September 2019
Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2018:
Updates Under Consideration for Offshore Production Emissions
1 Background
As an outcome to finalizing EPA's 2018 Inventory of U.S. Greenhouse Gas Emissions and Sinks (GHGI), EPA released
a memo to document updates still under consideration for improving estimates, including for sources within the
offshore production segment: Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2016: Additional
Revisions Considered for 2018 and Future GHGIs (April 2018)1 ("Additional Revisions memo"). This memo builds
upon those analyses and presents considerations for updating offshore production emissions estimates in natural
gas systems and petroleum systems. All figures within this memo (i.e., Figure 1 through Figure 19) are shown in
Appendix A.
diistry 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, fugitive 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 2014
(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.
2 Overview of Current GHGI Methodology
EPA most recently updated the GHGI methodology for offshore production emissions in the 2015 GHGI, using
emission factors (EFs) developed from year 2011 BOEM data across the entire time series. The following sections
1 https://www.epa.gov/ghgemissions/natural-gas-and-petroleum-systems-ghg-inventory-additional-information-1990-2016-ghg
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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September 2019
summarize the data sources and methodology for the current GHGI approach to estimating vented and leak
emissions (Section 2.1) and flaring emissions (Section 2.2).
2.1 Vented and Leak Emissions
To calculate vented and leak emissions from offshore production facilities in the 2015 and later GHGIs, 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 GHGI were based on a count of structures, the 2015 GHGI used structure-
based EFs. Table 1 presents the 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 current 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 2015 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
CO; c
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 is 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
water gas, and shallow water oil), based on a nationwide Department of Interior (DOI)/Mineral Management
Service (MMS) facility census. The MMS facility census has not been updated since 2010 (when the agency was
reorganized), so the current GHGI uses year 2010 activity as surrogate for all later time series years. Additionally,
5 https://www.epa.gov/sites/production/files/2015-12/documents/revision-offshoreplatforms-emissions-estimate-4-10-2015.pdf
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September 2019
the MMS data source did not differentiate between active and inactive structures, so all structures in the dataset
were considered active. The current GHGI methodology also does not account for emissions from offshore
structures that are located in state waters or in federal Pacific waters.
2.2 Flaring Emissions
In the current GHGI, EPA calculates 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 are
currently included in the CH4 EFs calculated from the 2011 BOEM GEI data, shown in Table 1. The basis for the C02
estimate is 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 is 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 current GHGI uses 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 current GHGI approach of reporting all offshore C02 flaring emissions under natural gas systems. Similar to
the vented and leak emissions methodology, the current GHGI flaring emissions methodology does 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 current GHGI approach relies 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 current 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 current GHGI methodology uses 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.
illable Data
To calculate offshore production emissions in the upcoming GHGI, EPA is considering several data sources that
provide emissions and/or activity data. The data sources currently under consideration include the BOEM GEI,
BOEM OGOR data, 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. In
Section 5, EPA seeks stakeholder feedback on the appropriateness of and approaches for using these data
sources, and information on other data sources that should be considered for GHGI updates.
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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September 2019
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)
Monthly
Monthly
Monthly
Annual (2011 -
2017)
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 provides
considerations for using the data in updating the 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 calendar years 2000, 2005, 2008, 2011,
and 2014.10 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; fugitive sources (valves, flanges, connectors); glycol dehydrators; losses from flashing; mud
degassing; turbines; pneumatic pumps; pressure and level controllers; storage tanks; and cold vents. Each
8 All existing offshore production facilities in the GOM are located west of 87.5 degrees longitude.
9 The 2014 GEI NTL is available at https://www.boem.gov/BOEM-NTL-No-2014-G01/. Note, this NTL has been superseded by the current
NTL for the 2017 GEI, which 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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September 2019
emission source uses a documented methodology to calculate emissions, and most rely on equations or EFs that
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 GEI study. 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
# Active & Inactive Structures
3,154
1,619
3,304
3,051
1,856
# Active Structures
2,873
1,585
3,026
2,544
1,651
# Non-Reporting Structures (estimate3)
NE
NE
583
538
250
# Active Complexes
2,529
1,407
2,614
2,205
1,397
Flared Volume (MMcf)
2,498
5,104
6,985
10,074
5,123
Vent and Leak Emissions
Cm (mt)
510,014
194,294
383,073
245,838
204,420
CO2 (mt)
8,511
2,160
4,282
4,009
3,394
Flare Emissions
CH4 (mt)
144
296
401
332
301
CO2 (mt)
263b
9,785b
380,186
547,942
278,861
N2O (mt)
<1
0.2
7
10
5
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 plans to take 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
C02 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.
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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September 2019
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 GEI.
• 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 activity (and corresponding calculated emissions),
o Therefore, as discussed in Section 4.1.1, it is likely appropriate to limit application of year 2005
GEI data in the GHGI (e.g., refrain from using 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, it is likely appropriate to exclude year 2000 GEI data from
consideration for GHGI updates.
3.1.2 Considerations for Use in GHGI Updates
The 2011 BOEM GEI is the basis of the current GHGI EFs, but GEIs are available for years 2000, 2005, 2008, 2011,
and 2014. In considering updates for the 2020 GHGI, EPA calculated EFs using each year of the BOEM GEI data to
assess how trends might be reflected over the time series. Additionally, EPA seeks to address stakeholder
feedback received in response to recent GHGI stakeholder memos and workshops/webinars. EPA is considering
updating the EF basis in two ways: (1) switching from a structure-basis to a complex-basis; and (2) establishing EF
subcategories for "major" versus "minor" complexes, instead of the current water depth subcategories. This
section details these and other considerations for updating the 2020 GHGI.
3.1,2, t Complex-level EFs
EPA is considering calculating 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 would be considered as a single unit. Complexes with one or more non-production structures would
also be 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
In response to stakeholder feedback, EPA is considering introducing 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 would replace the current
subcategorization scheme based on water depth, which more indirectly correlates 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 is considering crosswalking 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
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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September 2019
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 has conducted a preliminary analysis and
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 versus minor
complex classifications from the BOEM Platform Database.
3,1,2,3 Facility Production Type Assignment
In reviewing the current GHGI methodology for developing EFs from GEI data, EPA identified an opportunity to
improve estimates by utilizing more of the available GEI data. The current GHGI methodology, as discussed in
Section 2, relies 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. Determining the gas-to-oil ratio (GOR) at the Area and
Area/Block-level and assigning each as oil or gas was evaluated to gap-fill those complexes which could not be
assigned at the lease-level.
The current GHGI oil versus gas assignments for each complex rely on year 2011 data, because the 2011 GEI is the
basis of the EFs. However, EPA evaluated data from additional GEI years and thus 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 is considering a four-step process to assign production type for each complex:
Step 1: Assign production type as oil versus gas based on year-specific lease-level production in OGOR-A
(similar to current 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, considering all
complexes in the GEIs for 2005, 2008, 2011, and 2014.13
13 Table 4 does not provide unique complex counts (that information is available in Table 3). Rather, if a complex reports to each of the four
GEIs, it would be counted four times in Table 4.
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September 2019
Table 4. Number of GEI Complexes Assigned to Oil versus Gas, by Data Processing Step
Data Processing Step
# Complexes Assigned
to Oil in Step
# Complexes Assigned
to Gas in Step
Step 1: Year-Specific Lease-
Level Production
7,789
3,185
Step 2: Nearest-Year Lease-
Level Production
375
476
Step 3: Area/Block-Level
Production
104
54
Step 4: Area-level Production
275
196
Total Complexes
8,543
3,911
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, including the number of complexes with flares, is shown in Table
5. EPA calculated EFs for the 2005, 2008, 2011, and 2014 GEIs on a complex basis for each subcategory; vent and
leak EFs are in Table 6 and flaring EFs are in Table 7. Vent and leak CH4 EFs and flaring C02 EFs (the dominant
emission categories) are depicted in Figure 2 and Figure 3. 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
2005
2008
2011
2014
#
Complexes
#
Complexes
w/Flares
#
Complexes
#
Complexes
w/Flares
#
Complexes
#
Complexes
w/Flares
#
Complexes
#
Complexes
w/Flares
Gas
Major
438
5
487
14
319
14
181
6
Oil
Major
791
52
845
76
728
81
660
52
Total
Major
1,229
57
1,332
90
1,047
95
841
58
Gas
Minor
69
4
418
4
360
4
110
4
Oil
Minor
107
4
844
5
780
8
444
9
Total
Minor
176
8
1,262
9
1,140
12
554
13
Total Used in EF Calcs
1,405
65
2,594
99
2,187
107
1,395
71
Total Reported to GEIa
1,407
65
2,614
99
2,205
108
1,397
71
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 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)
CH„
Gas / Major
91
256
123
113
Oil / Major
183
285
265
252
Gas / Minor
39
12
13
35
Oil / Minor
66
14
12
30
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September 2019
Pollutant/Facility
Subcategory
2005 Complex EF
(mt/yr)
2008 Complex EF
(mt/yr)
2011 Complex EF
(mt/yr)
2014 Complex EF
(mt/yr)
CO;
Gas / Major
0.8
2.9
2.2
1.4
Oil / Major
2.2
3.2
4.2
4.4
Gas / Minor
0.1
0.1
0.4
0.7
Oil / Minor
0.5
0.2
0.2
0.4
Table 7. Complex-Level Flaring 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)
CH4
Gas / Major
<0.005
0.01
0.01
0.01
Oil / Major
0.35
0.44
0.43
0.37
Gas / Minor
<0.005
0.01
<0.005
<0.005
Oil / Minor
0.14
0.02
0.02
0.12
C02
Gas / Major
r
17
10
13
Oil / Major
ir
415
725
342
Gas / Minor
4a
6
1
2
Oil / Minor
r
22
15
114
a - Flaring CO2 EFs are noticeably low in this year because the 2005 GEI estimated emissions from flare pilot gas only.
3.2 BOEM Platform Database
This section summarizes the scope and available data from the BOEM Platform Database14 and provides
considerations for using the data in updating the 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.15 There are 7,070 structures and 6,164
complexes in the database; the earliest install date is 1947 and the earliest removal date is 1973. EPA accessed
the BOEM Platform Database in May 2019 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.
3.2.2 Considerations for Use in GHGI Updates
EPA evaluated the BOEM Platform Database for consideration in determining 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.
14 https://www.data.boem.gov/Platform/PlatformStructures/Default.aspx
15 A major structure is defined as containing at least 6 completions or containing more than 2 pieces of production equipment.
9
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September 2019
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 plans to consider that a structure or complex is active in year N only if its removal date is
three or more years after year N.
3.3 BOEM taction Dataset
This section summarizes the scope and available data from the BOEM OGOR-A dataset and provides
considerations for using the data in updating the 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.16 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.17 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 GHGI Updates
EPA is considering using 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 is considering using 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.
These production type assignments can then be 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 is considering using the ratio
16 See "Production Data" at https://www.data.boem.gov/Main/RawData.aspx.
17 https://www.data.boem.gov/Main/OGOR-A.aspx
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September 2019
between GOM OCS production and GOM state waters production18 to estimate offshore production emissions in
GOM state waters (see discussion in Section 4.2).
iiiiig and Venting Volumes Dataset
This section summarizes the scope and available data from the BOEM OGOR-B dataset and provides
considerations for using the data in updating the 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 current GHGI, C02 emissions from all offshore flaring activities have been
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,19 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 may facilitate 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 current methodology which does not separate flaring emissions between natural gas and
petroleum systems.
To assess agreement between the current 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 current 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 current GHGI (as provided by MMS staff) and the volumes of flared gas
reported in the publicly available OGOR-B data are compared in Table 8.
Table 8. Comparison of Flared Gas Volumes for Offshore Production Facilities Between Current GHGI and
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
18 GOM State waters production is available in separate data sources, as discussed in Section 3.6.1.
19 https://www.data.boem.gov/Main/OGOR-B.aspx
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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
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
9,640
67%
84% /16%
6,471
93%/7%
2017
_ a
_ a
10,177
64%
83% /17%
6,501
94%/6%
a - Data from MMS staff were provided for 1990-2008. Year 2008 data are used as surrogate for years 2009 forward in
the current 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 GHGI Updates
EPA is considering two options (referred to as Option A and Option B) to combine the current GHGI (based on
historical MMS data) and OGOR-B datasets to calculate offshore flaring emissions in the updated GHGI. The
current GHGI assigns all offshore flaring emissions to natural gas systems, and the OGOR-B data would allow for a
portion of the flaring emissions to be attributed to offshore oil production within petroleum systems.
Under Option A, the current GHGI data would generally be used for years 1990-2008 and OGOR-B data would be
used for subsequent years. Combining the current GHGI and OGOR-B datasets for Option A would require 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 is
considering applying the year 2011 values (80% of 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; EPA is
considering linearly interpolating between the 2008 and 2011 volumes.
Under Option B, the current GHGI data generally would be used for years 1990-1995, the current GHGI data (% of
gas flared) combined with the OGOR-B data (flared and vented gas volume, % flared gas from oil and gas wells)
would both be used for years 1996-2008, and OGOR-B data would be used for years 2009 forward. Combining the
current GHGI and OGOR-B datasets for Option B would require three assumptions to estimate separate oil and
gas offshore flaring emissions over the time series. First, for years prior to 2011, Option B would rest on the
assumption that the percent of flared and vented gas from oil complexes (and gas complexes) is equivalent to the
percent of flared gas from oil complexes (and gas complexes). Second, for years 1990-1995, the percent of flared
12
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September 2019
gas from oil versus gas complexes is not available; EPA is considering applying the 1996 values (65% of flared gas
is from oil complexes and 35% of flared gas is from gas complexes) to prior time series years. Lastly, the percent of
gas flared is not available for 2009 and 2010; EPA is considering linearly interpolating between the 2008 value
(51% of flared and vented gas is flared) and 2011 value (63% of flared and vented gas is flared).
The flared gas volumes that result for Option A and Option B are compared in Figure 6. For the emissions
estimates shown in this memo, Option A is applied to calculate flaring emissions.
OGOR-B data are specific to GOM offshore facilities in federal waters, therefore EPA is considering other
approaches to estimate offshore flaring emissions for GOM state waters, Pacific, and Alaska regions (see Sections
4.2 and 4.3).
The current GHGI includes flaring CH4 emissions within the EFs shown in Table 1. In order to calculate CH4 and N20
flaring emissions in the same manner as calculating C02 emissions discussed here (using flared gas volumes as the
activity basis), new flaring CH4 and N20 EFs would be needed to apply to the flared gas volumes. EPA is
considering applying a CH4 EF of 0.057 kg/MMBtu and an N20 EF of 0.00091 kg/MMBtu, which are used in the
BOEM GEI calculations. These EFs would then be adjusted each year using the natural gas heat content, as
discussed in Section 2.2.
3,5 GHGRP
This section summarizes the scope and available data from EPA's GHGRP dataset and provides considerations for
using the data in updating the 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 must 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.
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September 2019
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
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 9 provides an overview of the GHGRP offshore production and emissions reported for RY2011 through
RY2017.
Table 9. GHGRP Offshore Emissions and Production Reporting Overview
Data
2011
2012
2013
2014
2015
2016
2017
# Facilities
101
108
109
129
133
137
141
Gas production (Bscf)
NR
NR
NR
NR
1,355
1,344
1,650
Oil/condensate production (MMbbl)
NR
NR
NR
NR
506
563
615
Subpart W Vent and Leak Emissions
Cm (mt)
69,306
62,818
59,205
69,921
69,269
71,917
61,248
CO2 (mt)
919
1,691
4,239
904
21,678
55,147
52,688
N2O (mt)
0
0
0
0
0
0
0
Subpart W Flare Emissions
CH4 (mt)
731
893
517
683
937
1,106
723
CO2 (mt)
485,890
467,999
370,561
371,907
459,434
457,617
355,880
N2O (mt)
8
7
6
10
12
11
6
Subpart C Emissions
CH4 (mt)
80
87
87
94
99
98
99
NR- Not publicly reported in Envirofacts.
3,5,2 Considerations for Use in GIIGI 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 per-facility basis and 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. Production data are not
available for RY2011 through 2014, so the RY2015 oil versus gas assignment for a facility was used for all prior
14
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September 2019
years. Table 10 and Table 11 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.
Table 10. Year-specific EFs Calculated from GHGRP Data for Offshore Oil Facilities
Region/Emission
Type/Pollutant
2015
2016
2017
GOM
Vent and Leak EFs (mt/MMbbl)
cm
123
120
90
co2
1.6
1.6
1.9
Flare EFs (mt/MMbbl
cm
1.7
1.6
0.7
CO2
818
709
472
n2o
0.02
0.02
0.01
Pacific
Vent and Leak EFs (mt/MMbbl)
cm
421
283
309
CO2
124
3.0
3.1
Flare EFs (mt/MMbbl
cm
0.7
0.6
0.8
CO2
1,188
623
821
n2o
0.01
0.01
0.01
Alaska
Vent and Leak EFs (mt/MMbbl)
cm
461
468
598
CO2
4.6
4.4
4.0
Flare EFs (mt/MMbbl
cm
8.2
6.4
3.0
CO2
7,647
6,004
5,919
n2o
0.1
0.1
0.1
Table 11. Year-specific EFs Calculated from GHGRP Data for Offshore Gas Facilities
Region/Emission
Type/Pollutant
2015
2016
2017
GOM
Vent and Leak EFs (mt/Bcf)
CH
9.2
4.5
4.0
CO
40
126
64
Flare EFs (mt/Bcf)
cm
0.1
0.5
0.3
CO2
29
82
57
n2o
0.0002
0.0003
0.0002
Alaska
Vent and Leak EFs (mt/Bcf)
cm
20
34
25
CO2
0.10
0.01
0.00
Flare EFs (mt/Bcf)
cm
0.16
0.16
0.004
CO2
208
150
177
n2o
0.0
0.0
0.0
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September 2019
In Section 4, EPA discusses updates under consideration for the 2020 GHGI that use the EFs presented in the
tables above. In Section 5, EPA requests stakeholder feedback on use of this dataset in the GHGI and other
considerations.
3,6 Other 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.
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.20 A map of
offshore facilities off of Louisiana is available from the Louisiana Department of Wildlife and Fisheries,21 and
detailed well data are available through the Department of Natural Resources' online database - Strategic Online
Natural Resource Information System (SONRIS).22 The Texas General Lands Office provides GIS files for offshore
facilities.23 These datasets may allow EPA to estimate the number of currently operating offshore facilities in GOM
state waters, but it does not appear possible to develop such facility counts over the entire GHGI time series.
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").24 The Louisiana
Department of Natural Resources and the Texas Railroad Commission report oil and gas production from gas wells
and oil wells separately.25,26 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 EIA; however, the data are of
insufficient detail to fully assess GOM state waters oil production.27 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 is considering
applying 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.28 Federal waters facilities are under
20 https://www.gsa.state.al.us/ogb/wells
21 http://ldwf.maps.arcgis.com/apps/webappviewer/index.html?id=a71d6758535042dd969114fb6a356888
22 http://www.sonris.com/
23 http://www.glo.texas.gov/land/land-management/gis/
24 https://www.gsa.state.al.us/ogb/production
25 http://www.dnr.louisiana.gov/index.cfm?md=pagebuilder&tmp=home&pid=206
26 http://webapps.rrc.state.tx.us/PDQ/generalReportAction.do
27 http://www.eia.gov/dnav/ng/ng_prod_sum_a_epgO_fgw_mmcf_a.htm
28 https://www.slc.ca.gov/lnfo/Oil_Gas.html
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September 2019
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
3.2).29 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 Conservation30 and Pacific region federal waters production data are
available from BOEM31 and EIA.32,33 For Pacific region federal waters production, EPA is considering using EIA data
for 1990-1995 and BOEM data for all subsequent years. EPA is also considering assigning 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 is considering 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.34,35
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 is considering 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 Updates Under Consideration for the GHGI
The subsections below discuss updates under consideration for EFs and activity data in the 2020 GHGI, organized
by region, and summarized in Table 12.
Table 12. Approaches under Consideration for 2020 GHGI Updates, by Offshore Region
Region
Memo
Section
EF Basis Under Consideration
Activity Data Basis Under Consideration
GOM federal waters
4.1
BOEM GEI, complex-level EFs
BOEM Platform Database
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
California state and BOEM and/or EIA
federal offshore production data
Alaska state waters
4.3
GHGRP (facilities in Alaska region),
production-based EFs
Alaska state offshore production data
29 https://www.data.boem.gov/Main/PacificPlatform.aspx
30 https://www.conservation.ca.gov/dog/pubs_stats/annual_reports/Pages/annual_reports.aspx
31 https://www.data.boem.gov/Main/PacificProduction.aspx
32 http://www.eia.gov/dnav/ng/ng_prod_sum_a_epgO_fgw_mmcf_a.htm
33 http://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm
34 http://aogweb.state.ak.us/DataMiner3/Forms/WellList.aspx
35 http://aogweb.state.ak.us/DataMiner3/Forms/Production.aspx
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September 2019
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 is
therefore considering developing 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 applying 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 2014). 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.
EPA seeks stakeholder feedback on these preliminary approaches and the particular state waters consideration
noted above; refer to Section 5 for specific questions.
:ore Production In GOM Federal Waters
This section summarizes a preliminary approach for estimating emissions (EFs multiplied by activity data) from
offshore production in GOM Federal waters.
;fs
EPA is considering applying year-specific, complex-level EFs developed from the BOEM GEI dataset (see Table 6) 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 current GHGI (refer to Section 2).
EPA is specifically considering an approach for major complexes where the BOEM GEI-based EFs for a particular
year would generally be 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 would be applied to year 2005 only (due to the hurricane season
impact, discussed in Section 3.1.1);
• EFs calculated from the 2008 BOEM GEI would be applied to 1990 through 2004 and 2006 through 2009;
• EFs calculated from the 2011 BOEM GEI would be applied to 2010 through 2012; and
• EFs calculated from the 2014 BOEM GEI would be applied to 2013 through 2017.
• When the 2017 BOEM GEI data are available, EFs would be calculated and applied to years 2016 through
2018.
For minor complexes, EPA is considering applying the 2014 (or more recent) BOEM GEI minor complex EFs (see
Table 6) to estimate vent and leak emissions (including engine exhaust CH4) over the GHGI time series. 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. As is
the case for major complexes, when the 2017 BOEM GEI data are available, EFs would be calculated and applied
to years 2016 through 2018.
EPA considered two options to estimate flaring emissions from complexes in GOM Federal waters. The first option
would maintain the current GHGI approach, wherein EFs on the basis of kg/MMBtu (along with year-specific heat
content) would be applied to OGOR-B flared gas volumes over the time series—see Sections 2.2 and 3.4.2. While
the current GHGI only estimates flaring C02 emissions using this EF approach, EPA would also estimate flaring CH4
and N20 emissions under this option. The second option would use BOEM GEI-based flaring EFs (as shown in Table
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September 2019
7). Major complex flaring EFs would be applied as discussed in the prior paragraph, and minor complex flaring EFs
would be applied in the same manner as major complex flaring EFs (based on EPA analysis, the GEI reporting
requirement changes discussed in the above paragraph did not significantly impact minor source flaring
emissions). For purposes of estimating emissions discussed in the remainder of this memo, EPA applied the first
option discussed above, primarily because OGOR-B flared gas volume data are available for each time series year,
whereas GEI EFs can only be calculated for GEI publication years.
xtivity Data
EPA is considering an updated approach to estimate active GOM federal waters complex counts that would pair
with BOEM GEI EFs discussed in Section 4.1.1. As discussed in Section 2.1, the current GHGI activity data relies on
an MMS dataset that has 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 is considering
using the BOEM 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 is
considering then using the BOEM OGOR-A Production Dataset to further subcategorize complexes as gas versus
oil production; details of this approach are discussed in Section 3.3.2.3. Figure 11 presents the resulting complex
counts over the time series, compared to the facility counts in the 2019 GHGI.
EPA is considering two approaches to calculate offshore flaring emissions. The first, discussed above, would use
BOEM GEI EFs and the same AD as discussed in the above paragraph. The second would estimate offshore flared
gas volumes over the time series (such approach would be used with EFs from the second option for estimating
flaring emissions discussed in Section 4.1.1), by relying on both the historical activity data provided by MMS staff
(used in the current GHGI) and publicly available OGOR-B data. Details of this approach are discussed in Section
3.4.2, including considerations for two options to estimate the flared gas volumes (see Option A and Option B).
Emissions
Figure 12 and Figure 13 show the total CH4 emissions and C02 emissions, respectively, for the updates under
consideration for GOM federal water offshore production facilities, compared to the 2019 GHGI emissions (which
also solely represent GOM federal water emissions). The updates under consideration for the 2020 GHGI for GOM
federal water offshore facilities would result in a 2% increase in GOM federal water offshore production CH4
emissions for petroleum systems in year 2017 and an average increase of 44% over the 1990-2017 time series
(with most of the increase occurring over the 1990-2009 time frame). The updates under consideration would
result in a 91% decrease in GOM federal water offshore production CH4 emissions for natural gas systems in year
2017 and an average decrease of 29% over the 1990-2017 time series. Total CH4 GOM federal water offshore
production emissions would decrease by 39% for year 2017 and increase by 11% on average over the 1990-2017
time series for the updates under consideration compared to the 2019 GHGI.
The two approaches to estimate flaring emissions from GOM federal water production result in very different
estimates, with the approach that relies on BOEM GEI EFs generally leading to much higher C02 emissions. Using
the OGOR-B flaring volumes Option A approach under consideration (consistent with the current GHGI approach),
GOM federal waters offshore production total C02 emissions would increase by 6% for year 2017 and the annual
average over the 1990-2017 time series would not change. Using the BOEM GEI flaring EFs approach, GOM
federal waters offshore production total C02 emissions would decrease by 18% for year 2017 and increase by 72%
on average over the 1990-2017 time series.
4,2 Offshore Production In GOM State 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
19
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September 2019
limited data characterizing emissions and activity for such operations that likely compose some fraction of activity
within state waters. EPA is therefore considering estimating 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 is considering developing production-based EFs for each year of the time series from the GOM federal waters
data. EPA would calculate EFs by dividing the GOM federal waters emissions by the GOM federal waters
production in each year. The production basis would also be unique for oil complexes and gas complex emissions;
oil production would be used in the numerator for oil complexes and gas production would be used in the
numerator for gas complexes. Separate EFs for vent and leak emissions and flaring emissions would also be
developed from the GOM federal waters data set. For flaring emissions, this approach would apply to either of the
options EPA is considering in Section 4.1.
4.2.2 Activity Data
EPA is considering using annual state-specific offshore production (discussed in Section 3.6.1) paired with the EFs
discussed in Section 4.2.1 to calculate emissions.
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 under consideration.
4.3 Offshore Production in Pacific and 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 is considering using 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 is considering applying the GHGRP production-based EFs shown in Table 10 and Table 11 to estimate
emissions from facilities in the Pacific and Alaska regions, respectively. The GHGRP RY2015 EFs would be applied
to all prior years in the GHGI time series.
4.3.2 Activity Data
EPA is considering using 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.
4.3.3 Emissions
Figure 16 and Figure 17 show the total CH4 emissions and C02 emissions, respectively, for the 2020 GHGI updates
under consideration for the Pacific and Alaska regions.
4.4 Emissions Summary
Figure 18 and Figure 19 show the total offshore production CH4 emissions and C02 emissions, respectively, for the
updates under consideration for the 2020 GHGI for each of the production regions, compared to the 2019 GHGI
emissions. Flaring C02 emissions for the updates under consideration included in Figure 19 are based on the
approach that uses OGOR-B flaring volumes for the GOM.
For the updates under consideration for the 2020 GHGI, 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). In year 2017, GOM federal waters offshore facilities account for 91% of offshore
20
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September 2019
production CH4 emissions and 74% of offshore production C02 emissions for petroleum systems, and 69% of
offshore production CH4 emissions and 64% of offshore production C02 emissions for natural gas systems. In
addition, for year 2017, GOM state waters offshore gas facilities contribute 28% of offshore production CH4
emissions and 26% of offshore production C02 emissions for natural gas systems, while Alaska region offshore oil
facilities contribute 23% of offshore production C02 emissions for petroleum systems. Pacific region offshore
facilities generally contribute minimal emissions. Table 13 presents the offshore production CH4 emissions and
C02 emissions for each region in year 2017 for the updates under consideration for the 2020 GHGI and the 2019
GHGI.
Compared to the 2019 GHGI, petroleum systems offshore production CH4 emissions increase overall for the
updates under consideration for the 2020 GHGI, while natural gas systems offshore production CH4 emissions
decrease overall for the updates under consideration for the 2020 GHGI. Compared to the 2019 GHGI, offshore
production C02 emissions increase overall for the updates under consideration for the 2020 GHGI. Petroleum
systems offshore production flaring C02 emissions also constitute approximately 90% of the total flaring C02
emissions for the updates under consideration for the 2020 GHGI, whereas the 2019 GHGI assigned all offshore
production flaring C02 emissions to natural gas systems. Table 14 shows the percent change between the 2019
GHGI and the updates under consideration for the 2020 GHGI, for year 2017 and on average over the 1990-2017
time series.
Offshore production N20 emissions are not presented in this memo, but EPA would calculate offshore production
flaring N20 emissions for the updates under consideration for the 2020 GHGI in the same manner that offshore
production flaring C02 and CH4 emissions are calculated for each region. Offshore production flaring N20
emissions will have a minimal contribution to the natural gas and petroleum systems emissions estimates, and
would account for approximately 0.5% of total offshore production flaring emissions (on a C02 equivalent basis)
for the updates under consideration for the 2020 GHGI.
Table 13. Offshore Production Year 2017 CH4 and C02 Emissions (mt), by Region, for the Updates Under
Consideration for the 2020 GHGI and the 2019 GHGI
Emissions Category
Region
2020 GHGI Update
(Year 2017)
2019 GHGI
(Year 2017)
ch4
Petroleum systems
GOM Federal Waters
191,431
187,604
GOM State Waters
1,252
NE
Alaska
12,164
NE
Pacific
5,052
NE
Total
209,899
187,604
Natural gas systems
GOM Federal Waters
13,845
150,565
GOM State Waters
5,658
NE
Alaska
501
NE
Pacific
n/a
n/a
Total
20,005
150,565
C02
Petroleum systems
GOM Federal Waters
380,723
8,340
GOM State Waters
2,491
NE
Alaska
119,963
NE
Pacific
13,440
NE
Total
516,617
8,340
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September 2019
Emissions Category
Region
2020 GHGI Update
(Year 2017)
2019 GHGI
(Year 2017)
Natural gas systems
GOM Federal Waters
24,179
372,116
GOM State Waters
9,881
NE
Alaska
3,483
NE
Pacific
n/a
n/a
Total
37,543
372,116
NE = Not estimated,
n/a = Not applicable.
Table 14. Percent Change Due to Recalculations in CH4 and C02 Emissions Between the 2019 GHGI and the
Updates Under Consideration for the 2020 GHGI
Emissions Category
Year 2017 Change from 2017
Estimate in Previous GHGI
1990-2017 Time Series Average
Annual Change from Previous GHGI
ch4
Petroleum systems
12%
69%
Natural gas systems
-87%
-16%
Total
-32%
31%
C02
Petroleum systems*
6,094%
7,106%
Natural gas systems
-90%
-71%
Total
46%
184%
* In the previous GHGI, all C02 emissions from flaring were reported under Natural Gas Systems.
5 Requests for Stakeholder Feedback
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 GEl-
based complex-level vent and leak EFs.
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.
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September 2019
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.
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.
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September 2019
Appendix A - Memo Figures
Offshore Gas Production (BCF)
28
Offshore Oil Production (MMBBL)
1,277
i GOM - Federal Alaska - State GOM - State
Pacific (CA) - Federal Pacific (CA) - State
¦ GOM-Federal ¦ Alaska - State GOM - State
Pacific (CA) - Federal ¦ Pacific (CA) - State
Figure 1. Overview of U.S. Offshore Gas Production (BCF) and Oil Production (MMBBL), Year 2014
300
250
— 200
E
— 150
<-> 100
50
2005 Complex EF
2008 Complex EF
2011 Complex EF
2014 Complex EF
I..1
I
i.l
Gas Major Oil Major Gas Minor Oil Minor
Figure 2. Complex-Level Vent and Leak CH4 EFs (mt/yr) Calculated from BOEM GEI Data
24
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September 2019
800
700
600
>- 500
-M
E
— 400
U_
LU
O 300
u
200
100
0
Gas Major Oil Major Gas Minor Oil Minor
Figure 3. Complex-Level Flaring C02 EFs (mt/yr) Calculated from BOEM GEI Data
¦ 2005 Complex EF
¦ 2008 Complex EF
¦ 2011 Complex EF
¦ 2014 Complex EF
1
¦
1
100%
90%
£ 80%
x
CD
Q.
E
o
u
~03
4->
,o
70%
60%
50%
40%
£ 30%
cu
Q.
20%
10%
0%
% Oil Complexes
% Gas Complexes
0
01
en
r\i
cn
cn
''d-
cn
cn
VD
cn
cn
oo
cn
cn
o
o
o
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rsi
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UD
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O
rsi
OO
O
O
rsi
O
CM
O
rsi
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rsi
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rsi
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CM
Figure 4. Production Type of Active GOM Federal Water Complexes Over the GHGI Time Series
25
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September 2019
700
3,500
in
CTi
CTl
00
CTl
CTl
O
o
o
-------
September 2019
Louisiana
Figure 7, Offshore Oil Production from Oil Facilities in GOM State Waters
¦Louisiana
¦Texas
Alabama
-Q
200
,3i 150
Figure 8. Offshore Gas Production from Gas Facilities in GOM State Waters
27
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September 2019
State Waters
Federal Waters
Figure 9. Pacific Federal and State Waters Oil Production from Oil Facilities
100
150
(T3
_Q
C
o
j=
to
o
O
o
O
O
O
o
O
O
o
i
T—1
T—1
H
T—1
rsl
CM
rsl
rsl
(N
rsl
rsl
rsl
rsl
rsl
Figure 10. Alaska State Waters Production
28
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September 2019
3,500
3,000
2,500
g 2,000
U 1,500
1,000
500
Oil, Major Complexes ¦ Oil, Minor Complexes
Gas, Major Complexes ¦ Gas, Minor Complexes
Figure 11. GOM Federal Water Oil and Gas Complex Counts for the 2020 GHGI Updates Under Consideration
29
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September 2019
350
300
250
4—»
to
c
¦2 200
IS)
E
LU
x 150
+->
£
100
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 12, GOM Federal Waters Offshore Production CH4 Emissions by Production Type (Oil and Gas Facilities)
for 2020 GHGI Updates Under Consideration Compared to 2019 GHGI Emissions
400
350
300
£ 250
o
i/i
t/i
£ 200
LU
O
— 150
ro
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 Updates Under Consideration Compared to 2019 GHGI Emissions
30
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September 2019
Gas Facilities
¦ Oil Facilities
Figure 14. GOM State Waters Offshore Production CH4 Emissions for 2020 GHGI Updates Under Consideration
Gas Facilities
¦ Oil Facilities
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016
Figure 15. GOM State Waters Offshore Production C02 Emissions for 2020 GHGI Updates Under Consideration
31
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September 2019
¦ AK Gas Facilities
Pacific Oil Facilities
¦ AK Oil Facilities
Figure 16. Pacific and Alaska Region Offshore Production CH4 Emissions for 2020 GHGI Updates Under
Consideration
¦ AK Gas Facilities
Pacific Oil Facilities
¦ AK Oil Facilities
Figure 17. Pacific and Alaska Region Offshore Production C02 Emissions for 2020 GHGI Updates Under
Consideration
32
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September 2019
700
¦ 2020 GHGI Update - Petroleum Systems
2020 GHGI Update - Natural Gas Systems
2019 GHGI - Total
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016
Figure 18. Offshore Production Total CH4 Emissions For Updates Under Consideration for the 2020 GHGI
Compared to 2019 GHGI Emissions
1,200
¦ 2020 GHGI Update - Petroleum Systems
2020 GHGI Update - Natural Gas Systems
2019 GHGI - Total
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016
Figure 19. Offshore Production Total C02 Emissions For Updates Under Consideration for the 2020 GHGI
Compared to 2019 GHGI Emissions
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