series for major complexes, rather than applying the 2011 BOEM GEI EFs to all time
series years as in the previous GHGI (refer to Section 2). EPA specifically developed an approach for major
complexes where the BOEM GEI-based EFs for a particular year were generally used for the Inventory years on
either side of the BOEM GEI year that provides the EF, as follows:
• EFs calculated from the 2005 BOEM GEI were applied to year 2005 only (due to the hurricane season
impact, discussed in Section 3.1.1);
• EFs calculated from the 2008 BOEM GEI were applied to 1990 through 2004 and 2006 through 2009;
• EFs calculated from the 2011 BOEM GEI were applied to 2010 through 2012;
• EFs calculated from the 2014 BOEM GEI were applied to 2013 through 2015;
• EFs calculated from the 2017 BOEM GEI were applied to 2016 through 2018.
For minor complexes, EPA applied the 2014 and 2017 BOEM GEI minor complex emission source EFs (see Table 6,
Table 9, and Table 10) to estimate vent and leak emissions (including engine exhaust CH4). This consideration is
due to changes in BOEM GEI reporting requirements over time; as discussed in Section 3.1.1, the 2014 GEI is the
first year in which emissions from minor source structures are fully accounted for in the GEI. EPA applied minor
complex EFs calculated from the 2014 BOEM GEI to 1990 through 2015 and minor complex EFs calculated from
the 2017 BOEM GEI to 2016 through 2018.
EPA maintained the previous GHGI approach to estimate flaring emissions, wherein EFs on the basis of kg/MMBtu
(along with year-specific heat content) were applied to OGOR-B flared gas volumes over the time series—see
Sections 2.2 and 3.4.2. While the previous GHGI only estimated flaring C02 emissions using this approach, EPA
also estimated flaring CH4 and N20 emissions using the OGOR-B flaring volumes.
4.1.2 Activity Data
EPA developed an updated approach to estimate active GOM federal waters complex counts to pair with BOEM
GEI EFs discussed in Section 4.1.1. As discussed in Section 2.1, the previous GHGI activity data relied on an MMS
dataset that had not been updated since 2010, and EPA has recently identified opportunities to improve
subcategorization of EFs and thus applicable activity data, based on stakeholder feedback. EPA used the BOEM
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April 2020
Platform Database (discussed in Section 3.2) to count total active complexes, subcategorized by major versus
minor complexes over the time series; details of this approach are discussed in Section 3.2.2. EPA then used the
BOEM OGOR-A Production Dataset to further subcategorize complexes as gas versus oil production; details of this
approach are discussed in Section 3.3.2. Figure 11 presents the resulting complex counts over the time series,
compared to the facility counts in the 2019 GHGI.
EPA estimated offshore flared gas volumes over the time series by relying on both the historical activity data
provided by MMS staff (used in the previous GHGI) and publicly available OGOR-B data. Details of this approach
are discussed in Section 3.4.
Emissions
Figure 12 Figure 13 show the total CH4 emissions and C02 emissions, respectively, for the 2020 GHGI updates for
GOM federal water offshore production facilities, compared to the 2019 GHGI emissions (which also solely
represent GOM federal water emissions). The updates for the 2020 GHGI for GOM federal water offshore facilities
did not change the GOM federal water offshore production CH4 emissions for petroleum systems in year 2017 and
resulted in an average increase of 43% over the 1990-2017 time series (with most of the increase occurring over
the 1990-2009 time frame). The updates resulted in an 87% decrease in GOM federal water offshore production
CH4 emissions for natural gas systems in year 2017 and an average decrease of 27% over the 1990-2017 time
series. Total CH4 GOM federal water offshore production emissions decreased by 39% for year 2017 and increased
by 11% on average over the 1990-2017 time series for the 2020 GHGI updates compared to the 2019 GHGI. GOM
federal waters offshore production total C02 emissions increased by 6% for year 2017 and the annual average
over the 1990-2017 time series did not change.
4.2 Offffsliore Producl ite Waters
As explained in the introduction to Section 4, EPA understands near-shore offshore production might include
minimal offshore processing operations, with the production stream piped or shipped to centralized onshore
facilities where most of the production segment processing operations occur. However, EPA identified very
limited data characterizing emissions and activity for such operations that likely compose some fraction of activity
within state waters. EPA therefore estimated emissions from offshore production in GOM state waters using
production-based EFs developed from GOM federal water data, in conjunction with state-specific offshore oil and
gas production.
4.2.1 EFs
EPA developed production-based emission source EFs for each year of the time series from the GOM federal
waters data. EPA calculated EFs by dividing the GOM federal waters emissions for an emission source by the GOM
federal waters production in each year. The production basis was also unique for oil complexes and gas
complexes; oil production was used in the numerator for oil complexes and gas production was used in the
numerator for gas complexes.
4.2.2 Activity Data
EPA used annual state-specific offshore production (discussed in Section 3.6.1) paired with the EFs discussed in
Section 4.2.1 to calculate emissions. Similar to the EF basis, oil production was used for oil complexes and gas
production was used for gas complexes.
4.2.3 Emissions
Figure 14 and Figure 15 show the GOM state waters total CH4 emissions and C02 emissions, respectively, for the
2020 GHGI updates.
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April 2020
4.3 Offffsliore Producl iclfic ami Alaska Regions
As explained in the introduction to Section 4, EPA understands there are limitations to the available data for the
offshore Pacific and Alaska regions to characterize all offshore production emissions in these regions. However,
EPA used reported GHGRP data (refer to Section 3.5) to calculate production-based EFs, to be used in conjunction
with region-specific offshore oil and gas production.
4.3.1 EFs
EPA applied the GHGRP production-based EFs shown in Table 13 and Table 14 to estimate emissions from facilities
in the Pacific and Alaska regions. The GHGRP RY2015 EFs were applied to all prior years in the GHGI time series.
The production basis was also unique for oil complexes and gas complexes; oil production was used in the
numerator for oil complexes and gas production was used in the numerator for gas complexes.
4.3.2 Activity Data
EPA used year-specific, region-specific offshore production (discussed in Sections 3.6.2 and 3.6.3) to pair with the
EFs discussed in Section 4.3.1 to estimate emissions over the time series. Similar to the EF basis, oil production
was used for oil complexes and gas production was used for gas complexes.
4.3.3 Emissions
Figure 16 and Figure 17 show the total CH4 emissions and C02 emissions, respectively, for the 2020 GHGI updates
for the Pacific and Alaska regions.
4.4 Emissions Summary
Error! Reference source not found, and Figure 19 show the total offshore production CH4 emissions and C02
emissions, respectively, for the 2020 GHGI updates for each of the production regions, compared to the 2019
GHGI emissions.
For the 2020 GHGI updates, GOM federal waters offshore facilities account for a majority of the offshore
production emissions in both petroleum systems (offshore oil facilities) and natural gas systems (offshore gas
facilities). For offshore oil production, in year 2017, GOM federal waters offshore facilities account for 91% of CH4
emissions, 74% of C02 emissions, and 72% of N20 emissions. Alaska region offshore oil facilities contribute 6% of
offshore oil production CH4, 23% C02 emissions and 25% of N20 emissions. Offshore facilities in the Pacific region
and in GOM state waters each contribute less than 3% of emissions of CH4, C02, or N20 from offshore oil
production. For offshore gas production, in year 2017, GOM federal waters facilities account for 70% of CH4
emissions, 64% of C02 emissions, and 64% of N20 emissions. GOM state waters contribute 28% of CH4 emissions,
26% of C02 emissions, and 26% N20. Table 16 presents the offshore production CH4, N20, and C02 emissions for
each region in year 2017 for the 2020 GHGI updates and the 2019 GHGI.
Compared to the 2019 GHGI, petroleum systems offshore production CH4 emissions increase overall for the 2020
GHGI updates, while natural gas systems offshore production CH4 emissions decrease overall for the 2020 GHGI
updates. Compared to the 2019 GHGI, offshore production C02 emissions increase overall for the 2020 GHGI
updates. Petroleum systems offshore production flaring C02 emissions also constitute approximately 90% of the
total flaring C02 emissions for the 2020 GHGI updates, whereas the 2019 GHGI assigned all offshore production
flaring C02 emissions to natural gas systems. The 2019 GHGI did not calculate N20 emissions, while the 2020 GHGI
updates calculated flaring N20 emissions for each region. Table 17 shows the percent change between the 2019
GHGI and the 2020 GHGI updates, for year 2017 and on average over the 1990-2017 time series.
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April 2020
Table 16. Offshore Production Year 2017 CH4, C02, and N20 Emissions (mt), by Region, for the 2020 GHGI
Updates and the 2019 GHGI
Emissions Category
Region
2020 GHGI Update
(Year 2017)
2019 GHGI
(Year 2017)
ch4
Petroleum systems
GOM Federal Waters
186,806
187,604
GOM State Waters
1,222
NE
Alaska
12,164
NE
Pacific
5,052
NE
Total
205,243
187,604
Natural gas systems
GOM Federal Waters
19,563
150,565
GOM State Waters
7,995
NE
Alaska
501
NE
Pacific
n/a
n/a
Total
28,060
150,565
C02
Petroleum systems
GOM Federal Waters
379,413
8,340
GOM State Waters
2,482
NE
Alaska
119,963
NE
Pacific
13,440
NE
Total
515,299
8,340
Natural gas systems
GOM Federal Waters
24,564
372,116
GOM State Waters
10,039
NE
Alaska
3,483
NE
Pacific
n/a
n/a
Total
38,085
372,116
l\l20
Petroleum systems
GOM Federal Waters
6.25
NE
GOM State Waters
0.04
NE
Alaska
2.16
NE
Pacific
0.24
NE
Total
8.68
NE
Natural gas systems
GOM Federal Waters
0.40
NE
GOM State Waters
0.16
NE
Alaska
0.06
NE
Pacific
n/a
NE
Total
0.62
NE
NE = Not estimated,
n/a = Not applicable.
Table 17. Percent Change Due to Recalculations in CH4 and C02 Emissions Between the 2019 GHGI and the 2020
GHGI Updates
Emissions Category
Year 2017 Change from 2017
Estimate in Previous GHGI
1990-2017 Time Series Average
Annual Change from Previous GHGI
ch4
Petroleum systems
9%
67%
Natural gas systems
-81%
-14%
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April 2020
Emissions Category
Year 2017 Change from 2017
Estimate in Previous GHGI
1990-2017 Time Series Average
Annual Change from Previous GHGI
Total
-31%
31%
C02
Petroleum systems*
6,079%
7,106%
Natural gas systems
-90%
-71%
Total
45%
184%
* In the previous (2019) GHGI, all C02 emissions from flaring were reported under Natural Gas
Systems.
5 Requests for Stakeholder Feedback
EPA sought stakeholder feedback on the approaches under consideration discussed in the September 2019
memorandum. The questions below were not updated for this memorandum and are copied from the September
2019 memorandum. In response to the memo and public review draft emissions for the 2020 GHGI, stakeholders
provided feedback on the offshore production approaches, and their feedback is summarized here:
• Stakeholders generally supported the update to offshore oil and gas production emissions calculations,
including updating the activity data and EFs.
• Stakeholders suggested clarification on how complexes were assigned to oil and gas production,
specifically how to interpret Table 4 in the September 2019 memo. Clarification has been provided in an
updated version of Table 4, to emphasize that assigning each complex in the BOEM GEI dataset to oil or
gas production was based on data specific to that year (where possible) and that BOEM GEI datasets were
not consolidated or combined in any manner when calculating EFs.
• A stakeholder suggested clarification on the data source used to calculate emission factors for each
region. Clarification has been provided in Table 15, which identifies whether EFs were based off BOEM GEI
or GHGRP data.
• A stakeholder supported considering an approach that would use source-specific emission factors.
Additional information on source-specific emission factors calculated from BOEM GEI data are presented
in Table 7 through Table 10. Additionally, source-specific emission factors for each region are available in
the Annex Excel files.35
• A stakeholder expressed concern that the use of emission factors calculated from data from the GHGRP
reporting population (those emitting over the GHGRP threshold), applied to all Pacific and Alaska offshore
production could skew regional emission estimates. EPA applied the GHGRP EFs for these regions;
alternative data sources are unavailable.
• A stakeholder supported the use of GEI data as opposed to OGOR-B data to calculate flaring emissions.
This was considered but EPA applied the OGOR-B data because it is more readily available across the full
time series. EPA is aware the BOEM GEI studies may be updated more frequently in the future, and will
assess the data as it becomes available.
• A stakeholder noted upcoming availability of emissions data for offshore production. This feedback has
been noted in the Planned Improvements section of the GHGI.
General
1. EPA seeks stakeholder feedback on the proposed approach of calculating vent and leak EFs that include
emissions from all equipment at an offshore facility (except for flares), versus calculating emission source-
specific EFs. For consideration, Section 3.1.1 documents the emission sources included in the BOEM GEI-
based complex-level vent and leak EFs.
35 Annexes for the 1990-2018 Inventory are available at https://www.epa.gov/ghgemissions/natural-gas-and-petroleum-systems.
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2. The 2020 GHGI updates under consideration show a noticeable decrease in CH4 emissions over the time
series (see Figure 18). EPA seeks feedback on the trend, including information on changes in offshore
production practices over time that may have contributed to the trend.
Region-specific Approaches Under Consideration
3. GOM Federal Waters: EPA seeks feedback on the datasets and approach under consideration to estimate
offshore production emissions in GOM federal waters using BOEM GEI data. This includes feedback on the
following:
a. The approach to develop complex-level EFs from BOEM GEI data for each subcategory (i.e., oil
and gas complexes, major and minor complexes).
b. The approach for applying the BOEM GEI EFs over the time series, including applying BOEM GEI
2008 EFs to all prior years (except for 2005).
i. Applying the 2005 GEI EFs to prior years of the time series was not considered due to the
hurricane season impact (see Section 3.1.1).
c. The approach to estimate complex counts over the time series using the BOEM Platform Database
and OGOR-A data.
4. GOM Federal Waters Flaring: EPA seeks feedback on the two approaches under consideration to
estimate offshore production flaring emissions in GOM federal waters; applying GEI-based EFs (as shown
in Table 7) versus OGOR-B based flaring volumes.
a. If OGOR-B flaring volume data are used in the update, two options are presented in Section 3.4.2.
Option A is used to estimate emissions for this memo, but EPA seeks feedback on the
assumptions applied for each option and which option is most appropriate to apply, or whether a
different methodology should be applied.
b. Regarding flaring volumes, EPA notes some discrepancies between GEI and OGOR-B flaring
volumes. The GEI flaring volumes (used to calculate the GEI-based EFs) are higher than OGOR-B
flaring volumes in certain years but lower in other years, see the following table. EPA seeks
stakeholder feedback on these discrepancies.
Year
BOEM GEI Flared Gas
Volumes (Bcf)
OGOR-B Flared Gas
Volumes (Bcf)
2000
2.5
3.4
2005
5.1
3.0
2008
7.0
6.0
2011
10.0
7.0
2014
5.1
5.9
5. GOM State Waters, Pacific, and Alaska Regions: EPA seeks feedback on the datasets and approaches
under consideration to estimate offshore production emissions in these regions, specifically:
a. GOM state waters emissions estimates relying on GOM federal waters production-based EFs.
b. How to characterize operations and emissions from offshore production in GOM state waters. As
discussed in Section 4, EPA understands near-shore offshore production might include minimal
offshore processing operations, with the production stream piped or shipped to centralized
onshore facilities where most of the production segment processing occurs. However, EPA
identified very limited data characterizing emissions and activity for such operations that likely fall
within state waters.
c. Pacific federal and state waters emission estimates relying on GHGRP production-based EFs.
d. Alaska state waters emission estimates relying on GHGRP production-based EFs.
e. Whether data are available for EPA to consider an approach wherein facility counts, rather than
production volumes, could be used as the activity basis for emissions estimates in these regions.
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Other Considerations
6. EPA seeks stakeholder feedback on the potential utility of using Drillinglnfo Dl Desktop well-level data to
estimate oil and gas production in each offshore production region for each year of the time series (under
a scenario wherein production-based EFs were used in GHGI updates). The use of this data source would
provide benefits including: (1) consistency with the data source for onshore production volumes
underlying current GHGI estimates; (2) data processing efficiency compared to the current approach
under consideration that involves mining various individual state datasets. If stakeholder feedback
supports such an approach, EPA would develop draft methodologies, compare results to current state
dataset-based estimates, and share results with stakeholders for additional consideration.
7. EPA seeks feedback on how to track and estimate emissions from anomalous leak events occurring in
offshore producing regions, for example the Cook Inlet underwater gas pipeline rupture that occurred in
late 2016/early 2017 and released natural gas for multiple months.
8. EPA seeks stakeholder information on other available or upcoming data related to offshore oil and gas
emissions. For example, EPA is aware of a number of measurement studies in the Gulf of Mexico. EPA
seeks stakeholder information on how information from these studies may be used to assess or update
the GHG Inventory estimates.
26
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April 2020
Appendix A - Memo Figures
Offshore Gas Production (BCF) Offshore Oil Production (MMBBL)
Pacific (CA) - Federal ¦ Pacific (CA) - State Pacific (CA) - Federal ¦ Pacific (CA) - State
Figure 1. Overview of U.S. Offshore Gas Production (BCF) and Oil Production (MMBBL), Year 2017
300
¦ 2005 Complex EF
¦ 2008 Complex EF
Gas Major Oil Major Gas Minor Oil Minor
Figure 2. Complex-Level Vent and Leak CH4 EFs (mt/yr) Calculated from BOEM GEI Data
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April 2020
O
o
7
6
5
4
3
2
1
0
Gas Major Oil Major Gas Minor Oil Minor
Figure 3. Complex-Level Vent and Leak CO2 EFs (mt/yr) Calculated from BOEM GEI Data
¦ 2005 Complex EF
¦ 2008 Complex EF
¦
¦
¦ 2011 Complex EF
¦ 2014 Complex EF
¦ 2017 Complex EF
1
¦
¦
J
J
1-
100%
90%
£ 80%
x
a>
Q.
£
o
u
15
+->
,o
70%
60%
50%
40%
£ 30%
u
i_
(L)
Q_ 20%
10%
0%
% Oil Complexes
% Gas Complexes
o
en
cn
rsj
cn
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April 2020
3,500
3,000
2,500
2,000 ,-tt
1,500
1,000
o
Csl
^r
UD
00
o
fN
00
O
rsj
^r
00
cn
cn
cn
cn
cn
o
O
o
O
O
T—1
T—1
T—1
T—t
r—1
cn
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April 2020
Figure 7, Offshore Oil Production from Oil Facilities in GOM State Waters
250
CD
CD
_Q
13
U
c
o
Alabama
—Louisiana
—Texas
200
150
o
ru
TO
O
E
o
v_
4—
c
o
13
~o
o
ru
C3
100
50
o
en
c7)
rsl
cr>
en
<3-
en
cn
UD
cr>
CT)
CO
cn
cn
o
o
o
rsl
O
O
rsl
«sT
O
O
fsJ
•X)
O
O
CM
00
o
o
CM
o
rsl
O
CM
O
rsl
O
rsl
O
rsl
Figure 8. Offshore Gas Production from Gas Facilities in GOM State Waters
30
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April 2020
Figure 9. Pacific Federal and State Waters Oil Production from Oil Facilities
150
—Oil Prod
—Gas Prod
135 gj
4—
O
120 -§
u
c
o
105 =
90 &
75
60
45
30
15
u
03
OJ
c
o
4-J
o
=5
"O
o
03
CD
o
rsi
^r
CD
00
o
rsi
"3"
CD
00
O
(N
<3*
CD
00
CD
cn
CD
cn
cn
o
o
O
O
O
r-H
r—1
T—1
t-H
rH
cn
0">
CD
cn
cn
o
o
o
O
O
o
O
o
o
O
T—1
t-H
r—1
*—i
tH
CM
rsi
fN
rsi
(N
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April 2020
3,500
3,000
in
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April 2020
350
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018
2020 GHGI Update - Oil Facilities 2020 GHGI Update - Gas Facilities
2019 GHGI - Oil Facilities 2019 GHGI - Gas Facilities
Figure 12, GOM Federal Waters Offshore Production CH4 Emissions by Production Type (Oil and Gas Facilities)
for 2020 GHGI Update Compared to 2019 GHGI Emissions
450
400
350
i 7 /
i 1 \ /
S- 300
LO
c
1 250
E
UJ
^ 200
u
/¦*\
/ »
il \ /
il \ /
il \ /
/ \
/ \
1 \
/ \
/ /\ \
' / Y*
/ / \ \
> ' / \ X
\ / / \ \
\ / / \ ' " *
\ / / \ \ ;
^\\ // ,-v
| 150
Y" / y-'"
100
50
0
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018
2020 GHGI Update - Oil Facilities 2020 GHGI Update - Gas Facilities
2019 GHGI - Oil Facilities 2019 GHGI - Gas Facilities
Figure 13. GOM Federal Waters Offshore Production C02 Emissions by Production Type (Oil and Gas Facilities)
for 2020 GHGI Update Compared to 2019 GHGI Emissions
33
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April 2020
Figure 14. GOM State Waters Offshore Production CH4 Emissions for 2020 GHGI Update
30
¦ Gas Facilities
¦ Oil Facilities
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018
Figure 15. GOM State Waters Offshore Production C02 Emissions for 2020 GHGI Update
34
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April 2020
Figure 16. Pacific and Alaska Region Offshore Production CH4 Emissions for 2020 GHGI Update
Figure 17. Pacific and Alaska Region Offshore Production C02 Emissions for 2020 GHGI Update
35
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April 2020
700
¦ 2020 GHGI Update - Petroleum Systems
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018
Figure 18. Offshore Production Total CH4 Emissions For 2020 GHGI Updates Compared to 2019 GHGI Emissions
1,200
¦ 2020 GHGI Update - Petroleum Systems
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018
Figure 19. Offshore Production Total C02 Emissions For 2020 GHGI Updates Compared to 2019 GHGI Emissions
36
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