GREENHOUSE GAS EMISSIONS REPORTING FROM THE
PETROLEUM AND NATURAL GAS INDUSTRY
BACKGROUND TECHNICAL SUPPORT DOCUMENT
The Environmental Protection Agency (EPA) regulations cited in this technical support
document (TSD) contain legally-binding requirements. In several chapters this TSD offers
illustrative examples for complying with the minimum requirements indicated by the
regulations. This is done to provide information that may be helpful for reporters'
implementation efforts. Such recommendations are prefaced by the words "may" or "should"
and are to be considered advisory. They are not required elements of the regulations cited in
this TSD. Therefore, this document does not substitute for the regulations cited in this TSD,
nor is it a regulation itself, so it does not impose legally-binding requirements on EPA or the
regulated community. It may not apply to a particular situation based upon the
circumstances. Mention of trade names or commercial products does not constitute
endorsement or recommendation for use.
While EPA has made every effort to ensure the accuracy of the discussion in this document,
the obligations of the regulated community are determined by statutes, regulations or other
legally binding requirements. In the event of a conflict between the discussion in this
document and any statute or regulation, this document would not be controlling.
U.S. ENVIRONMENTAL PROTECTION AGENCY
CLIMATE CHANGE DIVISION
WASHINGTON DC
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TABLE OF CONTENTS
1. Segments in the Petroleum and Natural Gas Industry 4
a. Petroleum Industry 4
b. Natural Gas Industry 5
2. Types of Emissions Sources and GHGs 6
3. GHG Emissions from the Petroleum and Natural Gas Industry 7
4. Methodology for Selection of Industry Segments and Emissions Sources Feasible for
Inclusion in a GHG Reporting Rule 10
a. Review of Existing Regulations 11
b. Review of Existing Programs and Studies 12
c. Selection of Emissions Sources for Reporting 19
i. Facility Definition Characterization 19
ii. Selection of Potential Emissions Sources for Reporting 20
iii. Address Sources with Large Uncertainties 24
iv. Identify Industry Segments to be Included 25
5. Options for Reporting Threshold 27
a. Threshold Analysis 28
6. Monitoring Method Options 33
a. Review of Existing Relevant Reporting Programs/ Methodologies 33
b. Potential Monitoring Methods 33
i. Equipment Leak Detection 33
ii. Emissions Measurement 36
A. Direct Measurement 36
B. Engineering Estimation and Emission Factors 39
C. Emission Factors 47
D. Combination of Direct Measurement and Engineering Estimation 47
c. Leak detection and leaker emission factors 63
d. Population Count and Emission Factors 63
e. Method 21 64
f. Portable VOC Detection Instruments for Leak Measurement 66
g. Mass Balance for Quantification 66
h. Gulf Offshore Activity Data System program (GOADS) 67
i. Additional Questions Regarding Potential Monitoring Methods 67
i. Source Level Equipment Leak Detection Threshold 67
ii. Duration of Equipment Leaks 69
iii. Equipment Leak and Vented Emissions at Different Operational Modes 69
iv. Natural Gas Composition 70
v. Physical Access for Leak Measurement 71
7. Procedures for Estimating Missing Data 71
a. Emissions Measurement Data 72
b. Engineering Estimation Data 72
c. Emissions Estimation Data for Storage Tanks and Flares 72
d. Emissions Estimation Data Using Emissions Factors 73
8. QA/QC Requirements 73
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a. Equipment Maintenance 73
b. Data Management 73
c. Calculation checks 74
9. Reporting Procedure 75
10. Verification of Reported Emissions 75
Appendix A: Segregation of Emissions Sources using the Decision Process 76
Appendix B: Development of revised estimates for four U.G. GHG Inventory emissions
sources 84
Appendix C: Development of threshold analysis 92
Appendix D: Analysis of potential facility definitions for onshore petroleum and natural gas
production 106
Appendix E: Development of multipliers to scale emissions or miscellaneous sources
connected to storage tanks 110
Appendix F: Development of leaker emission Factors 113
Appendix G: Development of population emission factors 123
Appendix H: Glossary 134
Appendix I: References 141
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1. Segments in the Petroleum and Natural Gas Industry
The U.S. petroleum and natural gas industry encompasses the production of raw gas and
crude oil from wells to the delivery of processed gas and petroleum products to consumers.
These segments use energy and emit greenhouse gases (GHG). It is convenient to view the
industry in the following discrete segments:
• Petroleum Industry - petroleum production, petroleum transportation, petroleum
refining, petroleum storage terminals, and
• Natural Gas Industry -natural gas production, natural gas gathering and boosting
(natural gas gathering and boosting are not included in this rulemaking), natural gas
processing, natural gas transmission and underground storage, liquefied natural gas
(LNG) import and export terminals, and natural gas distribution.
Each industry segment uses common processes and equipment in its facilities, most of which
emit GHG. Each of these industry segments is described in further detail below.
a. Petroleum Industry
Petroleum Production. Petroleum or crude oil is produced from underground geologic
formations. In some cases, natural gas is also produced from oil production wells; this gas is
called associated natural gas. Production may require pumps or compressors for the injection
of liquids or gas into the well to maintain production pressure. The produced crude oil is
typically separated from water and gas, injected with chemicals, heated, and temporarily
stored. GHG emissions from crude oil production result from combustion-related activities,
and equipment leaks and vented emissions. Equipment counts and GHG-emitting practices
are related to the number of producing crude oil wells and their production rates.
As petroleum production matures in a field, the natural reservoir pressure is not sufficient to
bring the petroleum to the surface. In such cases, enhanced oil recovery (EOR) techniques
are used to extract oil that otherwise can not be produced using only reservoir pressure. In
the United States, there are three predominant types of EOR operations currently used;
thermal EOR, gas injection EOR, and chemical injection EOR. Thermal EOR is carried out
by injecting steam into the reservoir to reduce the viscosity of heavy petroleum to allow the
flow of the petroleum in the reservoir and up the production well. Gas injection EOR
involves injecting of gases, such as natural gas, nitrogen, or carbon dioxide (CO2), to
decrease the viscosity of the petroleum and push it towards and up the producing well.
Chemical injection EOR is carried out by injecting surfactants or polymers to improve the
flow of petroleum and/or enhance a water flood in the reservoir. Emissions sources from
EOR operations are similar to those in conventional petroleum production fields. However,
additional emissions occur when C02 is used for recovery. This specific EOR operation
requires pumps to inject supercritical CO2 into the reservoir while compressors maintain the
recycled C02's supercritical state. Venting from these two emissions sources is a major
source of emissions.
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Petroleum Transportation. The crude oil stored at production sites is either pumped into
crude oil transportation pipelines or loaded onto tankers and/or rail freight. Along the supply
chain crude oil may be stored several times in tanks. These operational practices and storage
tanks release mainly process GHG emissions. Emissions are related to the amount of crude
oil transported and the transportation mode.
Petroleum Refining Crude oil is delivered to refineries where it is temporarily stored
before being fractionated by distillation and treated. The fractions are reformed or cracked
and then blended into consumer petroleum products such as gasoline, diesel, aviation fuel,
kerosene, fuel oil, and asphalt. These processes are energy intensive. Equipment counts and
GHG gas emitting practices are related to the number and complexity of refineries. Subpart
Y of the GHG reporting rule (40 CFR Part 98) published in the Federal Register on October
30, 2009, addresses refineries and hence is not discussed further in this document.
Petroleum products are then transported via trucks, rail cars, and barges across the supply
chain network to terminals and finally to end users.
b. Natural Gas Industry
Natural Gas Production In natural gas production, wells are used to withdraw raw gas
from underground formations. Wells must be drilled to access the underground formations,
and often require natural gas well completion procedures or other practices that vent gas from
the well depending on the underground formation. The produced raw gas commonly requires
treatment in the form of separation of gas/liquids, heating, chemical injection, and
dehydration before being compressed and injected into gathering lines. Combustion
emissions, equipment leaks, and vented emissions arise from the wells themselves, gathering
pipelines, and all well-site natural gas treatment processes and related equipment and control
devices. Determining emissions, equipment counts, and frequency of GHG emitting
practices is related to the number of producing wellheads and the amount of produced natural
gas. Further details are provided on the individual sources of GHG emissions in Appendix
A.
Natural Gas Processing In the processing facility, natural gas liquids and various other
constituents from the raw gas are separated, resulting in "pipeline quality" gas that is
compressed and injected into the transmission pipelines. These separation processes include
acid gas removal, dehydration, and fractionation. Most equipment and practices have
associated GHG equipment leaks, energy consumption-related combustion GHG emissions,
and/or process control related GHG vented emissions. Equipment counts and frequency of
GHG emitting practices are related to the number and size of gas processing facilities.
Further details are provided on the individual sources of GHG emissions in Appendix A.
Natural Gas Transmission and Storage Natural gas transmission involves high pressure,
large diameter pipelines that transport natural gas from petroleum and natural gas production
sites and natural gas processing facilities to natural gas distribution pipelines or large volume
customers such as power plants or chemical plants. Compressor station facilities containing
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large reciprocating and / or centrifugal compressors, move the gas throughout the U.S.
transmission pipeline system. Equipment counts and frequency of GHG emitting practices
are related to the number and size of compressor stations and the length of transmission
pipelines.
Natural gas is also injected and stored in underground formations, or stored as LNG in above
ground storage tanks during periods of low demand (e.g., spring or fall), and then withdrawn,
processed, and distributed during periods of high demand (e.g., winter and summer).
Compressors, pumps, and dehydrators are the primary contributors to emissions from these
underground and LNG storage facilities. Equipment counts and GHG emitting practices are
related to the number of storage stations.
Imported and exported LNG also requires transportation and storage. These processes are
similar to LNG storage and require compression and cooling processes. GHG emissions in
this segment are related to the number of LNG import and export terminals and LNG storage
facilities. Further details are provided on the individual sources of GHG emissions for all of
transmission and storage in Appendix A.
Natural Gas Distribution Natural gas distribution pipelines take high-pressure gas from
the transmission pipelines at "city gate" stations, reduce and regulate the pressure, and
distribute the gas through primarily underground mains and service lines to individual end
users. There are also underground regulating vaults between distribution mains and service
lines. GHG emissions from distribution systems are related to the pipelines, regulating
stations and vaults, and customer/residential meters. Equipment counts and GHG emitting
practices can be related to the number of regulating stations and the length of pipelines.
Further details are provided on the individual sources of GHG emissions in Appendix A.
2. Types of Emissions Sources and GHGs
The three main GHGs that are relevant to the petroleum and natural gas industry are methane
(CH4), carbon dioxide CO2, and nitrous oxide (N2O). All three gases were taken into account
when developing the threshold analysis.
Emissions from sources in the petroleum and gas industry can be classified into one of two
types:
Combustion-related emissions
Combustion-related emissions result from the use of petroleum-derived fuels and
natural gas as fuel in equipment (e.g., heaters, engines, furnaces, etc.) in the
petroleum and gas industry. CO2 is the predominant combustion-related emission;
however, because combustion equipment is less than 100 percent efficient, CH4 and
other unburned hydrocarbons are emitted. N2O results from both fuel-bound
nitrogen and nitrogen from atmospheric air. For methodologies to quantify GHG
emissions from combustion, please refer to Subpart C of the GHG reporting rule
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(40 CFR Part 98), except for GHG emissions from flaring, onshore production
stationary and portable combustion GHG emissions, and combustion emissions
from stationary equipment involved in natural gas distribution. For methodologies
to quantify combustion emissions from flaring, onshore production stationary and
portable equipment, and combustion emissions from stationary equipment involved
in natural gas distribution, please refer to Subpart W.
Equipment leaks and vented emissions
The Intergovernmental Panel on Climate Change (IPCC) and the Inventory of U.S.
GHG Emissions and Sinks1 (henceforth referred to as the U.S. GHG Inventory)
define fugitive emissions to be both intentional and unintentional emissions from
systems that extract, process, and deliver fossil fuels. Intentional emissions are
emissions designed into the equipment or system. For example, reciprocating
compressor rod packing has a certain level of emissions by design, e.g., there is a
clearance provided between the packing and the compressor rod for free movement
of the rod that results in emissions. Also, by design, vent stacks in petroleum and
natural gas production, natural gas processing, and petroleum refining facilities
release natural gas to the atmosphere. Unintentional emissions result from wear and
tear or damage to the equipment. For example, valves result in emissions due to
wear and tear from continuous use over a period of time. Also, pipelines damaged
during maintenance operations or corrosion result in unintentional emissions.
IPCC's definition is not intuitive since fugitive in itself means unintentional.
Therefore, this document henceforth distinguishes between fugitive emissions
(referred to as equipment leaks in the final subpart W) and vented emissions.
Equipment leaks are those emissions which could not reasonably pass through a
stack, chimney, vent, or other functionally-equivalent opening.
Vented emissions are intentional or designed releases of CH4 or CO2 containing
natural gas or hydrocarbon gas (not including stationary combustion flue gas),
including process designed flow to the atmosphere through seals or vent pipes,
equipment blowdown for maintenance, and direct venting of gas used to power
equipment (such as pneumatic devices).
3. GHG Emissions from the Petroleum and Natural Gas Industry
The U.S. GHG Inventory provides estimates of equipment leaks and vented CH4 and CO2
emissions from all segments of the petroleum and natural gas industry. These estimates are
based mostly on emissions factors available from two major studies conducted by EPA/Gas
1 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006,
(April 2008), USEPA #430-R-08-005
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Research Institute (EPA/GRI)2 for the natural gas segment and EPA/Radian3 for the
petroleum segment. These studies were conducted in the early and late 1990s respectively.
Petroleum Segment
According to the 2006 U.S. GHG Inventory, EPA estimates that crude oil production
operations accounted for over 97 percent of total CH4 emissions from the petroleum industry.
Crude oil transportation activities accounted for less than one half of a percent of total CH4
emissions from the oil industry. Crude oil refining processes accounted for slightly over two
percent of total CH4 emissions from the petroleum industry because most of the CH4 in crude
oil is removed or escapes before the crude oil is delivered to the petroleum refineries. The
2006 U.S. GHG Inventory for Petroleum Systems currently estimates CO2 emissions from
only crude oil production operations. Research is underway to include other larger sources
of CO2 emissions in future inventories.
Natural Gas Segment
Emissions from natural gas production accounted for approximately 66 percent of CH4
emissions and about 25 percent of non-energy CO2 emissions from the natural gas industry in
2006. Processing facilities accounted for about 6 percent of CH4 emissions and
approximately 74 percent of non-energy CO2 emissions from the natural gas industry. CH4
emissions from the natural gas transmission and storage segment accounted for
approximately 17 percent of emissions, while CO2 emissions from natural gas transmission
and storage accounted for less than one percent of the non-energy C02 emissions from the
natural gas industry. Natural gas distribution segment emissions, which account for
approximately 10 percent of CH4 emissions from natural gas systems and less than one
percent of non-energy CO2 emissions, result mainly from equipment leaks from gate stations
and pipelines.
Updates to Certain Emissions Sources
The EPA/GRI study used the best available data and somewhat restricted knowledge of
industry practices at the time to provide estimates of emissions from each source in the
various segments of the natural gas industry. In addition, this study was conducted at a time
when CH4 emissions were not a significant concern in the discussion about GHG emissions.
Over the years, new data and increased knowledge of industry operations and practices have
highlighted the fact that emissions estimates from the EPA/GRI study are outdated and
potentially understated for some emissions sources. The following emissions sources are
believed to be significantly underestimated in the U.S. GHG Inventory: well venting for
liquids unloading; gas well venting during well completions; gas well venting during well
workovers; crude oil and condensate storage tanks; centrifugal compressor wet seal
degassing venting; scrubber dump valves; onshore combustion; and flaring.
2 EPA/GRI (1996) Methane Emissions from the Natural Gas Industry. Prepared by Harrison, M., T. Shires, J.
Wessels, and R. Cowgill, eds., Radian International LLC for National Risk Management Research Laboratory,
Air Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a.
3 EPA (1996) Methane Emissions from the U.S. Petroleum Industry (Draft). Prepared by Radian. U.S.
Environmental Protection Agency. June 1996.
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The understatement of emissions in the U.S. GHG Inventory were revised using publicly
available information for all sources and included in the analysis, except crude oil and
condensate storage tanks and flares, and scrubber dump valves.4 The revised estimates for
storage tanks are available in "Analysis of Tank Emissions", found in the EPA-HQ-OAR-
2009-0923-0002 docket, but the revised emissions have not been included in this analysis
(See Appendix C for further details). For further discussion on the inclusion of scrubber
dump valves in this rulemaking please see the analysis "Scrubber Dump Valves" in EPA-
HQ-OAR-2009-0923 docket. EPA has limited publicly available information to accurately
revise estimates on a national level for flaring and scrubber dump valves. For onshore
combustion emissions, EPA used emissions estimates from the GHG inventory which are
based on EIA data which EPA believes to be underestimated. Refer to section 4(c)(iii) of the
TSD for further details. This is explained further below. Appendix B provides a detailed
discussion on how new estimates were developed for each of the four underestimated
sources. Table 1 provides a comparison of emissions factors as available from the EPA/GRI
study and as revised in this document. Table 2 provides a comparison of emissions from
each segment of the natural gas industry as available in the U.S. GHG Inventory and as
calculated based on the revised estimates for the four underestimated sources.
Table 1: Comparison of Emissions Factors from Four Updated Emissions Sources
Emissions Source Name
EPA/GRI
Emissions
Factor
Revised
Emissions
Factor
Units
1) Well venting for liquids
unloading
1.02
11
CH4 - metric tons/year-
well
2) Gas well venting during completions
Conventional well completions
0.02
0.71
CH4 - metric tons/year-
completion
Unconventional well completions
0.02
177
CH4 - metric tons/year-
completion
3) Gas well venting during well workovers
Conventional well workovers
0.05
0.05
CH4 - metric tons/year-
workover
Unconventional well workovers
0.05
177
CH4 - metric tons/year-
workover
4) Centrifugal compressor wet
seal degassing venting
0
233
CH4 - metric tons/year-
compressor
1. Conversion factor: 0.01926 metric tons = 1
Mcf
4 EPA did consider the data available from two new studies, TCEQ (2009) and TERC (2009). However, it was
found that the data available from the two studies raise several questions regarding the magnitude of emissions
from tanks and hence were not found appropriate for any further analysis until the issues are satisfactorily
understood and/ or resolved by the authors and covered parties.
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Table 2: Comparison of Process Emissions from each Segment of the Natural Gas and
Petroleum Industries
Segment Name
U.S. GHG Inventory7
Estimate for Year 2006
(MMTC02e)
Revised Estimate for
Year 2006
(MMTC02e)
Production2
90.2
198.0
Processing
35.9
39.5
Transmission and Storage
48.4
52.6
Distribution
27.3
27.3
1. U.S. EPA (2008) Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006.
2.Production includes equipment leaks and vented emissions from both the natural gas and petroleum sectors' onshore and offshore
facilities.
After revising the U.S. GHG Inventory emissions estimates for the sources listed in Table 1,
total equipment leak and vented CH4 and CO2 emissions from the petroleum and natural gas
industry were 317 million metric tons of C02 equivalent (MMTC02e) in 2006. Of this total,
the natural gas industry emitted 261 MMTCC^e of CH4 and 28.50 MMTCC^e of CO2 in
2006. Total CH4 and C02 emissions from the petroleum industry in 2006 were 27.74
MMTC02e and 0.29 MMTCC^e respectively.
4. Methodology for Selection of Industry Segments and Emissions Sources
Feasible for Inclusion in a GHG Reporting Rule
It is important to develop criteria to help identify GHG emissions sources in the petroleum
and natural gas industry most likely to be of interest to policymakers. To identify sources for
inclusion in a GHG reporting rule, two preliminary steps were taken; 1) review existing
regulations to identify emissions sources already being regulated, and 2) review existing
programs and guidance documents to identify a comprehensive list of emissions sources for
potential inclusion in the proposed rule.
The first step in determining emissions sources to be included in a GHG reporting rule was to
review existing regulations that the industry is subject to. Reviewing existing reporting
requirements highlighted those sources that are currently subject to regulation for other
pollutants and may be good candidates for addressing GHG emissions. The second step was
to establish a comprehensive list of emissions sources from the various existing programs
and guidance documents on GHG emissions reporting. This provided an exhaustive list of
emissions sources for the purposes of this analysis and avoided the exclusion of any
emissions sources already being monitored for reporting under other program(s). Both of
these steps are described below.
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a. Review of Existing Regulations
The first step was to understand existing regulations and consider adapting elements of the
existing regulations to a reporting rule for GHG emissions. When the Mandatory Reporting
Rule development process began, there were three emissions reporting regulations and six
emissions reduction regulations in place for the petroleum and natural gas industry, including
one voluntary reporting program included in the Code of Federal Regulations. This table also
includes EPA's final GHG reporting rule, which requires certain petroleum and gas facilities
to report their combustion-related emissions. Table 3 provides a summary of each of these
nine reporting and reduction regulations.
Table 3: Summary of Regulations Related to the Petroleum and Natural Gas Industry
Ki'Uiiliilioii
Tj |)l'
Point/ Area/
Msijor/ Mobile
Source
(j;iscs
( o\crcd
Segment iiiul Sources
EPA 40 CFR Part 98
Final Rule: Mandatory
Reporting of
Greenhouse Gases
Mandatory
Emissions
Reporting
Point, Area,
Biogenic
co2, ch4,
N20, HFCs,
PFCs,, SF6,
NF3, and HFE
Annual reporting of GHG
emissions from direct
emitters (including
petroleum and natural gas
systems) and suppliers of
industrial GHGs in the
United States.
EPA 40 CFR Part 51-
Consolidated
Emissions Reporting
Emissions
Reporting
Point, Area,
Mobile,
VOCs, NOx,
CO, nh3,
PMio, PM2.5
All segments of the
petroleum and natural gas
industry
DOE 10 CFR Part 300
- Voluntary GHG
Reporting
Voluntary
GHG
Reporting
Point, Area,
Mobile
co2, ch4,
N20, HFCs,
PFCs,, SF6,
and CFCs
All segments of the
petroleum and natural gas
industry
EPA 40 CFR Part 60,
Subpart KKK
NSPS2
Point
VOCs
Onshore processing plants;
sources include compressor
stations, dehydration units,
sweetening units,
underground storage tanks,
field gas gathering systems,
or liquefied natural gas
units located in the plant
EPA 40 CFR Part 60,
Subpart LLL
NSPS2
Point
S02
Onshore processing plants;
Sweetening units, and
sweetening units followed
by a sulfur recovery unit
EPA 40 CFR Part 63,
NESHAP1 Subpart
HHH
MACT3
Point (Glycol
dehydrators,
natural gas
transmission and
storage facilities)
HAPs
Glycol dehydrators
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EPA 40 CFR Part 63,
NESHAP1, Subpart
HH
MACT3
Major and Area
(petroleum and
natural gas
production, up to
and including
processing
plants)
HAPs
Point Source - Glycol
dehydrators and tanks in
petroleum and natural gas
production; equipment leaks
at gas processing plants
Area Source - Triethylene
glycol (TEG) dehydrators in
petroleum and natural gas
production
EPA 40 CFR Part 63,
NESHAP1, -Subpart
YYYY
MACT3
Major and Area
(Stationary
Combustion
Turbine)
HAPs
All segments of the
petroleum and natural gas
industry
EPA 40 CFR Part 63,
NESHAP1, Subpart
zzzz
MACT3
Major and Area
(Reciprocating
Internal
Combustion
Engines)
HAPs
All segments of the
petroleum and natural gas
industry
Notes:
National Emission Standards for Hazardous Air Pollutants
2New Source Performance Standard
3Maximum Allowable Control Technology
Table 3, indicates that only DOE 10 CFR Part 300 includes the monitoring or reporting of
CH4 emissions from the petroleum and natural gas industry. However, this program is a
voluntary reporting program and is not expected to have a comprehensive coverage of CH4
emissions. Although some of the sources included in the other regulations lead to CH4
emissions, these emissions are not reported. The MACT regulated sources are subject to Part
70 permits which require the reporting of all major HAP emission sources, but not GHGs.
GHG emissions from petroleum and natural gas operations are not systematically monitored
and reported; therefore these regulations and programs cannot serve as the foundation for a
GHG emissions reporting rule.
b. Review of Existing Programs and Studies
The second step was to review existing monitoring and reporting programs to identify all
emissions sources that are already monitored under these programs. When the Mandatory
Reporting Rule development process began, six reporting programs and six guidance
documents were reviewed. Table 4 summarizes this review, highlighting monitoring points
identified by the programs and guidance documents.
Table 4 shows that the different monitoring programs and guidance documents reflect the
points of monitoring identified in the U.S. GHG Inventory, which are consistent with the
range of sources covered in the 2006 IPCC Guidelines. Therefore, the U.S. GHG Inventory
was used to provide the initial list of emissions sources for determining the emissions sources
that can be potentially included in the rule.
The preliminary review provided a potential list of sources, but did not yield any definitive
indication on the emissions sources that were most suitable for potential inclusion in a
reporting program. A systematic assessment of emissions sources in the petroleum and
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natural gas industry was then undertaken to identify the specific emissions sources (e.g.,
equipment or component) for inclusion in a GHG reporting rule.
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Table 4: Summary of Program and Guidance Documents on GHG Emissions Monitoring and Reporting
Reporting
Program/Guidance
Source Category
(or Fuel)
Coverage (Gases or
Fuels)
Points of Monitoring
Monitoring Methods and/or GHG Calculation
Methods*
2006 IPCC Guidelines for
National GHG Inventory,
Volume 2, Chapter 4
Petroleum and Gas
- all segments
CH4, non-combustion
C02 and other GHG
gases
Oil and natural gas systems
fugitive equipment leaks,
evaporation losses, venting,
flaring, and accidental
releases; and all other fugitive
emissions at oil and natural
gas production, transportation,
processing, refining, and
distribution facilities from
equipment leaks, storage
losses, pipeline breaks, well
blowouts, land farms,
gas migration to the surface
around the outside of wellhead
casing, surface casing vent
bows, biogenic gas formation
from tailings ponds and any
other gas or vapor releases not
specifically accounted for as
venting or flaring
Accounting/ reporting methodologies and guidelines
Companies choose a base year for which verifiable
emissions data are available. The base year emissions
are used as an historic control against which the
company's emissions are tracked over time. This
ensures data consistency over time. Direct
measurement of GHG emissions by monitoring
concentration and flow rate can also be conducted.
IPCC methodologies are broken down into the
following categories:
Tier I calculation-based methodologies for
estimating emissions involve the calculation of
emissions based on activity data and default
industry segment emission factors
Tier II calculation-based methodologies for
estimating emissions involve the calculation of
emissions based on activity data and country-
specific industry segment emission factors or by
performing a mass balance using country-
specific oil and/or gas production information
Tier III calculation-based methodologies for estimating
emissions involve "rigorous bottom-up assessment by
primary type of source (e.g. evaporation losses,
equipment leaks) at the individual facility level with
appropriate accounting of contributions from
temporary and minor field or well-site installations.
The calculation of emissions is based on activity data
and facility-specific emission factors
AGA - Greenhouse Gas
Emissions Estimation
Methodologies,
Procedures, and Guidelines
Gas - Distribution
CH4, non-combustion
C02 and other GHG
gases
Segment-level counts,
equipment discharges (i.e.
valves, open-ended lines, vent
stacks), and segment
Equipment or segment emissions rates and engineering
calculations
Tier I, II (IPCC) - facility level emissions rates
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for the Natural Gas
Distribution Sector
capacities, facility counts and
capacities
Tier III (IPCC) - equipment emissions rates for
intentional emissions, process level emissions rates,
and process/equipment level emissions rate
API - Compendium of
GHG Emissions Estimation
Methodologies for the Oil
and Gas Industry
Gas and Petroleum
- all segments
CH4, non-combustion
C02
Equipment discharges (e.g.
valves, open-ended lines, vent
stacks), vent stacks for
equipment types, tank
PRV/vents, and facility input
Equipment or segment emissions rates and engineering
calculations
Tier II (IPCC) - facility level emissions rates
Tier III (IPCC) - equipment emissions rates for
intentional emissions, process level emissions rates,
tank level emissions rates, and process/equipment level
emissions rate (BY SEGMENT)
California Climate Action
Registry General Reporting
Protocol, March 2007
All legal entities
(e.g. corporations,
institutions, and
organizations)
registered in
California,
including
petroleum and gas
- all segments
CH4, non-combustion
C02 and other GHG
gases
All activities resulting in
indirect and direct emission of
GHG gases for the entity
Provides references for use in making fugitive
calculations
The CCAR does not specify methodology to calculate
fugitive emissions
California Mandatory GHG
Reporting Program
Petroleum -
Refineries
CH4, non-combustion
C02 and other GHG
gases
All activities resulting in CH4
and C02 fugitive emissions for
petroleum refineries
Continuous monitoring methodologies and equipment
or process emissions rates
C02 process emissions can be determined by
continuous emissions monitoring systems. Methods for
calculating fugitive emissions and emissions from
flares and other control devices are also available
DOE Voluntary Reporting
of Greenhouse Gases
Program (1605(b))
Petroleum and
Gas- All Segments
CH4, non-combustion
C02 and other GHG
gases
All activities resulting in
direct and indirect emissions
of GHG gases for the
corporation or organization
Direct, site-specific measurements of emissions or all
mass balance factors
Mass-balance approach, using measured activity data
and emission factors that are publicly documented and
widely reviewed and adopted by a public agency, a
standards-setting organization or an industry group
Mass-balance approach, using measured activity data
and other emission factors
Background Technical Support Document - Petroleum and Natural Gas Industry
15
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Mass balance approach using estimated activity data
and default emissions factors.
EU ETS 1st and 2nd
Reporting Period
Petroleum -
Refining
Non-combustion C02
Hydrogen production
Engineering calculations
Operators may calculate emissions using a mass-
balance approach
INGAA - GHG Emissions
Estimation Guidelines for
Natural Gas Transmission
and Storage, Volume 1
Gas -
T ransmission/Stora
ge
CH4, non-combustion
C02
Segment-level counts,
equipment discharges (i.e.
valves, open-ended lines, vent
stacks), and segment
capacities, facility counts and
capacities
Equipment or segment emissions rates
Tier I (IPCC)- segment level emissions rates from
intentional and unintentional releases
Tier II - equipment level emissions rates for intentional
releases
Tier II (IPCC) - facility and equipment level emissions
rates for unintentional leaks
Engineering calculation methodologies for:
- Pig traps
- Overhauls
- Flaring
IPIECA - Petroleum
Industry Guidelines for
Reporting GHG Emissions
Petroleum and Gas
- all segments
CH4, non-combustion
C02 and other GHG
gases
Refers to API Compendium
points of monitoring:
Equipment discharges (e.g.
valves, open-ended lines, vent
stacks), vent stacks for
equipment types, tank
PRV/vents, and facility input
Tiers I, II, and III (IPCC) definitions and reporting
methods for all fugitive and vented GHG emissions in
the oil and gas industry
New Mexico GHG
Mandatory Emissions
Inventory
Petroleum
refineries
C02 reporting starts
2008, CH4 reporting
starts 2010
Equipment discharges (e.g.
valves, pump seals,
connectors, and flanges)
2009 reporting procedures will be made available
in 10/2008
Background Technical Support Document - Petroleum and Natural Gas Industry
16
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The Climate Registry
(General Reporting
Protocol for the Voluntary
Reporting Program), 2007
All legal entities
(e.g.
corporations,
institutions, and
organizations)
including
petroleum and
gas - all
segments
CH4, non-combustion
C02 and other GHG
gases
All activities resulting in
emission of GHG gases for the
entity
Continuous monitoring methodologies and equipment
or process emissions rates
Measurement-based methodology monitor gas flow
(continuous, flow meter) and test methane
concentration in the flue gas. Calculation-based
methodologies involve the calculation of emissions
based on activity data and emission factors
Western Regional Air
Partnership (WRAP)
Petroleum and
Gas - all
segments
CH4, non-combustion
C02 and other GHG
gases
All activities resulting in
emission of GHG gases for the
entity
Provides quantification methods for all sources from all
sectors of the petroleum and gas industry considered in
the rule. Quantification methods are typically
engineering equation; however, parameters for the
equations in several cases require measurement of flow
rates, such as from well venting
World Resources Institute/
World Business Council
for Sustainable
Development GHG
Protocol Corporate
Standard, Revised Edition
2003
Organizations
with operations
that result in
GHG (GHG)
emissions e.g.
corporations
(primarily),
universities,
NGOs, and
government
agencies. This
includes the oil
and gas industry
CH4, non-combustion
C02 and other GHG
gases
All activities resulting in
direct and indirect emission of
GHG gases for the corporation
or organization
Provides continuous monitoring methodologies and
equipment or process emissions rates
Companies need to choose a base year for which
verifiable emissions data are available and specify their
reasons for choosing the year. "The base year
emissions are used as an historic datum against which
the company's emissions are tracked over time.
Emissions in the base year should be recalculated to
reflect a change in the structure of the company, or to
reflect a change in the accounting methodology used.
This ensures data consistency over time." Direct
measurement of GHG emissions by monitoring
concentration and flow rate can be conducted.
Calculation-based methodologies for estimating
emissions involve the calculation of emissions based
on activity data and emission factors
Background Technical Support Document - Petroleum and Natural Gas Industry
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i. EPA 2007 Cooperative Agreement with University of Texas (UT) Austin to Update GRI/
EPA Study Estimated Emission Factors
In the past decade, there has been growing interest in better understanding CH4 emissions
sources from the petroleum and natural gas industry. As mentioned above, the seminal
study, upon which much of the current knowledge on CH4 emission factors is based, is
Methane Emissions from the Natural Gas Industry (GRI/EPA 1996). In the United States, the
GRI/EPA Study serves as the basis for most CH4 estimates from natural gas systems in
EPA's Inventory of U.S. GHG Emissions and Sinks, EPA's Natural Gas STAR Program,
Methane to Markets International Program, State Inventories, the American Petroleum
Institute (API) Compendium, a transmission and distribution protocol by the Interstate
Natural Gas Association of America (INGAA), as well as all of the organizations that
reference these documents and programs in their individual work. The GRI/EPA Study was
also evaluated for its relevance for a separate effort to develop a transmission and distribution
GHG accounting protocol by the California Climate Action Registry. Internationally, the
GRI/EPA Study is the source for many of the emission factors included in the
Intergovernmental Panel on Climate Change Guidelines for National Greenhouse Gas
Inventories.
Although the GRI/EPA Study has been the cornerstone for estimating CH4 emissions from
the natural gas industry to date, the data on which the study is based are now over a decade
and a half old and in some cases (e.g., wells, compressors), not always reflective of current
conditions in the United States. In recognition of the fact that existing methane emission
factors were becoming quickly outdated, in 2007 EPA funded a 4-year cooperative
agreement with UT Austin to support research and, as appropriate, measurement studies to
update selected CH4 emission factors from the 1996 GRI study. The cooperative agreement
identified a small set of 11 priority sources in different industry segments on which to focus
emission factor development. With the limited budget available, as of mid-2010, the project
has begun work on updating emission factors for reciprocating and centrifugal compressors
only. Specifically, the project team has initiated preliminary measurement studies at
compressor stations at natural gas transmission and storage facilities owned by two
companies. Now approaching its final year, the project team is currently evaluating the most
efficient use of the remaining resources; specifically whether to undertake additional
measurements on transmission and storage facilities to gain the most robust data set possible,
or to use remaining funds on another source of emissions in the production, processing,
transmission, or distribution segments.
The UT Austin cooperative agreement was initiated to develop representative national
emission factors- it was not designed, like the GHG reporting rule, to comprehensively
collect actual GHG emissions data to support a range of future climate policies. To meet the
goals of the reporting rule, for larger sources, such as compressors, it is critical that EPA
collect actual emissions data in order to understand trends and also connect emissions to
specific equipment and types of operations. For example, if there is a trend regarding the
maintenance of rod packing over time, this information would not be obtained through a
static data set based on national compressor-level emission factors. .
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Further, the limited budget available for the UT Austin study will not allow for emissions
information from a large number of sources; the GHG reporting rule will be collecting
comprehensive actual emissions data and other relevant information from major sources
across the United States petroleum and natural gas industry for all U.S. facilities over 25,000
mtC02e. In addition, the GHG reporting rule will collect applicable information (e.g.,
equipment component counts and operational data) needed to verify the reported GHG data
and support future climate policy analysis.
c. Selection of Emissions Sources for Reporting
When identifying emissions sources for inclusion in a GHG reporting rule, two questions
need addressing. The first is defining a facility. In other words, what physically constitutes a
facility? The second is determining which sources of emissions should a facility report?
Including or excluding sources from a GHG reporting rule without knowing the definition of
a facility is difficult. Therefore, both the facility definition and emissions source inclusion (or
exclusion) were reviewed to arrive at a conclusion.
i. Facility Definition Characterization
Typically, the various regulations under the Clean Air Act (CAA) define a facility as a group
of emissions sources all located in a contiguous area and under the common control of the
same person (or persons). This definition can be easily applied to offshore petroleum and
natural production, onshore natural gas processing, onshore natural gas transmission
compression, underground natural gas storage, and LNG import and export equipment since
the operations are all located in a clearly defined boundary. However, as discussed further
below, this definition does not as directly lend itself to all industry segments, such as onshore
petroleum and natural gas production, natural gas distribution, and petroleum transportation
sectors.
Onshore petroleum and natural gas production operations can be very diverse in
arrangement. Sometimes crude oil and natural gas producing wellheads are far apart with
individual equipment at each wellhead. Alternatively, several wells in close proximity may
be connected to common pieces of equipment. Whether wells are connected to common
equipment or individual equipment depends on factors such as distance between wells,
production rate, and ownership and royalty payment. New well drilling techniques such as
horizontal and directional drilling allow for multiple wellheads to be located at a single
location (or pad) from where they are drilled to connect to different zones in the same
reservoir. Therefore, the conventional facility definition of a "contiguous area" under a
common owner/ operator cannot be easily applied to the onshore petroleum and natural gas
production industry segment. Refer to Section 4(c)(iv) in the TSD for a more detailed
discussion of the facility definition for onshore petroleum and natural gas production.
An alternative to a physical facility definition is the use of a corporate level reporter
definition. In such a case the corporation that owns or operates petroleum and natural gas
production operations could be required to report. Here the threshold for reporting could
require that an individual corporation sum up GHG emissions from all the fields it is
Background Technical Support Document - Petroleum and Natural Gas Industry
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operating in and determine if its total emissions surpass the threshold. See Appendix D for
further discussion of this issue.
In the natural gas distribution segment the meters and regulators in the distribution segment
are primarily located at small stations or underground vaults distributed over large urban or
suburban regions. Individually defining each station or vault as a facility is impractical owing
to the size and expected magnitude of emissions from single stations. However, a logical
grouping of distribution equipment exists at the regulated local distribution company level.
The precedent for reporting at this type of facility already exists under the Pipeline and
Hazardous Materials Safety Administration (PHMSA) requirements under CFR Title 49
Section 191.11. Refer to Section 4(c)(iv) of the TSD for a more detailed discussion of the
definition for natural gas distribution. As explained in the Response to Comments, the
PHMSA regulations primarily relate to pipeline safety provisions, and are unrelated to
information EPA seeks to collect under this rule.
ii. Selection of Potential Emissions Sources for Reporting
Given that there are over 100 emissions sources1 in the petroleum and natural gas industry, it
is important to target sources which contribute significantly to the total national emissions for
the industry. This avoids an excessive reporting burden on the industry, but at the same time
enables maximum coverage for emissions reporting. The selection of emissions sources for
potential inclusion in the proposed rulemaking was conducted in three steps.
Step 1: Characterize Emissions Sources
The U.S. GHG Inventory was used as the complete list of sources under consideration for
inclusion in a reporting rule. The U.S. GHG Inventory was also used to provide all relevant
emissions source characteristics such as type, number of sources across industry segments,
geographic location, emissions per unit of output, total national emissions from each
emissions source, and frequency of emissions. Also, information included in the U.S. GHG
Inventory and the Natural Gas STAR Program technical studies were used to identify the
different monitoring methods that are considered the best for each emissions source. If there
are several monitoring methods for the same source, with equivalent capabilities, then the
one with lower economic burden was considered in the analysis.
Step 2: Identify Selection Criteria and Develop Decision Tree for Selection
There are several factors that impact the decision on whether an emissions source should be
included for reporting. A discussion of the factors follows below.
• Significant Contribution to U.S. GHG Inventory - Emissions sources that contribute
significant emissions can be considered for potential inclusion in the rule, since they
increase the coverage of emissions reporting. Typically, in petroleum and natural gas
facilities, 80 percent or more of the facility emissions are reported to be from
approximately 10 percent of the emissions sources. This is a good benchmark to ensure
the adequate coverage of emissions while reducing the number of emissions sources
required for reporting thus, keeping the reporting burden to a minimum. Emissions
sources in each segment of the natural gas and petroleum industry can be sorted into two
Background Technical Support Document - Petroleum and Natural Gas Industry
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main categories: (1) top sources contributing to 80 percent of the emissions from the
segment, and (2) the remaining sources contributing to the remaining 20 percent of the
emissions from that particular segment. This can be easily achieved by determining the
emissions contribution of each emissions source to the segment it belongs to, listing the
emissions sources in a descending order, and identifying all the sources at the top that
contribute to 80 percent of the emissions. Appendix A provides a listing of all emissions
sources in the U.S. GHG Inventory and a breakdown of the top emissions sources by
industry segment.
• Type of Emissions - The magnitude of emissions per unit or piece of equipment typically
depends on the type of emissions. Vented emissions per unit source are usually much
higher than equipment leak emissions from a unit source. For example, emissions from
compressor blowdown venting for one compressor are much higher than equipment leak
emissions from any one unit component source on the compressor. The burden from
covering emissions reporting from each unit source (i.e. dollar per ton of emissions
reported) is typically much lower in the case of venting sources in comparison to
equipment leak emission sources when the same monitoring method is used. Therefore,
vented sources could be treated separately from equipment leak sources for assessment of
monitoring requirements.
• Best Practice Monitoring Method(s) - Depending on the types of monitoring methods
typically used, a source may or may not be a potential for emissions reporting. There are
four types of monitoring methods as follows:
o Continuous monitoring - refers to cases where technologies are available that
continuously monitor either the emissions from a source or a related parameter that
can be used in estimating emissions. For example, continuous monitoring meters
can determine the flow rate and in line analyzers can determine the composition of
emissions from a process vent,
o Periodic monitoring - refers to monitoring at periodic intervals to determine
emissions from sources. For example, leak detection and measurement equipment
can be used on a recurring basis to identify and measure an emissions rate from
equipment.
o Engineering calculations - refers to estimation of emissions using engineering
parameters. For example, emissions from a vessel emergency release can be
estimated by calculating the volume of the emitting vessel,
o Emissions factors - refers to utilizing an existing emissions rate for a given source
and multiplying it by the relevant activity data to estimate emissions. For example,
emissions per equipment unit per year can be multiplied by the number of pieces of
equipment in a facility to estimate annual emissions from that equipment for the
facility.
• Accessibility of emissions sources - Not all emissions sources are directly accessible
physically for emissions detection and/or measurement. For example, connectors on
pipelines, pressure relief valves on equipment, and vents on storage tanks may be out of
direct physical reach and could require the use of bucket trucks or scaffolding to access
Background Technical Support Document - Petroleum and Natural Gas Industry
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them. In such cases requiring emissions detection and measurement may not always be
feasible such as with leak detection equipment that requires the operator to be in close
physical proximity to the equipment. Also, such requirements could pose health and
safety hazards or lead to large cost burden. The accessibility of emissions sources was
considered when addressing monitoring requirements and determining the type of leak
detection equipment allowed under Subpart W.
• Geographical dispersion of emissions sources - The cost burden for detecting and
measuring emissions will largely depend on the distance between various sources.
Monitoring methods will have to be chosen considering the dispersion of emissions
sources.
• Applicability of Population or Leaker Emission factors - When the total emissions from
all leaking sources of the same type are divided by the total count of that source type then
the resultant factor is referred to as population emissions factor. When the total emissions
from all leaking sources of the same type are divided by the total count of leaking sources
for that source type then the resultant factor is referred to as leaker emissions factor. For
example, in an emissions detection and measurement study, if 10 out of 100 valves in the
facility are found leaking then:
o the total emissions from the 10 valves divided by 100 is referred to as
population emissions factor
o the total emissions from the 10 valves divided by 10 is referred to as leaker
emissions factor
Requiring emissions leak detection and application of a corresponding emissions factor
results in lower reporting burden as compared to conducting actual measurements.
Furthermore, the use of leaker emissions factors provides an estimate of "actual"
emissions as opposed to the use of population emissions factor where the emissions from
each facility can only be a "potential" of emissions.
Based on the criteria outlined above, a decision process was developed to identify the
potential sources that could be included in the reporting rule. Error! Reference source not
found, shows the resulting decision tree that includes these criteria and supported the
decision-making process. The decision process provided in Error! Reference source not
found, was applied to each emissions source in the natural gas segment of the U.S. GHG
Inventory. The onshore petroleum production segment has emissions sources that either are
equivalent to their counterparts in the natural gas onshore production segment or fall in the
20 percent exclusion category. Only CH4 emissions from the petroleum segment were taken
into consideration for this exercise given that, for most sources, non-combustion CO2
emissions from the petroleum segment are negligible in comparison to CH4 emissions from
the same sources. The exception to these are flares and acid gas recovery units in EOR
operations that have large C02 emission, but EPA does not have any emissions estimates for
these source (see Section 3 and (4)(c)(iv) of the TSD). Appendix A summarizes the results of
this analysis and provides guidance on the feasibility of each of the monitoring options
discussed previously.
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Figure 1: Decision Process for Emissions Source Selection
Background Technical Support Document - Petroleum and Natural Gas Industry
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iii. Address Sources with Large Uncertainties
As described in Section 3 of the TSD, the petroleum and natural gas industry inventories are
primarily based on the EPA/GRI 1996 Study, however the emissions for several sources in
the EPA/GRI study do not correctly reflect today's operational practices. In some cases,
comprehensive and sufficient information is not publicly available to revise the national
Inventory estimates. In cases where public data are available, it is often incomplete and does
not represent the industry at a national level.
Over the years, new data and increased knowledge of industry operations and practices have
highlighted the fact that emissions estimates for certain sources are understated in the US
Inventory
o Condensate and petroleum storage tanks
o Natural gas well workovers
o Natural gas well completions
o Natural gas well liquid unloading
o Centrifugal compressor wet seals
o Flares
o Scrubber dump valve emissions through tanks
o Onshore combustion emissions
The decision tree was not necessarily ideal for the sources listed above because they are
known to be underestimated in current inventories. Therefore, after careful evaluation, EPA
determined that these are significant emission sources that should be included in a
comprehensive petroleum and natural gas systems GHG reporting rule. The following
emissions sources are believed to be significantly underestimated in the U.S. GHG Inventory:
well venting for liquids unloading; gas well venting during well completions; gas well
venting during well workovers; crude oil and condensate storage tanks; centrifugal
compressor wet seal degassing venting; scrubber dump valves; onshore combustion; and
flaring. Refer to Appendix B for a detailed discussion on how new estimates were developed
for each of the underestimated sources; natural gas well workovers, natural gas well
completions, and natural gas well blowdowns. For centrifugal wet seals, EPA used an
emission factor from a presentation given at the 24th World Gas Conference.5
In addition, the U.S. GHG Inventory includes reasonable estimation of CH4 and CO2
combustion emissions from natural gas engines and turbines (except in onshore production),
as well as petroleum refineries. Emissions from these sources were not considered further
here because methods for calculating and reporting emissions from these sources are
addressed in the background technical support documents for Stationary Combustion
5 The Bylin, Carey (EPA) study reported wet seal degassing emission measurements from 48 centrifugal compressors. Five
centrifugal compressors were found not emitting while, the remaining 43 emitted 14,860 thousand cubic meters per year.
Twenty-three cubic feet per minute was determined by dividing the 14,860 by the 43 centrifugal compressors. Bylin,
Carey (EPA), et. al (2009) Methane's Role in Promoting Sustainable Development in Oil and Natural Gas
Industry.
Background Technical Support Document - Petroleum and Natural Gas Industry
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described in Subpart C and Petroleum Refineries described in Subpart Y of the of the final
GHG reporting rule (40 CFR Part 98) respectively.
Onshore Combustion Emissions:
The EPA estimates onshore production combustions emissions in its national GHG
inventory. However, there are two challenges with the way these data are collected that make
it difficult to use this data to support potential future climate policies. First, combustion-
related emissions are reported in the national inventory at a fairly high level of aggregation,
making it difficult to discern facility-level emissions. Second, there are concerns that this
aggregate estimate is underestimating the total emissions from this source. The National
Inventory of U.S. GHG Emissions and Sinks uses the "lease and plant" fuel consumption
data as reported by the Energy Information Administration (EIA) as activity data to apply an
emissions factor to estimate emissions. However, EIA estimates the lease and plant volume
using data available from individual petroleum and natural gas producing States. The States
in turn require only the voluntary reporting of this data from petroleum and natural gas
producing operators raising questions as to whether the national data are complete. In
addition, this estimate may not include all of the combustion emissions resulting from
contracted and/ or portable combustion equipment. Given the high level of aggregation of
this data and the potential omissions of some fuel consumption in onshore production in the
National Inventory, this source type would be valuable to include in the rule for a more
complete picture of facility-related emissions from onshore production facilities.
iv. Identify Industry Segments to be Included
Based on the understanding of facility definitions for each segment of the petroleum and
natural gas industry and the identification of potential sources for inclusion in a GHG
reporting rule, the industry segments could be defined as follows:
Onshore Petroleum and Natural Gas Production Segment - Onshore petroleum and
natural gas production is an important segment for inclusion in a GHG reporting
program, due to its relatively large share of emissions. However, in order to include
this segment, it is important to clearly articulate how to define the facility and identify
who is the reporter. Onshore production operations are a challenge for emissions
reporting using the conventional facility definition of a "contiguous area" under a
common owner/ operator. EPA evaluated possible options for defining a facility for
onshore petroleum and natural gas production in order to ensure that the reporting
delineation is clear, to avoid double counting, and ensure appropriate emissions
coverage. One potential option considered was to define a facility for this segment as
all petroleum or natural gas equipment on a well pad or associated with a well pad
and CO2 EOR operations that are under common ownership or common control and
that are located in a single hydrocarbon basin as defined in 40 CRF Part 98.238. This
includes leased, rented, or contracted activities by an onshore petroleum and natural
gas production owner or operator. Where a person or entity owns or operates more
than one well in a basin, then all onshore petroleum and natural gas production
equipment associated with all wells that the person or entity owns or operates in the
basin would be considered one facility. In this case, the operator would be the
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company or corporation holding the required permit for drilling or operating. If the
petroleum and natural gas wells operate without a drilling or operating permit, the
person or entity that pays the state or federal business income taxes may also be
considered the owner or operator. Operational boundaries and basin demarcations are
clearly defined and are widely known, and reporting at this level would provide the
necessary coverage of GHG emissions to inform policy. This facility definition for
onshore petroleum and natural gas production will result in 85% GHG emissions
coverage of this industry segment.
EPA reviewed other possible alternatives to define a production facility such as at the
field level. In such cases, the company (or corporation) operating in the field would
report emissions. EPA analyzed this option and found that such a field level definition
would result in a larger number of reporters and in lower emissions coverage than
basin level reporting, since fields are typically a segment of a basin.
In addition to basin and field level reporting, one additional alternative is identifying
a facility as an individual well pad, including all stationary and portable equipment
operating in conjunction with that well, including drilling rigs with their ancillary
equipment, gas/liquid separators, compressors, gas dehydrators, crude petroleum
heater-treaters, gas powered pneumatic instruments and pumps, electrical generators,
steam boilers and crude oil and gas liquids stock tanks. In reviewing this option, EPA
found that defining a facility as a single wellhead would significantly increase the
number of reporters to a program, lower emissions coverage, and potentially raise
implementation issues. For a complete discussion of the threshold analysis and
estimated emissions coverage for each of the onshore petroleum and natural gas
production facility options considered, refer to Section 5 of the TSD.
Offshore Petroleum and Natural Gas Production Segment - All of the production
activities offshore take place on platforms. These platforms can be grouped into two
main categories; wellhead platforms and processing platforms. Wellhead platforms
consist of crude oil and/ or natural gas producing wellheads that are connected to
processing platforms or send the hydrocarbons onshore. Processing platforms consist
of wellheads as well as processing equipment such as separators and dehydrators, in
addition to compressors. All platforms are within a confined area and can be
distinctly identified as a facility. Since all sources are within a small area on and
around the platform, all sources of emissions on or associated with offshore platforms
could be monitored and reported.
Onshore Natural Gas Processing Segment -Processing plants process the gas
received from production and/ or gathering or boosting segments to remove hydrogen
sulfide (H2S) and/ or CO2 from the natural gas, if any, separate the higher molecular
weight hydrocarbons (ethane, propane, butane, pentanes, etc.) from the natural gas
and compress the natural gas to be injected into the onshore natural gas transmission
segment. Natural gas processing facilities have a well defined boundary within which
all processes take place. All emissions sources in processing facilities could be
monitored and included in a GHG reporting rule.
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Onshore Natural Gas Transmission Compression - Transmission compressor stations
are the largest source of emissions on transmission pipelines and meet the
conventional definition of a facility. Given the relatively large share of emissions
from the compressor station, as compared to the pipeline segments between
transmission compressor stations, the station may be the most logical place to capture
emissions from this segment.
Underground Natural Gas Storage, LNG Storage, and LNG Import and Export
Segments - All operations in an underground natural gas storage facility (except
wellheads), LNG storage facility, and LNG import and export facilities are confined
within defined boundaries. In the case of underground natural gas storage facilities,
the wellheads are within short distances of the main compressor station such that it is
feasible to monitor them along with the stations themselves. All three segments could
be included in a GHG reporting rule.
Natural Gas Distribution Segment - The distribution segment metering and regulator
above ground stations and below ground vaults are identifiable as facilities. However,
the magnitude of emissions from a single station or vault may not be significant,
which would result in minimal coverage of emissions from this segment. Multiple
stations or vaults collectively contribute to a significant share of emissions from the
natural gas industry nationally, but they may not be considered one facility because
they are not contiguous and there is no logical grouping unless the entire system is
considered.
Another option for including distribution sector is adapting the facility definition
from Subpart NN, Suppliers of Natural Gas and Natural Gas Liquids, of the MRR
which defines a local distribution company (LDC) as a facility. In this case, the
definition of natural gas distribution would be the distribution pipelines, metering and
regulator stations and vaults that are operated by a Local Distribution Company
(LDC) that is regulated as a separate operating company by a public utility
commission or that are operated as an independent municipally-owned distribution
system This facility definition provides clear reporting delineation because the
equipment that they operate is clearly known, the ownership is clear to one company,
and reporting at this level is consistent with the final MRR as well as other existing
data reporting mechanisms. Additionally, this aggregation of equipment will include
all the significant sources of emissions from the segment.
Petroleum Transportation Segment - All the sources in the petroleum transportation
segment were excluded as a result of the decision process. Hence, this segment may
not be amenable to inclusion in a reporting program.
5. Options for Reporting Threshold
For each segment in the petroleum and natural gas industry identified above as amenable to a
reporting program, four thresholds were considered for emissions reporting as applicable to
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an individual facility; 1,000 metric tons of CO2 equivalent (MtC02e) per year, 10,000
MtC02e, 25,000 MtC02e, and 100,000 MtC02e. A threshold analysis was then conducted on
each segment to determine which level of threshold was most suitable for each industry
segment. CH4, C02, and N20 emissions from each segment were included in the threshold
analysis.
a. Threshold Analysis
For each segment, a threshold analysis was conducted to determine how many of the
facilities in the segment exceed the various reporting thresholds, and the total emissions from
these impacted facilities. This analysis was conducted considering equipment leak and vented
CH4 and C02 emissions, and incremental combustion CH4, C02, and N20 emissions.
Incremental combustion emissions are those combustion emissions from facilities not already
reported under Subpart C of the 40 CFR Part 98, but are required to be reported because the
combined process emissions from Subpar W plus combustion emissions exceed the 25,000
metric tons C02e reporting threshold. The equipment leak and vented emissions estimates
available from the U.S. GHG Inventory were used in the analysis. However, the emissions
estimates for four sources, well venting for liquids unloading, gas well venting during well
completions, gas well venting during well workovers, and centrifugal compressor wet seal
degassing venting from the U.S. GHG Inventory were replaced with revised estimates
developed as described in Appendix B. Centrifugal compressor emissions were revised using
centrifugal compressor activity data from the U.S. Inventory and an emission factor from the
24th World Gas Conference5. Incremental combustion emissions were estimated using gas
engine methane emissions factors available from the GRI study, back calculating the natural
gas consumptions in engines, and finally applying a C02 emissions factor to the natural gas
consumed as fuel. Nitrous Oxide emissions were also calculated similarly. In the case of
offshore petroleum and natural gas production platforms combustion emissions are already
available from the GOADS 2000 study analysis and hence were directly used for the
threshold analysis. It must be noted that the threshold analysis for 40 CFR Part 98, Subpart
W includes all equipment leak and vented emissions, but only incremental combustion
emissions. Due to these reasons the total emissions from the threshold analysis does not
necessarily match the U.S. GHG Inventory for all segments of the petroleum and natural gas
industry. A detailed discussion on the threshold analysis is available in Appendix C.
The general rationale for selecting a reporting threshold could be to identify a level at which
the incremental emissions reporting between thresholds is the highest for the lowest
incremental increase in number of facilities reporting between the same thresholds. This
would ensure maximum emissions reporting coverage with minimal burden on the industry.
For example, for onshore production the emissions reporting coverage is 74 percent and the
corresponding reporting facilities coverage is 2 percent for a threshold of 100,000 MtC02e
per year. The incremental emissions and facilities coverage is 11 and 2 percent (85 percent
minus 74 percent and 4 percent minus 2 percent), respectively, for a 25,000 MtC02e per year
threshold. However, at the next reporting threshold level of 10,000 MtC02e per year the
incremental emissions and entities coverage is 6 and 5 percent, respectively. It can be seen
that the incremental coverage of emissions decreases but the coverage of facilities increases.
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Table 5 provides the details of the threshold analysis at all threshold levels for the different
segments in the petroleum and gas industry. It must be noted that the threshold analysis
estimates of emissions in this table are slightly different from the estimate of emissions in the
April 2010 proposal. The slight decrease in reported emissions of 4 percent for the entire oil
and gas sector resulted from data and calculation corrections in the transmission and LNG
storage segments and use of different well property databases in onshore production (HPDI®
in the final, as opposed to LASSER® in the April 2010 proposal). The same note applies to
Table 7 below.
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Table 5: Threshold Analysis for the Petroleum and Gas Industry Segments
l iicililii"- ( mm-ml
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Onshore Nalnral Cms Production
facilities (Basin)
100.000
265.349.383
22,510
136,547,535
60,732,073
197,279,608
74" o
385
2" 0
25.000
265.349.383
22,510
152,395,746
73,695,453
226,091,199
85%
981
4%
10,000
265,349,383
22,510
158,499,897
82,061,519
240,561,416
91%
1,929
9%
1,000
265,349,383
22,510
165,212,244
96,180,842
261,393,085
99%
8,169
36%
100,000
11,261,305
3,235
3,217,228
25,161
3,242,389
29%
4
0.12%
Offshore Petroleum and Natural Gas
Production Facilities
25,000
11,261,305
3,235
4,619,175
500,229
5,119,405
45%
58
1.79%
10,000
11,261,305
3,235
5,515,419
1,596,144
7,111,563
63%
184
5.69%
1,000
11,261,305
3,235
6,907,812
3,646,076
10,553,889
94%
1,192
36.85%
100,000
33,984,015
566
24,846,992
27,792
24,874,783
73%
130
23%
Onshore Natural Gas Processing
Facilities
25,000
33,984,015
566
29,551,689
1,677,382
31,229,071
92%
289
51%
10,000
33,984,015
566
30,725,532
2,257,443
32,982,975
97%
396
70%
1,000
33,984,015
566
31,652,484
2,331,531
33,984,015
100%
566
100%
100,000
47,935,158
1,944
24,197,401
7,834
24,205,235
50%
433
22%
Onshore Natural Gas Transmission
Facilities
25,000
47,935,158
1,944
36,154,061
6,155,313
42,309,374
88%
1,145
59%
10,000
47,935,158
1,944
37,593,627
9,118,603
46,712,230
97%
1,443
74%
1,000
47,935,158
1,944
37,993,603
9,934,474
47,928,077
100%
1,695
87%
100,000
9,730,625
397
3,557,040
0
3,557,040
37%
36
9%
Underground Natural Gas Storage
Facilities
25,000
9,730,625
397
6,585,276
1,276,239
7,861,516
81%
133
34%
10,000
9,730,625
397
7,299,582
1,685,936
8,985,518
92%
200
50%
1,000
9,730,625
397
7,762,600
1,951,505
9,714,105
100%
347
87%
100,000
2,113,601
157
596,154
25,956
622,110
29%
4
3%
LNG Storage Facilities
25,000
2,113,601
157
1,524,652
188,552
1,713,205
81%
33
21%
2,113,601
157
1,626,435
204,297
1,830,731
87%
41
26%
1,000
2,113,601
157
1,862,200
252,895
2,115,095
100%
54
34%
100,000
315,888
5
314,803
0
314,803
100%
4
80%
LNG Import Facilities1
25,000
315,888
5
314,803
0
314,803
100%
4
80%
10,000
315,888
5
314,803
0
314,803
100%
4
80%
1,000
315,888
5
315,048
840
315,888
100%
5
100%
100,000
25,258,347
1,427
18,470,457
0
18,470,457
73%
66
5%
Natural Gas Distribution Facilities
25,000
25,258,347
1,427
22,741,042
0
22,741,042
90%
143
10%
10,000
25,258,347
1,427
23,733,488
0
23,733,488
94%
203
14%
1,000
25,258,347
1,427
24,983,115
0
24,983,115
99%
594
42%
1. The only LNG export facility in Alaska has not been included in this analysis.
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Note: Totals may not add exactly due to rounding. Equipment leak and vented emissions in the threshold
analysis are a sum of facility level emissions for each segment. Hence the total equipment leak and vented
emissions from each segment may not match the U.S. GHG Inventory.
As discussed above, alternative definitions of facility for onshore petroleum and natural gas
production could be considered. One alternative option is applying the threshold at the field
level. Table 7 provides the results of the threshold analysis for a field level facility
definition. The results of this analysis show that at a 25,000 metric ton C02e threshold, 1,157
facilities would be covered and only 57 percent of national emissions. If the threshold were
decreased to 1,000 metric tons C02e, over 80 percent of national emissions would be covered
but the number of reporters would increase to over 22,000.
Table 7. Emissions coverage and number of reporting entities for field level facility
definition
Threshold
Level2
Emissions Covered
Facilities Covered
Metric tons
C02e/year
Percent
Number
Percent
100,000
110,437,470
42%
306
0%
25,000
150,297,681
57%
1,157
2%
10,000
171,902,688
65%
2,549
4%
1,000
219,121,375
83%
22,459
33%
A third alternative for a facility definition was individual well pads as facilities for onshore
petroleum and natural gas production segment. Four different scenarios were also considered
below for applying thresholds at individual well pads.
• Case 1 (highest well pad emissions): Drilling and completion of an
unconventional gas well early in the year with the well producing the remainder of
the year with a full complement of common, higher process emissions equipment on
the well pad including a compressor, glycol dehydrator, gas pneumatic controllers,
and condensate tank without vapor recovery. We assumed that unconventional well
completion does not employ "Reduced Emissions Completion" practices.
• Case 2 (second highest well pad emissions): Drilling and completion of a
conventional gas well early in the year with the well producing the remainder of the
year with a full complement of common, higher process emissions equipment on the
well pad including a compressor, glycol dehydrator, gas pneumatic controllers, and
condensate tank without vapor recovery.
• Case 3 (third highest well pad emissions): Drilling and completion of a
conventional oil well early in the year with the well producing the remainder of the
year with a full complement of common, higher process emissions equipment on the
well pad including an associated gas compressor, glycol dehydrator, gas pneumatic
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controllers, chemical injection pump, an oil heater-treater, and a crude oil stock tank
without vapor recovery.
• Case 4 (fourth highest well pad emissions): Production at an associate gas
and oil well (no drilling) with a compressor, dehydrator, gas pneumatics, oil
heater/treater and oil stock tank without vapor recovery.
Table 8 below illustrates the average emissions for each scenario and the number of facilities
that have emissions equal to or greater than that average. For example, in case 1, average
emissions are 4,927 tons C02e/well pad. A threshold would have to be set as low as
appropriately 5,000 tons C02e/well pad to capture even 6% of emissions from onshore
petroleum and gas production. For the other cases, the threshold would have to be set lower
than the thresholds considered for other sectors of the GHG reporting rule to capture even
relatively small percentages of total emissions. In all cases, the number of reporters is higher
than would be affected under the field or basin level options.
Table 8: Alternate Well-head Facility Definitions
Case 1
Case 2
Case 3
Case 4
Average emissions (tons C02e / well pad)
4,927
700
700
370
Number of Reporters
3,349
38,949
66,762
166,690
Covered Emissions (metric tons C02e)
16,498,228
40,943,092
50,572,248
87,516,080
Percent Coverage
6%
16%
19%
33%
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The petroleum and natural gas industry may be somewhat unique when calculating facility
emissions to be applied against a threshold for reporting. Subpart C in the GHG reporting
rule excluded the calculation and reporting of emissions from portable equipment. This was
one option considered for the petroleum and natural gas industry. However, given that
portable equipment is so central to many of the operations in the petroleum and natural gas
industry and such a large contributor to emissions for the industry, particularly for onshore
petroleum and natural gas production, portable equipment emissions are an important source
of emissions for inclusion a reporting rule. If these emissions were excluded from the
threshold calculation, EPA estimates that a large number of facilities would fall below the
threshold, preventing the collection of significant data from the industry that would be
beneficial to the development of future climate policies and programs. Please see "Portable
Combustion Emissions" memo under rulemaking docket EPA-HQ-OAR-2009-0923.
Another issue that concerns onshore petroleum and natural gas production is the number of
equipment operating contractors that support the well operators. It is typical to find
production well operators contracting out the majority of their process equipment from
separation, dehydration, and tanks, up to gathering and boosting and transport. Hence
requiring well operators to report only emissions from equipment they own or directly
operate could lead to a significant reduction in emissions coverage. Accordingly, the final
rule provides that emissions from such equipment must be reported whether from equipment
contracted to, leased from, owned or run by a third party. For a more full discussion of this
issue, see Vol. 9, Response to Legal Issues on Mandatory Greenhouse Gas Reporting Rule
Subpart W - Petroleum and Natural Gas.
6. Monitoring Method Options
a. Review of Existing Relevant Reporting Programs/ Methodologies
To determine applicability of the different monitoring methods available, existing programs
and guidance documents were reviewed. Table 4 shows a listing of the existing programs
and guidance documents that were reviewed. All of the program and guidance documents
provide direction on estimating CH4 and/ or C02 emissions. All documents, in general,
provide emissions rate (emissions factors) that can be used to estimate emissions and in some
cases refer to continuous emissions monitoring.
b. Potential Monitoring Methods
Depending on the particular source to be monitored in a facility, several of the currently
available monitoring methods for estimating emissions could be used.
i. Equipment Leak Detection
Traditional equipment leak detection technologies like the Toxic Vapor Analyzer (TVA) and
the Organic Vapor Analyzer (OVA) are appropriate for use in small facilities with few pieces
of equipment. However, comprehensive leak detection in large facilities can be cumbersome,
time consuming, and in many cases costly. But new infrared remote equipment leak detection
technologies are currently being used in the United States and internationally to efficiently
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detect leaks across large facilities. Considering these factors, one of the following two
technologies can be used to detect leaks in facilities depending on suitability;
Infrared Remote Equipment Leak Detectors
Hydrocarbons in natural gas emissions absorb infrared light. The infrared remote equipment
leak detectors use this property to detect leakages in systems. There are two main types of
detectors; a) those that scan the an area to produce images of equipment leaks from a source
(passive instruments), and b) those that point or aim an IR beam towards a potential source to
indicate presence of equipment leaks (active instruments).
An IR camera scans a given area and converts it into a moving image of the area while
distinctly identifying the location where infrared light has been absorbed, i.e. the equipment
leak source. The camera can actually "see" equipment leaks. The advantages of IR cameras
are that they are easy to use, very efficient in that they can detect multiple leaks at the same
time, and can be used to do a comprehensive survey of a facility. The main disadvantage of
an IR camera is that it may involve substantial upfront capital investment depending on the
features that are made available. Therefore, these cameras are most applicable in facilities
with large number of equipment and multiple potential leak sources or when purchased at the
corporate level, and then shared among the facilities, thereby lowering costs.
Aiming devices are based on infrared laser reflection, which is tuned to detect the interaction
of CH4 and other organic compounds with infrared light in a wavelength range where CH4
has strong absorption bands, but do not visually display an image of the equipment leaks.
Such devices do not have screens to view equipment leaks, but pin point the location of the
emissions with a visual guide (such as a visible pointer laser) combined with an audible
alarm when CH4 is detected. These devices are considerably less expensive than the camera
and also can detect equipment leaks from a distance (i.e. the instrument need not be in close
proximity to the emissions). More time is required for screening, however, since each
equipment (or component) has to be pointed at to determine if it is leaking. Also, if there are
multiple leaks in the pathway of the IR beam then it may not accurately detect the right
source of emissions.
Method For IR instruments that visually display an image of equipment leaks, the
background of the emissions has to be appropriate for emissions to be detectable. Therefore,
the operator should inspect the emissions source from multiple angles or locations until the
entire source has been viewed without visual obstructions to identify all emissions. For other
IR detection instruments, such as those based on IR laser reflection, instruments would have
to monitor potential emissions sources along all joints and connection points where a
potential path to the atmosphere exists. For example, a flange can potentially have leaks
along its circumference and such surfaces will have to be monitored completely by tracing
the instrument along each surface.
Calibration The minimum detectable quantity of equipment leaks using an IR instrument
depends on a number of factors including manufacturer, viewing distance, wind speed, gas
composition, ambient temperature, gas temperature, and type of background behind the
equipment leaks. For best survey results, equipment leak detection can be performed under
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favorable conditions, such as during daylight hours, in the absence of precipitation, in the
absence of high wind, and, for active laser devices, in front of appropriate reflective
backgrounds within the detection range of the instrument. The EPA Alternative Work
Practice (AWP) requires optical imaging devices to detect a minimum flow rate, specified in
Title 40 CFR Part 65 Section 7, before each use. The AWP specifies instructions for
determining the minimum detectable flow rate, the purity of the calibration gas, and the
allowed viewing distance. Equipment leak detection and measurement instrument manuals
can also be used to determine optimal operating conditions to help ensure best results.
Toxic Vapor Analyzer (or Organic Vapor Analyzer)
TVAs and OVAs consist of a flame ionization detector that is used to detect the presence of
hydrocarbons and measure the concentration of equipment leaks. It consists of a probe that is
moved close to and around the potential emissions source and an emissions detection results
in a positive reading on the instrument monitoring scale. The concentration can be used in
conjunction with correlation equations to determine the leak rate. However, concentration is
not a true measure of an emission's magnitude. Therefore concentration data from TVAs and
OVAs, for the purposes of the rule, may be best suited for screening purposes only. The
advantage of these instruments is that they have lower costs than IR cameras and several
facilities conducting Leak Detection and Repair (LDAR) programs might already have these
instruments, thereby reducing capital investment burden. But these instruments screen very
slowly given that each potential emissions source has to be individually and thoroughly
circumscribed less than 1 centimeter from the potentially leaking joints or seals.
Method TVAs and OVAs can be used for all equipment leak detection that is safely
accessible at close-range. For each potential emissions source, all joints, connections, and
other potential paths to the atmosphere would be monitored for emissions. Due to residence
time of a sample in the probe, there is a lag between when an emission is captured and the
operator is alerted. To pinpoint the source of the equipment leak, upon alert the instrument
can be slowly retraced over the source until the exact location is found.
Calibration Method 21 guidance can be used to calibrate the TVA or OVA using guidelines
from Determination of Volatile Organic Compound Leaks Sections 3, 6, and 7.
Acoustic Leak Detectors
Acoustic leak detectors are simple devices that filter out the low frequency vibrations and
noise of heavy machinery operating and sense and measure the decibel reading of high
frequency vibrations and noise of fluids leaking through small cracks or openings. Fluid flow
through open valves has little difference in sonic generated noise between the inlet and outlet
of a valve, or the valve body itself. Similarly tightly closed valves have little difference in
sonic noise measured on the inlet, outlet or valve body. Valves which are not tightly closed
(i.e. a crevice or deformation of the valve plug and seat) will generate a high frequency noise
depending on the valve type and size, the pressure drop across the closed valve, and the fluid
density. This frequency can be measured in decibels and correlated with through valve
leakage rate.
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Method
The instalment operator places the "stethoscope" like probe on the valve body or valve
flange in one or more of the recommended locations, and observes the decibel reading
displayed on the instrument digital signal indicator. This reading is documented in the field,
along with the valve identification (valve number or location descriptor). The type of fluid,
its density, and the system pressure upstream and downstream of the closed valve are also
recorded to be entered along with the valve type (ball, plug, gate, pressure relief, etc) and
nominal size) into an Excel spreadsheet supplied by the valve manufacturer. The through
valve leakage rate is calculated by correlation algorithms developed by the instrument
manufacturer.
Calibration
Calibration requirements are as provided by the manufacturer, depending on the type of
acoustic detector.
ii. Emissions Measurement
A. Direct Measurement
Three types of technologies can be used where appropriate to measure or quantify the
magnitude of emissions.
High Volume Sampler
A high volume sampler consists of a simple fixed rate induced flow sampling system to
capture the emissions and measure its volume. The emissions and the air surrounding the
emissions source are drawn into the instrument using a sampling hose. The instrument
measures the flow rate of the captured volume of air and emissions mixture. A separate
sample of the ambient air is taken by the instrument to correct for the volume of ambient air
that is captured along with the emissions.
High volume samplers have moderate costs and have a potential capacity for measuring up to
30 leaking components per hour with high precision at 0.02 percent methane. This allows for
reduced labor costs and survey times while maintaining precise results. For this reason, high
volume samplers are considered the preferred and most cost-effective direct measurement
option for emissions within their maximum range. However, large component emissions and
many vent emissions are above the high volume sampler capacity and therefore warrant the
use of other measurement instruments.
Method A high volume sampler is typically used to measure only emissions for which the
instrument can intake the entire emissions from a single source. To ensure proper use of the
instrument, a trained technician can conduct the measurements. The technician will have to
be conversant with all operating procedures and measurement methodologies relevant to
using a high volume sampler, such as positioning the instrument for complete capture of the
emissions without creating backpressure on the source. If the high volume sampler, along
with all attachments available from the manufacturer, is not able to capture all the emissions
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from the source then anti-static wraps or other aids can be used to capture all emissions
without violating operating requirements as provided in the instrument manufacturer's
manual. The attachments help capture the emissions from different points on the source
allowing the measurement of the emission by the high volume sampler.
Calibration The instrument can be calibrated at 2.5% and 100% CH4 by using calibrated
gas samples and by following the manufacturer's instructions for calibration.
Meters
Several types of meters measure natural gas flows and can be used for measurement of
emissions from sources where the volume of emissions are large like in vent stacks.
Rotameter - A rotameter consists of a tapered calibrated transparent tube and a
floating bob inside to measure emissions. To measure emissions a rotameter is placed
over an emissions source (typically vents and open ended lines) and the emissions
pass through the tube. As the emissions move through the tube it raises the floating
bob to indicate the magnitude of emissions on the calibrated scale. Rotameters are
most advantageous to use in cases where the emissions are very large. The
disadvantage though is that it can only be used on leaks where the entire emissions
can be captured and directed through the rotameter.
Turbine Meter -To measure emissions a turbine meter is placed over an emissions
source and the emissions pass through the tube. As the emissions move through the
tube it spins the turbine; the rate at which the turbine spins indicates the magnitude of
emissions. Like rotameters, turbine meters are most advantageous to use in cases
where emissions are very large. The disadvantage is that it can only be used on
emissions that can be entirely captured and directed through the meter.
Hotwire Anemometer - Hotwire anemometers measure emissions velocity by noting
the heat conducted away by the emissions. The core of the anemometer is an exposed
hot wire either heated up by a constant current or maintained at a constant
temperature. In either case, the heat lost to emissions by convection is a function of
the emissions velocity. Hotwire anemometers are best for measuring vents and open
ended lines of known cross-sectional area and do not require complete capture of
emissions. Hot wire anemometers have low levels of accuracy since they measure
velocity that is converted into mass emissions rate.
Pitot Tube Flow Meter - A simple pitot tube is a right angled tube open at one end
and closed at the other. The closed end is connected to a transducer to measure
pressure of the inflowing emissions. The open end is aligned parallel to the direction
of emissions flow. Emissions are directed into the tube so that the pressure required to
bring the air inside the tube to stagnation is measured. The difference in pressure
between the interior of the pitot tube and the surrounding air is measured and
converted to an emissions rate. Pitot tube flow meters can be used when the cross-
sectional area of an emitting vent or open ended line is known, or when the entire
emission can be directed into the tube. The pitot tube flow meter measures pressure
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differential that is converted to mass emissions rate. The pitot tube detects the flow
velocity at only one point along the flowstream, hence the placement of the pitot tube
inside the pipe where the flow is to be measured is critical to determine a
representative flow volume, and not a location-specific flow volume, which can give
erroneous results. It has relatively low accuracy compared to most flow meters, due
to the low pressure drop measured. This also makes it vulnerable to fluctuations from
turbulence changes in the flow stream. Although inaccurate compared to most
meters, the pitot tube is one of the least expensive flow meters available.
Vane Anemometer - A vane anemometer channels the emissions over a rotating vane
that in turn rotates a fan to measure the velocity of emissions. The number of
revolutions of the fan are detected and measured and converted to a flow velocity.
Using the cross section of flow of the emissions, the volumetric flow rate of
emissions can be estimated. A vane anemometer is best used for lines that have
known cross-sectional areas. The disadvantage is if the flow direction of the
emissions changes with respect to the axis of rotation of the vanes, it can result in
errors in velocity and flow rate estimation.
Method To ensure accurate measurements when using metering (e.g. rotameters, turbine
meters, and others), all emissions from a single source will have to be channeled directly
through the meter. An appropriately sized meter can be used to prevent the flow from
exceeding the full range of the meter and conversely to have sufficient momentum for the
meter to register continuously in the course of measurement.
Calibration The meters can be calibrated using either one of the two methods provided
below:
(A) Develop calibration curves by following the manufacturer's instruction.
(B) Weigh the amount of gas that flows through the meter into or out of a container
during the calibration procedure using a master weigh scale (approved by the
National Institute of Standards and Technology (NIST) or calibrated using
standards traceable by NIST) that has a very high degree of accuracy. Determine
correction factors for the flow meter according to the manufacturer's instructions,
record deviations from the correct reading at several flow rates, plot the data
points, compare the flow meter output to the actual flow rate as determined by the
master weigh scale and use the difference as a correction factor.
(C) The Final GHG Reporting Program provides guidance on calibration for meters in
section §98.3(i).
Calibrated Bagging
A calibrated bag (also known as a vent bag) made of anti-static material is used to enclose an
emissions source to completely capture all the leaking gas. The time required to fill the bag
with emissions is measured using a stop watch. The volume of the bag and time required to
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fill it is used to determine the mass rate of emissions. Calibrated bags have a very high
accuracy, since all the emissions are captured in the measurement.
Calibrated bags are the lowest cost measurement technique, and can measure up to 30
leaking components in an hour, but may require two operators (one to deploy the bag, the
other to measure time inflation). It is a suitable technique for emission sources that are
within a safe temperature range and can be safely accessed. The speed of measurement is
highly dependent on the emissions rate and the results are susceptible to human error in
enclosing the emission source and taking the measurement data, leading to lower precision
and accuracy. For those sources outside the capacity of high volume samplers and within the
limitations of bagging, this would be a second best choice for quantification.
Method Calibrated bags can be used only where the emissions are at near-atmospheric
pressures and the entire emissions volume can be captured for measurement. Using these
bags on high pressure vent stacks can be dangerous. For conducting measurement the bag is
physically held in place by a trained technician, enclosing the emissions source, to capture
the entire emissions and record the time required to completely fill the bag. Three
measurements of the time required to fill the bag can be conducted to estimate the emissions
rates. The average of the three rates will provide a more accurate measurement than a single
measurement.
Calibration To ensure accurate results, a technician can be trained to obtain consistent
results when measuring the time it takes to fill the bag with emissions.
All of the emissions measurement instruments discussed above measure the flow rate of the
natural gas emissions. In order to convert the natural gas emissions into C02 and CH4
emissions, speciation factors determined from natural gas composition analysis must be
applied. Another key issue is that all measurement technologies discussed require physical
access to the emissions source in order to quantify emissions.
B. Engineering Estimation and Emission Factors
For several emissions sources, there are viable alternatives to physical measurement for
calculating emissions. For example, emissions to the atmosphere due to emergency
conditions from vessels or other equipment and engineered emissions from equipment like
pneumatic devices can be estimated or quantified using engineering calculations. This is
referred to as engineering estimation. Emission factors can be considered for nearly every
source where emissions data is available, however, they usually have high uncertainties.
Emissions factors may be appropriate for frequent, geographically sparse emission sources
such as pneumatic devices. Several sources are outlined below along with relevant
engineering estimation methods that can be used to estimate GHG gas emissions from each
source.
1. Natural Gas Driven Pneumatic Pumps
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Leaks from natural gas driven pneumatic pumps can be calculated using data obtained from
the manufacturer for natural gas emissions per unit volume of liquid pumped at operating
pressures. This information is available from the pump manufacturer in their manuals.
Operators can maintain a log of the amount of liquids pumped annually for individual
pneumatic pumps and use Equation 1 below for calculating emissions:
Es,n =FS*V Equation 1
where,
ES:„ = Annual natural gas emissions at standard conditions in cubic feet
per year
Fs = Natural gas driven pneumatic pump gas emission in "emission per
volume of liquid pumped at operating pressure" in scf/gallon at
standard conditions, as provided by the manufacturer
V = Volume of liquid pumped annually in gallons/year
If manufacturer data for a specific pump is not available, then data for a similar pump model
of the same size and operational characteristics can be used to estimate emissions. As an
alternative to manufacturer data on pneumatic pump natural gas emissions, the operator can
conduct a one-time measurement to determine natural gas emissions per unit volume of
liquid pumped using a calibrated bag for each pneumatic pump, when it is pumping liquids.
Due to the geographically isolated nature of pneumatic pumps, if manufacturer data is not
readily available or would result in high burden to obtain the data, pneumatic pump
emissions can also be quantified using published emission factors. The use of emission
factors is less burdensome than collecting manufacturer data from each pneumatic pump but
can be inaccurate due to limited data and variable pump design. However, the resulting
information can still be useful for the purposes of informing policy because it will provide
updated activity data on the number and type of pneumatic pumps in operation. See
Appendix G for a discussion of population emission factors for pneumatic pumps and see
Section (6)(d) of the TSD for how to calculate emissions from population factors. Emissions
from natural gas driven pneumatic pumps can be calculated using an emissions factor as
follows;
Masssi = Count * EF * GHGt *Convi * 24*365 Equation 2
where,
Masssj = Annual total mass GHG emissions in metric tons per year at standard
conditions from all natural gas driven pneumatic pumps at the facility,
for GHG;
Count = Total number of natural gas driven pneumatic pumps at the facility
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EF = Population emission factors for natural gas driven pneumatic pumps
listed in Appendix G for onshore petroleum and natural gas production,
onshore natural gas transmission, and underground natural gas storage
facilities, respectively
GHGi = for onshore petroleum and natural gas production facilities,
concentration of GHG,, CH4 or CO2, in produced natural gas; for other
facilities GHG, equals 1
Conv; = conversion from standard cubic feet to metric tons C02e; 0.000410 for
CH4, and 0.00005357 for C02
24 * 365 = conversion to yearly emissions estimate
2. Natural Gas Driven Pneumatic Manual Valve Actuators
Emissions from natural gas driven pneumatic manual valve actuators can be calculated using
data obtained from the manufacturer for natural gas emissions per actuation. Operators can
maintain a log of the number of manual actuations annually for individual pneumatic devices
and use Equation 3 below:
Es,„ =AS*N Equation 3
where,
ES:„ = natural gas emissions at standard conditions
As = natural gas driven pneumatic valve actuator natural gas emissions
in "emissions per actuation" units at standard conditions, as
provided by the manufacturer.
N = Number of times the pneumatic device was actuated through the
reporting period
As an alternative to manufacturer data, the operator could conduct a one-time measurement
to determine natural gas emissions per actuation using a calibrated bag for each pneumatic
device.
3. Natural Gas Driven Pneumatic Bleed Devices
Pneumatic devices typically fall in three categories; low bleed devices, high bleed devices,
and intermittent bleed devices. Low bleed devices are devices that bleed less than 6 scf of
natural gas per hour. High bleed devices are devices that bleed more than 6 scf of natural gas
per hour.6'7 Intermittent bleed devices are snap-acting or throttling devices that discharge the
full volume of the actuator intermittently when control action is necessary, but do not bleed
continuously. Given the vast difference in bleed rates, low bleed devices contribute to a
6 "Opportunities to Reduce Anthropogenic Methane Emissions in the United States," EPA 430-R-93-012, October 1993
7 PG&E (Pacific Gas and Electric). 1990. Unaccounted for Gas Project Summary Volume, PG&E Research and
Development; San Ramon, CA: GRI-90/0067.1
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small portion of the total emissions from pneumatic devices nationally. Therefore, it may be
feasible to provide an emissions factor approach for low bleed pneumatic devices to reduce
burden. The following are two different options for determining emissions from low bleed,
high bleed, and intermittent pneumatic devices.
Emissions from a natural gas pneumatic high bleed device venting can be calculated using a
specific pneumatic device model natural gas bleed rate during normal operation as available
from the manufacturer. If manufacturer data for a specific device is not available then data
for a similar size and operation device can potentially be used to estimate emissions. The
natural gas emissions for each bleed device can be calculated as follows;
Es,n =BS* T Equation 4
where,
ES:„ = Annual natural gas emissions at standard conditions, in cubic feet
Bs = Natural gas driven pneumatic device bleed rate volume at standard
conditions in cubic feet per minute, as provided by the manufacturer
T = Amount of time in minutes that the pneumatic device has been operational
through the reporting period
Due to the geographically isolated nature of pneumatic devices, if manufacturer data is not
readily available or would result in high burden to obtain the data, pneumatic device
emissions can also be quantified using published emission factors. The use of emission
factors is less burdensome than collecting manufacturer data from each device, but can be
inaccurate due to limited data and variable design. However, the resulting information can
still be useful for the purposes of informing policy because it will provide updated activity
data on the number and type of pneumatic pumps in operation. See Appendix G for a
discussion of population emission factors for pneumatic devices and see Section (6)(d) of the
TSD for how to calculate emissions from population factors. Emissions from natural gas
pneumatic low bleed device venting can be calculated using emissions factor as follows;
Masssi = Count * EF * GHGi *Convi * 24*365 Equation 5
where,
Masssj = Annual total mass GHG emissions in metric tons per year at standard
conditions from all natural gas pneumatic low bleed device venting at
the facility, for GHG i
Count = Total number of natural gas pneumatic low bleed devices at the facility
EF = Population emission factors for natural gas pneumatic low bleed device
venting listed in Appendix G for onshore petroleum and natural gas
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production, onshore natural gas transmission, and underground natural
gas storage facilities, respectively
GHGi = for onshore petroleum and natural gas production facilities,
concentration of GHG,, CH4 or CO2, in produced natural gas; for other
facilities GHG, equals 1
Conv; = conversion from standard cubic feet to metric tons C02e; 0.000410 for
CH4, and 0.00005357 for C02
24 * 365 = conversion to yearly emissions estimate
4. Acid Gas Removal (AGR) Vent Stacks
AGR vents consist of both CO2 and CH4 emissions. CO2 emissions from AGR units can be
reliably estimated using continuous emissions monitoring (CEMS) systems, mass balance
approach, or one of the standard simulation software packages. CH4 emissions can only be
estimated using simulation software packages. It must be noted, however, that CH4 emissions
from AGR vents are insignificant, 0.06 percent of the total volume of CO2 and CH4
emissions. The mass balance approach has the advantage of being usable in systems that use
membrane, molecular sieves, or absorbents other than amines; simulation software packages
currently do not provide an option for these types of technologies.
Some facilities may have CEMS installed on their AGR unit vent stacks. In such a case, if
the CEMS can reliably measure CO2 volumes then the measurements from CEMS can
sufficiently inform on the CO2 emissions from AGR units. Alternatively, if the vent stack has
a meter on it then the CO2 emissions can be estimated using this metered vent stack gas
volume and the percent CO2 in the vent stack gas.
Operators can calculate emissions from acid gas removal vent stacks using simulation
software packages, such as ASPEN™ or AMINECalc™. Different software packages might
use different calculations and input parameters to determine emissions from an acid gas
removal unit. However, there are some parameters that directly impact the accuracy of
emissions calculation. Therefore, any standard simulation software could be used assuming it
accounts for the following operational parameters:
• Natural gas feed temperature, pressure, and flow rate;
• Acid gas content of feed natural gas;
• Acid gas content of outlet natural gas;
• Unit operating hours, excluding downtime for maintenance or standby;
• Emissions control method(s), if any, and associated reduction of emissions;
• Exit temperature of natural gas; and
• Solvent pressure, temperature, circulation rate, and weight.
CO2 emissions from AGR unit vent stacks can also be calculated using mass balance
approach from the throughput of the AGR unit and gas composition as follows;
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£fl,co2 =(v + a*(v* (Vol, - VolQ ))) * (Vol t - VolQ ) Equation 6
where,
Ea,co2 = Annual volumetric C02 emissions at actual condition, in cubic feet per
year.
V = Total annual volume of natural gas flow into or out of the AGR unit in
cubic feet per year at actual condition as determined using methods
specified in paragraph (d)(5) of this section of the TSD.
a = Factor is 1 if the outlet stream flow is measured. Factor is 0 if the inlet
stream flow is measured.
Voli = Volume fraction of C02 content in natural gas into the AGR unit as
determined in paragraph (d)(7) of this section.
Volo = Volume fraction of C02 content in natural gas out of the AGR unit as
determined in paragraph (d)(8) of this section of the TSD.
Sometimes AGR units have a continuous gas analyzer in which case they can be used to
determine Voli and Volo.
There are gas processing plants that capture CO2 for EOR or carbon sequestration projects.
In such cases, the emissions ECo2 can be adjusted downward to account for the percentage of
total emissions captured.
5. Slowdown Vent Stacks
Emissions from blowdown vent stacks can be calculated using the total physical volume
between isolation valves (including all natural gas-containing pipelines and vessels) and logs
of the number of blowdowns for each piece of equipment using Equation 7 below:
Es,n=N"
( (
K
V v
(459.67 + Ts)Pa
(459.67 + Ta)Ps
\ \
-V*C
Equation 7
y
where,
Es,n = Annual natural gas venting emissions at standard conditions from
blowdowns in cubic feet.
N = Number of repetitive blowdowns for each equipment type of a unique
volume in calendar year.
Vv = Total volume of blowdown equipment chambers (including pipelines,
compressors and vessels) between isolation valves in cubic feet.
C = Purge factor that is 1 if the equipment is not purged or zero if the
equipment is purged using non-GHG gases.
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Ts = Temperature at standard conditions (°F).
Ta = Temperature at actual conditions in the blowdown equipment chamber
(F).
Ps = Absolute pressure at standard conditions (psia).
Pa = Absolute pressure at actual conditions in the blowdown equipment
chamber (psia).
6. Dehydrator Vent
There are two predominant types of technologies that are used to dehydrate natural gas. The
first type is the most prevalent and uses liquid tri-ethylene glycol for dehydration, typically
referred to as glycol dehydrators. The second type of dehydrators use solid desiccants to
extract water from natural gas. For glycol dehydrators, when contacted with natural gas for
dehydration, the glycol absorbs some amount of natural gas, which is released as emissions
during its regeneration. Standard simulation software packages that use some form of
equilibrium analysis can estimate emissions from such liquid glycol type dehydrators. On the
other hand, in desiccant dehydrators the solid desiccant itself does not absorb any significant
quantities of natural gas. But emissions result when the desiccant dehydrator is opened to the
atmosphere for the regeneration of the desiccant, which results in the release of natural gas
trapped in the desiccant dehydrator vessel. Hence, for desiccant dehydrators standard
simulation software packages cannot be used. However, calculative methods can be used to
determine emissions from solid desiccant type dehydrators. The two monitoring methods for
the two different types for dehydrators are as below.
Emissions from a dehydrator vents can be calculated using a simulation software package,
such as GLYCalc™. There may be several other simulation packages, such as Aspen
HYSYS, that can also estimate emissions from glycol dehydrators. However, GLYCalc™ is
the most widely used software and referenced by several State and Federal agencies in their
programs and regulations. Different software packages might use different calculations and
input parameters to determine emissions from dehydration systems. However, there are some
parameters that directly impact the accuracy of emissions calculation. Therefore, any
standard simulation software could be used provided it accounts for the following operational
parameters:
• Feed natural gas flow rate;
• Feed natural gas water content;
• Outlet natural gas water content;
• Absorbent circulation pump type(natural gas pneumatic/ air pneumatic/ electric);
• Absorbent circulation rate;
• Absorbent type: including, but not limited to, triethylene glycol (TEG), diethylene
glycol (DEG) or ethylene glycol (EG);
• Use of stripping natural gas;
• Use of flash tank separator (and disposition of recovered gas);
• Hours operated; and
• Wet natural gas temperature, pressure, and composition.
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For dehydrators that use desiccant emissions can be calculated from the amount of gas vented
from the vessel every time it is depressurized for the desiccant refilling process using
Equation 8 below:
_ (H * D2 * P* P2*%G*365days /yr)
*•" ~ (4 *PX *r*l,000c//Mcf* 100) Equation 8
where,
ESi„ = Annual natural gas emissions at standard conditions
H = Height of the dehydrator vessel (ft)
Dv = Inside diameter of the vessel (ft)
Pi = Atmospheric pressure (psia)
P2 = Pressure of the gas (psia)
P = pi(3.14)
G% = Percent of packed vessel volume that is gas
T = Time between refilling (days)
100 = Conversion of %G to fraction.
Some dehydrator vented emissions are sent to a flare. Annual emissions from dehydrator
vents sent to flares can be calculated using the methodology under Section 8 of the TSD for
flares. Alternatively, a simple combustion efficiency factors, such as 98 percent, can be used
in conjunction with a C02 emissions factor for natural gas to estimate emissions from glycol
dehydrator vents to flare stack.
7. EOR injection pump blowdown.
EOR operations use pumps to inject supercritical phase C02 into reservoirs. For
maintenance, these pumps may be blown down to release all the supercritical phase CO2. The
volume of C02 released to during such blow down practices can be calculated using the total
volume between isolation valves (including, but not limited to, pipelines, compressors and
vessels).The emissions can be calculated using Equation 9 below.
Massc i = N *Vv* Rc* GHGi * 10 3 Equation 9
where,
Massc,i = Annual EOR injection gas venting emissions in metric tons at critical
conditions "c" from blowdowns.
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Rc
N
Vv
Number of blowdowns for the equipment in calendar year.
Total volume in cubic meters of blowdown equipment chambers
(including, but not limited to, pipelines, compressors and vessels
between isolation valves.
Density of critical phase EOR injection gas in kg/m3. Use an appropriate
standard method published by a consensus-based standards organization
to determine density of super critical EOR injection gas.
GHGi = mass fraction of GHG/in critical phase injection gas
C. Emission Factors
The EPA/ GRI and EPA/Radian studies provide emissions factors for almost all the
emissions sources in the petroleum and natural gas industry. These can potentially be used to
estimate emissions for reporting under the rule. However, the emissions factors are not
appropriate for all the emissions sources. The emissions factors were developed more than a
decade ago when the industry practices were much different from now. In some cases, the
emissions factors were developed using limited sample data and knowledge about the
industry's operations (e.g., wells, compressors). While the available emission factors alone
may not be appropriate for GHG reporting, certain emission factors may be sufficient, under
certain circumstances, to calculate and characterize GHG emissions. Also, the introduction
of many emissions reduction technologies are not reflected in the emissions factor estimates.
However, the two studies provide raw emission data that in conjunction with newer
publically available data (e.g., Clearstone 2006 study) could be used for developing emission
factors for certain sources. Refer to Section 4(c)(ii), 6(c), and Appendix F and G of the TSD
for a complete discussion of the use of emission factors in the reporting rule.
D. Combination of Direct Measurement and Engineering Estimation
Emissions from several sources can be estimated using a combination of direct measurement
and engineering estimation. Direct measurement can provide either a snapshot of the
emissions in time or information on parameters that can be used for using a calculative
method to estimate emissions. Following are options for using such a combination of
monitoring methods to estimate emissions.
8. Flare stacks
Flares typically burn two types of hydrocarbon streams; continuous and intermittent.
Continuous streams result from vented emissions from equipment such as glycol dehydrators
and storage tanks. Intermittent streams result from such sources as emergency releases from
equipment blowdown. It must be noted that most of these streams, continuous or intermittent,
can be covered using monitoring methods already provided on an individual emissions
source level.
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Flare emissions whether from continuous or intermittent streams can be monitored using one
of the following monitoring methods
Method 1:
Many facilities, such as in the processing sector, may already have a continuous flow monitor
on the flare. In such cases, the measured flow rates can be used when the monitor is
operational, to calculate the total flare volumes for the calendar year.
Method 2:
Another option is to require the estimation of all streams of hydrocarbons going to the flare at
an individual emissions source level. Here engineering calculation and other methods
described for different sources in this Section of the TSD can be used to estimates of volume
flare gas
Method 3:
When the flare stream is mostly continuous, a flow velocity measuring device (such as hot
wire anemometer, pitot tube, or vane anemometer) can be inserted directly upstream of the
flare stack to determine the velocity of gas sent to flare. The GHG volumetric emissions at
actual conditions can then be calculated as follows.
Ea CHA{un - combusted ) = Va * (1 - rj) * XCH4
Ea.coi {un - combusted )=Va*XCQ2
Ea,co2 (combusted) = Y.'fV^Y, *R.
j
Ea t =EaC01 (combusted) + Ea t (un - combusted)
Equation 10
Equation 11
Equation 12
Equation 13
where,
Ea: j (un-combusted)
Ea,co2(combusted)
Ea/total)
Va
Contribution of annual un-combusted emissions from
flare stack in cubic feet, under ambient conditions, for
both CH4 and C02 as described in Equation 10 and
Equation 11.
Contribution of annual emissions of CO2 from
combustion from flare stack, in cubic feet, under ambient
conditions
Total annual emissions from flare stack in cubic feet,
under ambient conditions
Volume of natural gas sent to flare in cubic feet, during
the year
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if = Percent of natural gas combusted by flare (default is 98
percent)
Xi = Concentration of GHG, in gas to the flare; where i = CO2
or CH4.
Yj = Concentration of natural gas hydrocarbon constituents j
(such as methane, ethane, propane, butane, and pentanes
plus).
Rj = Number of carbon atoms in the natural gas hydrocarbon
constituent /; 1 for methane, 2 for ethane, 3 for propane, 4
for butane, and 5 for pentanes plus)
In some cases the facility may have a continuous gas composition analyzer on the flare. Here
the compositions from the analyzer can be used in calculating emissions. If an analyzer is not
present then a sample of the gas to the flare stack can be taken every quarter to evaluate the
composition of GHGs present in the stream. The natural gas composition analyses can be
conducted using ASTM D1945-03. It must be noted that for processing plants there are two
distinct streams of natural gas with significant differences in composition. The natural gas
stream upstream of the de-methanizer can be expected to have higher C2+ components as
opposed to the residue stream downstream of the de-methanizer. In addition, the CO2 content
in natural gas can change significantly after acid gas removal. Finally, processing plants may
send pure streams of separated hydrocarbons such as ethane, propane, butane, iso-butane, or
pentanes plus to the flare during an emergency shutdown of any particular equipment. Such
variations in hydrocarbon streams being sent to the flare would have to be accounted for in
the monitoring methodology.
9. Compressor wet seal degassing vents
In several compressors, the wet seal degassing vents emit flash gas from degassed oil straight
into or close to the compressor engine exhaust vent stack. The temperatures at the degassing
vent exit are very high due to the proximity to the engine exhaust vent stack. In such cases,
emissions can be estimated using a flow velocity measuring device (such as hot wire
anemometer, pitot tube) or a flow rate measurement device such as vane anemometer, which
can be inserted directly upstream of the degassing unit vent exit to determine the velocity or
flow rate of gas sent to the vent. If a velocity measuring device is used then the volume of
natural gas sent to vent can be calculated from the velocity measurement using the
manufacturer manual for conversion. Annual emissions can be estimated using meter flow
measurement as follows:
EaJ =MT * T*Mt*(l-B) Equation 14
where,
Ea,i = Annual GHG; (either CH4 or CO2) volumetric emissions at ambient
conditions
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MT = Meter reading of gas emissions per unit time
T = Total time the compressor associated with the wet seal(s) is operational in
the calendar year
Mi = Mole percent of GHG, in the degassing vent gas
B = percentage of centrifugal compressor wet seal degassing vent gas sent to
vapor recovery or fuel gas or other beneficial use as determined by keeping
logs of the number of operating hours for the vapor recovery system or
recycle to fuel gas system
A sample representative of the gas to the degassing vent can be taken every quarter to
evaluate the composition of GHGs present in the stream using ASTM D1945-03. Some
facilities may send their degassing vent vapors to a flare or to fuel use. The monitoring
method will have to account for this.
10. Reciprocating compressor rod packing venting
There are three primary considerations for emissions from rod packing on reciprocating
compressors. First, the rod packing case may or may not be connected to an open ended line
or vent. Second, the rod packing may leak through the nose gasket in addition to the
emissions directed to the vent. And third, the emissions from rod packing will vary
depending on the mode of operation of the reciprocating compressor - running, standby and
pressurized, or standby and de-pressurized.
If the rod packing case is connected to an open ended line or vent then emissions from the
rod packing case can be estimated using bagging or high volume sampler. Alternatively, a
temporary meter such as vane anemometer or permanent meter such as orifice meter can be
used to measure emissions from rod packing vents.
If the rod packing case is open to the atmosphere then the emissions from the rod packing
case will be mingled with the emissions from the nose gasket. The emissions from an open
rod packing case usually will migrate to the distance piece (dog house), and if the distance
piece is enclosed then this emissions will migrate to the engine crank case, before being
emitted to the atmosphere. There are two possible options to monitor these emissions. The
first option is to use an emissions factor for rod packing along with a population count. The
second option is to require equipment leak detection and measurement to determine the exact
location and volume of emission.
Typically, rod packing emissions vary with the mode of operation of the compressor. The
emissions are highest when the compressor is operating and lower when they are in standby
pressurized mode. When the compressor is standby de-pressurized there might be some
migration of natural gas from the unit isolation valve through the rod packing. But rod
packing emissions from leaking unit isolation valves is for the most part negligible because
unit isolation valves leak primarily through the blowdown vent stack. Hence to correctly
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characterize annual emissions from rod packing, estimation of emissions at two compressor
modes, operating and standby pressurized, may be required.
11. Compressor isolation valve and blowdown valve
Blowdown valves on a compressor are used to depressurize and release all of the natural gas
in the compressor chambers when the compressor is taken offline. These blowdown valves,
however, can leak in some cases when the compressor is in operating or standby pressurized
modes. Isolation valves are used to isolate the compressor chambers from the pipeline that
connects the natural gas flow into and out of the compressor. These isolation valves can leak
when the compressor is take offline. Both the blowndown valve and isolation valve are
typically connected to the blowdown vent system. The emissions from leaks in an isolation
valve or blowdown valve can be detected and measured using detection and measurement
methods as discussed in Sections (6)(b)(i) and (6)(b)(ii)(A) of the TSD.
12. Storage tanks
Emissions from storage tanks can be estimated using one of the following four methods.
Method 1:
In the case of storage tanks, emissions rates are not constant; and thus, a one-time
measurement may not provide accurate emissions rates for the entire reporting period. To
accurately estimate emissions from storage tanks, it is necessary to conduct multiple
measurements during a cycle of operation that is representative of the tank operations
through the year. Equation 15 below can be used to calculate GHG emissions:
Ea,h ~QX ER Equation 15
where,
Ea,h = hydrocarbon vapor emissions at ambient conditions, in cubic meters
Q = storage tank total annual throughput, in barrels
ER = measured hydrocarbon vapor emissions rate per throughput (e.g.
meter/barrel)
ER can be estimating using the following procedure:
• The hydrocarbon vapor emissions from storage tanks can be measured using a
flow meter for a test period that is representative of the normal operating
conditions of the storage tank throughout the year and which includes a complete
cycle of accumulation of hydrocarbon liquids and pumping out of hydrocarbon
liquids from the storage tank.
• The throughput of the storage tank during the test period can be recorded.
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• The temperature and pressure of hydrocarbon vapors emitted during the test
period can be recorded.
• A sample of hydrocarbon vapors can be collected for composition analysis.
Method 2:
A second method is to use simulation software such as E&P Tank (GEO-RVP) to estimate
vented emissions from storage tanks. Therefore, any standard simulation software could be
used assuming it accounts for the following operational parameters:
• Feed liquid flow rate to tank;
• Feed liquid API gravity;
• Feed liquid composition or characteristics;
• Upstream (typically a separator) pressure;
• Upstream (typically a separator) temperature;
• Tank or ambient pressure; and
• Tank or ambient temperature;
• Sales oil API gravity;
• Sales oil production rate;
• Sales oil Reid vapor pressure;
A third method to estimating emissions from storage tanks is to use the Peng-Robinson
equation directly instead of using a simulation software. The Peng-Robinson equation is the
basis behind most of the simulation softwares and therefore will result in estimates similar to
Method 2 above.
Method 3:
RT
aa
p V.-b V;+2bVm-b2
Equation 16
where:
p = Absolute pressure
R = Universal gas constant
T = Absolute temperature
Vm = Molar volume
0.45724i?2rc2
Pc
0.7780i?rc
Pc
(
1 + (o.37464 + 1.54226® - 0.26992®2
¦v\2
a
\
where:
Q = Acentric factor of the species
Tc = Critical temperature
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Pc = Critical pressure
Method 4:
A conservative method to estimate GHG emissions from flashing in storage tanks is to take a
sample of liquids at the low pressure separator (i.e. the last separator before the liquids enter
the storage tank) and then assume that all the CH4 and C02 dissolved in this sample is
released to the atmosphere.
Method 5:
A fifth method for storage tank vented emissions quantification is use of the Vasquez-Beggs
equation. This correlation equation provides an estimate of the gas-to-oil ratio for flashing
tank vapors; however, it does not provide the GHG of the vapors, so composition analysis of
tank vapors is still required. Equation 17 demonstrates the use of this correlation equation:
( CxC ^
GOR= AxGfgx (Psep + 14.7)x exp — Equation 17
I sep + j
where,
GOR = ratio of flash gas production to standard stock tank barrels of oil produced,
in standard cubic feet/barrel (barrels corrected to 60°F)
Gfg = Specific gravity of the tank flash gas, where air = 1. A suggested default
value for Gfg is 1.22
Goii = API gravity of stock tank oil at 60°F
Psep = Pressure in separator (or other vessel directly upstream), in pounds per
square inch gauge
Tsep = Temperature in separator (or other vessel directly upstream of the tank), °F
A = 0.0362 for Goii30°API
B = 1.0937 for Goii30°API
C = 25.724 for Goii 30°API
Sometimes one or more emissions source vents may be connected to the storage tank. In such
cases the emissions from these sources will be commingled with the emissions from the
storage tank. In addition, two phase separators directly upstream of the storage tank may not
have a vortex breaker. This can lead to channeling of natural gas from the separator to the
storage tank. All these multiple scenarios mean that only Method 1 could potentially capture
such miscellaneous sources connected to the storage tank. If, however, Method 1 is
performed at a time when say the separator is not vortexing then even Method 1 may not
capture the emissions from the miscellaneous emissions sources connected to the storage
tank. Hence there is no single method that can identify these variations in storage tank
emissions that represent multiple sources. These data are available from two recent studies
provided by the Texas Commission on Environmental Quality (2009) and the Texas
Environment Research Consortium (2009) that highlight this fact. A potential option to
correct such scenarios where other emissions sources are connected to the storage tank or if
the separator is vortexing is to use multipliers on emissions estimated from Methods 1 and 2
above. Two such potential multipliers are as below,
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(i) The emissions for sales oil less than 45 API gravity can be multiplied by 3.87
(ii) The emissions for sales oil equal to or greater than 45 API gravity can be
multiplied by 5.37
Details on the development of these multipliers are available in Appendix E.
Dump Valve Emissions Estimation
Storage tank vented emissions quantification could include the emissions that result from a
gas-liquids separator liquid dump valve malfunction. Liquid dump or scrubber dump valves
open periodically to reduce the accumulation of liquids in the separator. Scrubber dump
valves can get stuck open due to debris preventing it from closing properly. In such a case,
natural gas from the separator is lost through the dump valve ultimately passing through the
storage tank's atmospheric vent. Equation 18, below, can be used to account for storage tank
emissions with improperly closed scrubber dump valves.
Es,i - (CFn xEnxTn)+(Enx (§760-Tn)) Equation 18
where,
ESJ = Annual total volumetric GHG emissions at standard conditions from each
storage tank in cubic feet.
En = Storage tank emissions as determined in calculation methods 1, 2, or 5
(with wellhead separators) of this section of the TSD during time Tn in
cubic feet per hour.
Tn = Total time the dump valve is not closing properly in the calendar year in
hours. Tn is estimated by maintenance or operations records (records) such
that when a record shows the valve to be open improperly, it is assumed
the valve was open for the entire time period preceding the record starting
at either the beginning of the calendar year or the previous record showing
it closed properly within the calendar year. If a subsequent record shows it
is closing properly, then assume from that time forward the valve closed
properly until either the next record of it not closing properly or, if there is
no subsequent record, the end of the calendar year.
CFn = Correction factor for tank emissions for time period Tn is 3.87 for sales oil
less than 45 API gravity. Correction factor for tank emissions for time
period Tn is 5.37 for sales oil equal to or greater than 45 API gravity.
Correction factor for tank emissions for time period Tn is 1.0 for periods
when the dump valve is closed.
Et = Storage tank emissions as determined in calculation methods 1, 2, or 3 of
this section of the TSD at maintenance or operations during the time the
dump valve is closing properly (ie.8760-Tn) in cubic feet per hour.
Transmission Storage Tanks:
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Storage tanks in the onshore natural gas transmission segment typically store the condensate
from the scrubbing of pipeline quality gas. The volume of condensate is typically low in
comparison to the volumes of hydrocarbon liquids stored in the upstream segments of the
industry. Hence the emissions from condensate itself in the transmission segment are
insignificant. However, scrubber dump valves often get stuck due to debris in the condensate
and can remain open resulting in natural gas loss via the open dump valve. If the scrubber
dump valve is stuck and leaking natural gas to the tank then the emissions will be visibly
significant and will not subside to inconspicuous volumes. If the scrubber dump valve
functions normally and shuts completely after the condensate has been dumped then the
storage tank emissions should subside and taper off to insignificant quantities; this will
happen because once the condensate has flashed the dissolved natural gas there will not be
significant emissions from the storage tank. If persistent and significant emissions are
detected then a measurement of those emissions may be required using a temporary meter or
ultrasonic devices that can detect and measure the emissions in a non-invasive way.
Storage tank vapors captured using vapor recovery systems or sent to flares will have to be
accounted for in the above methods.
13. Well testing venting and flaring
During well testing the well usually is flowing freely and the produced hydrocarbons are
typically vented and/ or flared. A gas to oil ratio is often determined when conducting well
testing. This information can be reliably used to estimate emissions from well testing
venting using Equation 19 below:
Esn =GOR *FR*D Equation 19
where,
ES:„ = Annual volumetric natural gas emissions from well testing in cubic feet
under actual conditions
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to
hydrocarbon liquids produced of all API gravities
FR = Flow rate in barrels of oil per day for the well being tested
D = Number of days during the year the well is tested
When well testing emissions are sent to a flare then the emissions estimated above should be
adjusted to reflect the combustion emissions.
14. Associated gas venting and flaring
Often times when onshore petroleum production fields are located in a remote location, the
associated gas produced is sent to a vent or flare. This is because the associated natural gas
is stranded gas, meaning that it is not economical to send the usually low volumes to the
market via a pipeline system. Also, gas from producing wells may sometimes be routed to a
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vent or a flare due to system upset conditions or for maintenance of field equipment. In such
cases the emissions can be estimated using the volume of oil produced and the corresponding
gas to oil ratio as following;
Vented associated natural gas emissions can be estimated using Equation 20 below:
Ea,„ = GOR *V Equation 20
where,
Ea,n = Annual volumetric natural gas emissions from associated gas venting
under actual conditions, in cubic feet
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to
hydrocarbon liquids produced of all API gravities
V = Total volume of oil produced in barrels in the calendar year.
When well testing emissions are sent to a flare then the emissions estimated above will have
to be adjusted to reflect the combustion emissions.
15. Hydrocarbon liquids dissolved CO2
Onshore petroleum production that uses EOR with CO2 injection results in the production of
petroleum that has significant amounts of CO2 dissolved in it. This CO2 is usually separated
from the liquid petroleum component, and re-injected in a closed loop system (although this
CO2 might be eventually recovered when the EOR operation at the site is closed). However,
the liquid portion of petroleum still contains dissolved CO2, since separation usually takes
place at higher than ambient pressure. Most of this CO2 is then released in a storage tank
where the CO2 flashes out of the liquid hydrocarbons. But even after this stage some amount
of CO2 remains entrapped in the liquid hydrocarbons and is lost to the atmosphere during the
transportation and processing phases.
The amount of CO2 retained in hydrocarbon liquids after flashing in tanks can be determined
by taking quarterly samples to account for retention of C02 in hydrocarbon liquids
immediately downstream of the storage tank. The emissions from this hydrocarbon
dissolved C02 can be estimated using Equation 21 below:
MassSj C02 = Sm * Vhi Equation 21
where,
Masss: C02 = Annual CO2 emissions from CO2 retained in hydrocarbon liquids
beyond tankage, in metric tons.
Sm = Amount of C02 retained in hydrocarbon liquids in metric tons per
barrel, under standard conditions.
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Vm = Total volume of hydrocarbon liquids produced in barrels in the
calendar year.
16. Produced water dissolved CO2
EOR operations may use water injection techniques to pressurize the reservoir and drive the
hydrocarbons containing C02 through the reservoir and up the production well. This water,
like the liquid petroleum, contains dissolved CO2, since CO2 readily dissolves in water. This
produced water is re-circulated for injection into the reservoir. However, often it may be sent
through tankage to avoid a two phase flow of CO2 and water through the injection pumps. In
such cases the C02 dissolved in the water is flashed to the atmosphere in the storage tank.
These emissions can be determined similar to hydrocarbon dissolved CO2 by sampling the
water on a periodic basis. To determine retention of CO2 in produced water immediately
downstream of the separator where hydrocarbon liquids and produced water are separated the
following equation can be used.
Mass, C02 = Spw * Vpw Equation 22
where,
MassSi C02 = Annual C02 emissions from C02 retained in produced water beyond
tankage, metric tons.
Spw = Amount of CO2 retained in produced water in metric tons per barrel, under
standard conditions.
Vpw = Total volume of produced water produced in barrels in the calendar year.
EOR operations that route produced water from separation directly to re-injection into the
hydrocarbon reservoir in a closed loop system without any leakage to the atmosphere could
be exempted from reporting.
17. Well venting for liquids unloading
There are three potential methods to estimate well venting emissions from liquids unloading.
Method 1 requires installation of a flow meter temporarily for developing an emissions
factor. Method 2 requires a transient pressure spike engineering analysis across the vent pipe
during one well unloading event. Method 3 uses an engineering calculation method that uses
the well's physical parameters to estimate emissions. Each of the three options is discussed
below.
Method 1:
For each unique well tubing diameter and producing horizon/formation combination in each
gas producing field where gas wells are vented to the atmosphere to expel liquids
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accumulated in the tubing, a recording flow meter can be installed on the vent line used to
vent gas from the well (e.g. on the vent line off the separator or a storage tank). An
emissions factor can be estimated as an average flow rate per minute of venting calculated
for each unique tubing diameter and producing horizon/formation combination in each
producing field. The emission factor can be applied to all wells in the field that have the
same tubing diameter and producing horizon/formation combination, multiplied by the
number of minutes of venting of all wells of the same tubing diameter and producing
horizon/formation combination in that field. A new factor can be determined periodically to
track field declining formation pressure and flow potential.
Method 2:
For each unique well tubing diameter and producing horizon/formation combination in each
gas producing field where gas wells are vented to the atmosphere to expel liquids
accumulated in the tubing, an engineering analysis of the transient pressure spike across the
vent line for well unloading events can be conducted. An emissions factor as an average
flow rate per minute of venting can then be calculated through such an analysis. This
emissions factor can be applied to all wells in the field that have the same tubing diameter
and producing horizon/formation combination, multiplied by the number of minutes of
venting all wells of the same tubing diameter and producing horizon/formation combination
in that field. A new emission factor can be determined periodically to track field declining
formation pressure and flow potential. Emissions from well venting for liquids unloading
can be calculated using Equation 23 below:
Es,„ = T * X * EF Equation 23
where,
F =
T
X
EF
Annual natural gas emissions at standard conditions
Amount of time of well venting
Concentration of GHG i in gas vented.
Emission factor developed using the transient pressure spike
For wells that have a plunger lift installed on a timer or programmable logic controller that
vent to the atmosphere and automatically closes the vent valve when the plunger is received
at the well head, an equation calculating the volume of gas in the tubing string calculated at
sales pipeline pressure can be used. This equation is unique for each category of wells with
the same well depth and tubing size. The emissions factor can be estimated by multiplying
the tubing cross-sectional area by the tubing string length from wellhead to the bottom
resting location of the plunger, corrected for sales line pressure and average gas flowing
temperature.
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Method 3:
The Natural Gas STAR Lessons Learned - Installing Plunger Lift Systems in Gas Wells
(available at ) provides an engineering
estimation method in its Appendix. This method uses physical characteristics of the well that
are usually well known. Using this method, emissions from well venting for liquids
unloading can be calculated using Equation 24 below:
Ea,„ = {(0.37X10'3) *CD2 * WD* SP*V}+ . ..
{SFR *(HR-T) *Zj Equation 24
where,
ES:„ = Annual natural gas emissions at actual conditions, in cubic feet/year
0.37x10'3 = {pi(3.14)/4}/{(l 4.7*144) psia converted to pounds per square feet}
CD = Casing diameter (inches)
WD = Well depth (feet)
SP = Shut-in pressure (psig)
V = Number of vents per year
SFR = Average sales flow rate of gas well in cubic feet per hour
HR = Hours that the well was left open to the atmosphere during unloading
T =1 hour for average well to blowdown casing volume at shut-in
pressure for wells without plunger lift assist; 0.5 hour for average
well to blowdown tubing volume at sales line pressure when using
plunger lift assist.
Z = If HR is less than 1.0 then Z is equal to 0. If HR is greater than or
equal to 1.0 then Z is equal to 1.
For details on the time taken to blowdown a casing and tubing to unload a well, see "Change
to Rule Equation W-7: Time to Vent the Casing Gas from Well Liquids Unloading" in the
rulemaking docket (EPA-HQ-OAR-2009-0923)
18. Gas well venting during well completions and workovers
There are two methods to estimate emissions from gas well venting during well completions
and workovers. Method 1 requires the installation of a recording flow meter on the vent line
to the atmosphere or to a flare. Method 2 is an engineering calculation for flow based on the
pressure drop across the well choke for subsonic and sonic flow. Method 3 uses the
production of the well to determine emissions.
Method 1:
A recording flow meter can be installed on the vent line to the atmosphere or to a flare during
each well completion or workover event. This one time reading can be extrapolated to yearly
emissions based on the time taken for completion or workover and the number of times the
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well is worked over (if more than once per year). Such emissions factors can be developed
for representative wells in a field on a yearly basis. During periods when gas is combusted in
a flare, the carbon dioxide quantity can be determined from the gas composition with an
adjustment for combustion efficiency. This method can also be used when phase separation
equipment is used and requires the installation of a recording flow meter on the vent line to
the atmosphere or to a flare.
Emissions from gas well venting during well completions and workovers can be calculated
using Equation 25 below:
Ea,n = T * FR - EnF - SG Equation 25
where,
Ea,„ = Annual natural gas vented emissions at ambient conditions in cubic feet
T = Cumulative amount of time in hours of well venting during the reporting
period
FR = Flow rate in cubic feet per hour, under ambient conditions
EnF = Volume of C02 or N2 injected gas in cubic feet at standard conditions that
was injected into the reservoir during an energized fracture job. If the
fracture process did not inject gas into the reservoir, then EnF is 0. If
injected gas is CO2 then EnF is 0.
SG = Volume of natural gas in cubic feet at standard conditions that was
recovered into a sales pipeline. If no gas was recovered for sales, SG is 0.
Method 2:
Using pressures measured upstream and downstream of the well choke, the average flow rate
across the choke can be calculated. Using engineering judgment and the total time that flow
across the choke is occurring, the total volume to the atmosphere or a flare during the back-
flow period can be estimated. This one time reading can be extrapolated to yearly emissions
based on the time taken for completion or workover and the number of times the well is
worked over (if more than once per year). Such emissions factors can be developed for
representative wells in a field on a yearly basis.
Emissions from gas well venting during well completions and workovers can be calculated
using Equation 26 for subsonic flow and Equation 27 for sonic flow below:
FR = 1.27*105 * A* T„
where,
yA
Equation 26
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FR = Average flow rate in cubic feet per hour, under subsonic flow
conditions.
A = Cross sectional area of orifice (m2).
Pi = Upstream pressure (psia).
Tu = Upstream temperature (degrees Kelvin).
P2 = Downstream pressure (psia).
3430 = Constant with units of m2/(sec2 * K).
1.27* 105 = Conversion from mVsecond to ftVhour.
FR = 1.27 *105 * A* yjl87.08* Tu Equation 27
FR
Average flow rate in cubic feet per hour, under sonic flow conditions
A
Cross sectional area of orifice (m2).
Tu
Upstream temperature (degrees Kelvin).
187.08
Constant with units of m2/(sec2 * K).
1.27* 105 =
Conversion from mVsecond to ftVhour.
Method 3:
A quick and least burdensome method to determine emissions from well venting during
completions and workovers is to use the daily gas production rate to estimate emissions using
Equation 28 below:
where,
Ea,n -Y/f*Tf Equation 28
Ea,n = Annual natural gas emissions in cubic feet at actual conditions from gas
well venting during well completions and workovers without hydraulic
fracturing.
/ = Total number of well completions without hydraulic fracturing in a field.
Vf = Average daily gas production rate in cubic feet per hour of each well
completion without hydraulic fracturing. This is the total annual gas
production volume divided by total number of hours the wells produced
to the sales line. For completed wells that have not established a
production rate, you may use the average flow rate from the first 30 days
of production. In the event that the well is completed less than 30 days
from the end of the calendar year, the first 30 days of the production
straddling the current and following calendar years shall be used.
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Tf = Time each well completion without hydraulic fracturing was venting in
hours during the year.
19. Onshore production combustion emissions
The combustion process is well understood in terms of GHG emissions. The use of emissions
factors is reliable if the quantity and type of fuel combustion is known. The alternative is to
use combustion emissions stack monitors, which are cost prohibitive and may not be
considered appropriate for onshore production. Onshore production segment does not meter
its fuel, since most of the equipment in the field is located upstream of the lease meter.
However, requiring meters at every single well site to measure fuel volume is not feasible in
terms of cost. Hence, the use of heat rating of the equipment along with the hours of
operations is the most feasible approach to estimate the amount of fuel consumed. Using the
emissions factors approach, GHG emissions from combustion equipment can be estimated
using broadly two methods; fuel specific emissions factors and equipment specific fuel
factors. Fuel specific emissions factors are related to a particular type of fuel in use and do
not take into account the type of equipment (e.g. whether internal or external combustion
equipment). The advantage of this type of approach is that if the fuel volume for a facility is
known then there is no need to identify the particular equipment that is combusting it. The
disadvantage in this method though is that it does not take into account the differing levels of
efficiency between different types of equipment. On the other hand, equipment specific
emissions factors take into account the efficiency levels of each equipment type
corresponding with the type of fuel it combusts. However, the disadvantage of using
equipment specific emissions factors is that fuel consumption has to be known at an
equipment level. Both fuel specific and equipment specific emissions factors are available
form the API Compendium and EPA AP-42 documents.
20. Natural gas distribution combustion emissions
The combustion emissions from natural gas distribution result mainly from inline gas heaters,
small compressors, etc. Heaters are used to prevent natural gas dropping below the dew point
(where liquids, mainly water, might condense) or to maintain the temperature of gas let-down
in pressure from high pressure transmission pipelines to low pressure distribution gate station
metering systems. The Joule-Thompson effect causes gas temperature to drop when the gas is
suddenly expanded across a valve or orifice. Thus, transmission pressure gas at, for example
1000 psig and ambient temperature of 70°F can drop well below freezing when depressurized
to 100 psig. This gas may be heated to a temperature above so-called "dry" gas dew point or
a range consistent with distribution gate station meter calibrations. These are usually small
sources of emissions and may not contribute significantly to the total emissions from the
distribution segment. However, some natural gas distribution systems operate compressor
stations that are similar in size and operations to the natural gas transmission or gas storage
systems. These compressor stations may have significant emissions and could be captured
under combustion emissions reporting.
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c. Leak detection and leaker emission factors
For leaks from standard components such as connectors, valves, meters, etc. emissions can
be estimated by conducting an equipment leak detection program and applying a leaker
emissions factor to those sources found to be emitting. This option may be considered over
direct measurement (e.g., high flow sampler) to avoid the capital cost in measurement
equipment and labor hours to conduct measurement. Estimating emissions using leaker
emission factors is more accurate than population factors because leaker factors are applied
to leaks once they are identified. Since equipment leaks occur randomly within a population
of components, determining the number of actual leaking component improves the emissions
estimate. Equation 29, below, can be used for this purpose.
E,,=GffG, »££/?,. Equation 29
where,
Esj = Annual total volumetric GHG emissions at standard conditions from
each equipment leak source in cubic feet.
x = Total number of this type of emissions source found to be leaking during
Tx.
EFe = Leaker emission factor for specific sources
GHGi = For onshore petroleum and natural gas production facilities and onshore
natural gas processing facilities,, concentration of GHG;, CH4 or CO2, in
the total hydrocarbon of the feed natural gas; other segments GHG;
equals 1 for CH4 and 1.1 x 10"2 for CO2.
Tx = The total time the component was found leaking and operational, in
hours. If one leak detection survey is conducted, assume the component
was leaking for the entire calendar year. If multiple leak detection
surveys are conducted, assume that the component found to be leaking
has been leaking since the previous survey or the beginning of the
calendar year. For the last leak detection survey in the calendar year,
assume that all leaking components continue to leak until the end of the
calendar year.
Leaker emissions factors are available for specific sources for onshore natural gas
processing facilities, onshore natural gas transmission compression facilities,
underground natural gas storage facilities, liquefied natural gas storage facilities,
liquefied natural gas import and export facilities, and natural gas distribution
facilities. These leaker emissions factors and a discussion on their development are
available in Appendix F.
d. Population Count and Emission Factors.
For equipment leaks that are geographically dispersed or where the cost burden is an issue,
emissions can be estimated using the population count of emissions sources and a
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corresponding population emissions factor. This option may be considered over direct
measurement to avoid the cost of purchasing a high volume sampler, screening device, and
the labor hours to use both. Such an option may be most feasible for emissions sources with
gas content greater than 10 percent CH4 plus C02 by weight since otherwise the emissions
factors may overestimate overall GHG emissions. The disadvantage of using population
factors is that it will only provide an estimate of potential emissions, not actual emissions. It
will also not provide any trends in changes in emissions over time, since the only variable is
equipment/ component count, which in most operations does not change significantly. Hence,
petroleum and natural gas operators who are voluntarily reducing emissions by conducting
periodic leak detection and repair will end up reporting more emissions than is actually
occurring in their operations. Emissions from all sources listed in this paragraph of this
section can be calculated using Equation 30.
Es i = Count * EF* GHGi * T Equation 30
where,
Esj = Annual total volumetric GHG emissions at standard conditions from
each equipment leak source category
Count = Total number of this type of emission source at the facility
EF = Population emission factor for specific sources listed in Appendix F.
GHGi = for onshore petroleum and natural gas production facilities and onshore
natural gas processing facilities, concentration of GHG i, CH4 or CO2, in
produced natural gas or feed natural gas; for other facilities GHG, equals
1
T = Total time the specific source associated with the equipment leak was
operational in the reporting period, in hours
Population emissions factors are available for specific sources for onshore petroleum and
natural gas production facilities, onshore natural gas processing facilities, onshore natural
gas transmission compression facilities, underground natural gas storage facilities,
liquefied natural gas storage facilities, liquefied natural gas import and export facilities,
and natural gas distribution facilities. These population emissions factors and a
discussion on their references are available in Appendix G.
e. Method 21
This is the authorized method for detecting volatile organic carbon (VOC) emissions under
Title 40 CFR. The method specifies the performance of a portable VOC emission detection
instrument with a probe not exceeding one fourth inch outside diameter, used to slowly
circumscribe the entire component interface where a leak could occur. The probe must be
maintained in close proximity to (but not touching) the interface; otherwise it could be
damaged by rotating shafts or plugged with ingested lubricants or greases. In most cases, it
can be no more than 1 centimeter away from the leak interface. Method 21 does not specify
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leak definitions; they are defined within specific subparts of the Title 40 CFR. Method 21
also allows certain alternative equipment leak detection methods, such as soap solutions
(where the leaking source is below the boiling point and above the freezing point of the soap
solution, does not have areas open to the atmosphere that the soap solution cannot bridge,
and does not have signs of liquid leakage). Method 21 does not specify any emissions mass
or volumetric quantification methods, but only specifies an emissions concentration
expressed in parts per million of combustible hydrocarbons in the air stream of the
instrument probe. This leak detection data has been used by state emission inventories with
"leaker" factors developed by the Synthetic Organic Chemicals Manufacturing Industry
(SOCMI)8 to estimate the quantity of VOC emissions. SOCMI factors were developed from
petroleum refinery and petrochemical plant data using Method 21.
Method 21 instrumentation technology has been used for over 30 years to detect leaks. The
approach uses gas concentration measurement of air and combustible gas drawn into the tip
of a probe manually circumscribed on or within one centimeter along the entire potential seal
surface or center of a vent to detect equipment leaks. This original practice is required for
certain regulated components that are reachable with the hand-held leak detection instrument
used while standing on the ground or fixed platform accessible by stairs (i.e. does not require
climbing ladders, standing on stools or use of bucket-lift trucks to access components). In a
study conducted by API at seven California refineries9 with over five years of measured data
(11.5 million data points), it was found that 0.13 percent of the components contributed over
90 percent of the controllable emissions (i.e. equipment leaks or vented emissions that can be
mitigated once detected). Given the fact that only a small number of sources contribute to
the majority of emissions, it is important for this final rule to detect and quantify leaking
sources beyond the scope of Method 21.
Performance standards for remote leak sensing devices, such as those based on infrared (IR)
light imaging, or laser beams in a narrow wavelength absorbed by hydrocarbon gases, were
promulgated in the general provisions of EPA 40 CFR Part 60. This alternate work practice
(AWP) permits leak detection using an instrument which can image both the equipment and
leaking gas for all 40 CFR 60 subparts that require monitoring under LDAR.
In a typical Method 21 program, the costs of conducting emissions detection remain the same
during each recurring study period. This is because the determination of whether a potential
source is emitting or not is made only after every regulated source is screened for emissions
as described above. The OVA/TVA requires the operator to physically access the emissions
source with the probe and thus is much more time intensive than using the optical gas
imaging instrument. Optical gas imaging instruments were found to be more cost effective
for leak detection for this reporting rule as these instruments are able to scan hundreds of
source components quickly, including components out of reach for an OVA/TVA.
8 EPA (1995). Protocol for Equipment Leak Emission Estimates. Research Triangle Park, NC. Publication No.
EPA-453/R-95-017. Online at: http://www.epa.gov/ttnchiel/efdocs/equiplks.pdf
9 Hal Taback Company Analysis of Refinery Screening Data, American Petroleum Institute, Publication
Number 310, November 1997.
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Although leak detection with Method 21 or the AWP in their current form in conjunction
with leaking component emission factors may not be the best suited for all mandatory
reporting, the principle could potentially be adopted for estimating emissions from minor
sources such as equipment leaks from components. Emissions can be detected from sources
(including those not required under Method 21, i.e. not within arm's reach) using AWP
procedures for the optical gas imaging instrument, and applying leaker emissions factors
available from studies conducted specifically with methane emissions in its scope. This will
be easier for industry to adapt to and also avoid the use of Synthetic Organic Chemical
Manufacturing Industry correlation equations or leak factors developed specifically for
different industry segments (i.e. petroleum refineries and chemical plants). This method will
also result in the estimation of real emissions, as opposed to potential emissions from
population emissions factor calculations.
f. Portable VOC Detection Instruments for Leak Measurement
As discussed above under Method 21, portable VOC detection instruments do not quantify
the volumetric or mass emissions. They quantify the concentration of combustible
hydrocarbon in the air stream induced through the maximum one fourth inch outside
diameter probe. Since these small size probes rarely ingest all of the emissions from a
component leak, they are used primarily for equipment leak detection. EPA provides
emissions quantification guidelines, derived from emissions detection data, for using portable
VOC detection devices. One choice of instrument emissions detection data is referred to as
"leak/no-leak," where equipment is determined to be leaking when the portable instrument
indicates the provided leak definition. Different leak definitions are specified within the
subparts of the Clean Air Act. Subpart KKK of 40 CFR Part 60 defines "leakers" for natural
gas processing facilities as components with a concentration of 10,000 ppm or more when
measured by a portable leak detection instrument. Components that are measured to be less
than 10,000 ppm are considered "not leaking." Hence, these quantification tables have a "no-
leak" emission factor for all components found to have emissions rates below the leak
definition, and "pegged" emission factors for all components above the leak definition.
Alternatively, the "stratified" method has emission factors based on ranges of actual leak
concentrations below, at and above the leak definition. Portable leak detection instruments
normally peg at 10,000 ppm, and so are unsuitable for use with the "stratified" quantification
factors.
g. Mass Balance for Quantification
There are mass balance methods that could be considered to calculate emissions for a
reporting program. This approach would take into account the volume of gas entering a
facility and the amount exiting the facility, with the difference assumed to be emitted to the
atmosphere. This is most often discussed for emissions estimation from the transportation
segment of the industry. For transportation, the mass balance is often not recommended
because of the uncertainties surrounding meter readings and the large volumes of throughput
relative to equipment leaks. The mass balance approach may, however, be feasible in cases
where the volume of emissions is significantly large and recognizable as meter readings. One
such source is an acid gas recovery unit where the volume of C02 extracted from natural gas
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is significant enough to be registered in a compositional difference of the natural gas and can
be determined using mass balance.
h. Gulf Offshore Activity Data System program (GOADS)
The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE)
conducts a comprehensive activity data collection effort under its Gulf Offshore Activity
Data System program (GOADS) in compliance with 30 CFR 250.302 through 304. This
requires all petroleum and natural gas production platforms located in the Federal Gulf of
Mexico (GoM) to report their activities to BOEMRE once in every three to four years. The
activity data reported includes counts of emissions sources, volumes of throughputs from
several pieces of equipment, fuel consumption by combustion devices, and parametric data
related to certain emissions sources such as glycol dehydrators. This activity data is then
converted into emissions estimates by BOEMRE and reported subsequently by BOEMRE.
The BOEMRE summary report provides estimates of GHG emissions in the GoM as well as
a detailed database of emissions from each source on platform in the GoM. The EPA could
potentially use this data reported by the GOADS program. However, since the data has
historically been collected once every three to four years, EPA will not receive new
emissions information for every reporting period. This means that between BOEMRE
reporting periods if a new platform is commissioned, an old platform is de-commissioned,
new equipment is installed on existing platforms, or operating levels of platforms change
then this information will not get recorded and reported for periods when BOEMRE GOADS
is not being conducted. This issue however, can be resolved by requiring new platforms to
use the most recent GOADS methods to estimate emissions and other reporters to adjust their
emissions annually based on the time each platform was operating in comparison to the
GOADS reporting year. Finally, the BOEMRE GOADS program does not collect
information from platforms in the GoM under State jurisdiction, as well as platforms in the
Pacific and Alaskan coasts. These platforms not under GOADS purview will not have
existing data to report if GOADS reporting were to be adopted by EPA. Nevertheless, a
reporting rule can potentially require non-GOADS platforms to adopt the GOADS
methodology to calculate emissions. If BOEMRE discontinues or delays their GOADS, then
platform operators under a reporting rule using GOADS may refer to the most recently
published version of the GOADS program instructions to continue reporting.
i. Additional Questions Regarding Potential Monitoring Methods
There are several additional issues regarding the potential monitoring methods relevant to
estimating equipment leak and vented emissions from the petroleum and natural gas industry.
i. Source Level Equipment Leak Detection Threshold
This document does not indicate a particular equipment leak definition or detection threshold
requiring emissions measurement. This is because different equipment leak detection
instruments have different levels and types of detection capabilities, i.e. some instruments
provide a visual image while others provide a digital value on a scale (not necessarily
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directly related to mass emissions). Hence the magnitude of actual emissions can only be
determined after measurement. This, however, may not serve the purpose of a reporting rule,
which is to limit the burden by focusing only on significant sources of emissions. A facility
can have hundreds of small emissions (as low as 3 grams per hour) and it might not be
practical to measure all of them for reporting.
There are, however, two possible approaches to overcome this issue, as follows; provide an
instrument performance standard such that any source determined to be emitting per the
instrument is considered an emissions source, or provide a threshold value for the emitter
such that any source below the threshold magnitude is not considered an emitter.
Instrument Performance Standards
Performance standards can be provided for equipment leak detection instruments and usage
such that all instruments follow a minimum common detection threshold. Alternatively, the
AWP to Detect Leaks from Equipment standards for optical gas imaging instruments recently
adopted by EPA can potentially be proposed. In such a case, all detected emissions from
components subject to the final rule may require measurement and reporting. This avoids the
necessity of specifying performance standards.
The EPA Alternative Work Practice (AWP) promulgated the use of optical gas imaging
instruments that can detect in some cases emissions as small as 1 gram per hour. The AWP
requires technology effectiveness of emissions statistically equivalent to 60 grams/hour on a
bi-monthly screening frequency, i.e. the technology should be able to routinely detect all
emissions equal to or greater than 60 grams/hour. EPA determined by Monte Carlo
simulation that 60 grams/hour leak rate threshold and bi-monthly monitoring are equivalent
to existing work practices (Method 21). To implement the technology effectiveness, the
AWP requires that the detection instrument meet a minimum detection sensitivity mass flow
rate. For the purposes of the proposed supplemental rule, such a performance standard could
be adapted for the detection of natural gas emissions with methane as the predominant
component (it should be noted that Method 21 is specifically meant for VOCs and HAPs and
not for methane).
Equipment Leak Threshold
One alternative to determining an emission source is to provide a mass emissions threshold
for the emitter. In such a case, any source that emits above the threshold value would be
considered an emitter. For portable VOC monitoring instruments that measure emission
concentrations a concentration threshold equivalent to a mass threshold can be provided.
However, the concentration measurement is converted to an equivalent mass value using
SOCMI correlation equations, which were developed from petroleum refinery and
petrochemical plant data. In the case of an optical imaging instrument, which does not
provide the magnitude of emissions, either concentration or mass emissions, quantification
would be required using a separate measurement instrument to determine whether a source is
an emitter or not. This could be very cost prohibitive for the purposes of this rule.
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ii. Duration of Equipment Leaks
Equipment leaks by nature occur randomly within the facility. Therefore, there is no way of
knowing when a particular source started emitting. If the potential monitoring method
requires a one time equipment leak detection and measurement, then assumptions will have
to be made regarding the duration of the emissions. There are several potential options for
calculating the duration of emissions. If a component leak is detected, total emissions from
each source could be quantified under one of the following three scenarios: 1) if a facility
conducts one comprehensive leak survey each reporting period, applicable component leaker
emissions factors could be applied to all specific component emissions sources and emissions
quantified based on emissions occurring for an entire reporting period; 2) if a facility
conducts two comprehensive leak surveys during a single reporting period, applicable
component leaker emissions factors could be applied to all component emissions sources. If
a specific emission source is found not leaking in the first survey but leaking in the second
survey, emissions could be quantified from the date of the first leak survey conducted in the
same reporting period forward through the remainder of the reporting period. If a specific
emissions source is found leaking in the first survey but is repaired and found not leaking in
the second survey, emissions could be quantified from the first day of the reporting period to
the date of the second survey. If a component is found leaking in both surveys, emissions
could be quantified based on an emission occurring for an entire reporting period; 3) if a
facility conducts multiple comprehensive leak surveys during the same reporting period,
applicable component leaker emissions factors could be applied to component emissions
sources. Each specific source found leaking in one or more surveys is quantified for the
period from a prior finding of no leak (or beginning of the reporting period) to a subsequent
finding of no leak (or end of the reporting period). If a component is found leaking in all
surveys, emissions could be quantified based on an emissions occurring for an entire
reporting period.
iii. Equipment Leak and Vented Emissions at Different Operational Modes
If a reporting program relies on a one time or periodic measurement, the measured emissions
may not account for the different modes in which a particular technology operates throughout
the reporting period. This may be particularly true for measurements taken at compressors.
Compressor leaks are a function of the mode in which the compressor is operating: i.e.
offline pressurized, or offline de-pressurized. Typically, a compressor station consists of
several compressors with one (or more) of them on standby based on system redundancy
requirements and peak delivery capacity. When a compressor is taken offline it may be kept
pressurized with natural gas or de-pressurized. When the compressor is offline and kept
pressurized, equipment leaks and vented emissions result from closed blowdown valves and
reciprocating compressor rod packing leaks, respectively. When the compressor is offline
and depressurized, emissions result from leaking isolation valves. When operating,
compressor vented emissions result from compressor seals or rod packing and other
components in the compressor system. In each of the compressor modes, the resultant
equipment leak and vented emissions are significantly different. One potential approach to
account for these varying levels of equipment leak and vented emissions is to have operators
measure all compressors in each operating mode once a reporting period. Operators would
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also need to report the time for which the compressor is in the different modes. The
disadvantages to this approach is that it will increase the reporting burden because
measurements will have to be taken at each mode of compressor operation in each reporting
period and the time that the equipment is in various operational modes would also have to be
tracked. In addition, it is not feasible to require operators to take compressors off-line every
year to conduct measurements in offline pressurized and depressurized modes. One
alternative approach is to report compressor emissions in the mode the compressors are
found, also known as reporting compressor emissions "as-is". The reporters could then
determine emission factors for each mode and apply them to the period of time each
compressor was not in the mode it was measured in for the reporting period. Since most
compressors would be found in the, pressurized, operating mode, reporters could be required
to measure each compressor in an offline mode less frequently (e.g. every three reporting
periods) to ensure sufficient data points are collected in the less common offline modes.
A similar issue exists with tanks where the operating conditions change more often than for
compressors. The amount of throughput through tanks varies continuously as new
hydrocarbon liquids are introduced and stored liquids are withdrawn for transportation.
Unlike other equipment, the operational level of tanks cannot be categorized into a fixed and
limited number of modes. This makes it all the more challenging to characterize emissions
from storage tanks. One option is to require operators to use best judgment and characterize a
few different modes for the storage tanks and make adjustments to the monitored emissions
accordingly.
iv. Natural Gas Composition
When measuring equipment leaks and vented emissions using the various measurement
instruments (high volume sampler, calibrated bags, and meters) or using engineering
estimation for vented emissions, only flow rate is measured or calculated and the individual
CH4 and C02 emissions are estimated from the natural gas mass emissions using natural gas
composition appropriate for each facility. For this purpose, the monitoring methodologies
discussed above would require that facilities use existing gas composition estimates to
determine CH4 and CO2 components of the natural gas emissions (acid gas recovery units,
flare stacks, and storage tank vented emissions are an exception to this general rule). These
gas composition estimates are assumed to be available at facilities. But this may or may not
be a practical assumption for reporting. In the absence of gas composition, periodic
measurement of the required gas composition for speciation of the natural gas mass
emissions into CH4 and C02 mass emissions could be a potential option.
In addition, GHG components of natural gas may change significantly in the facilities during
the reporting period and different sources in the same facility may be emitting different
compositions of natural gas. This is most prevalent in onshore production, offshore
production and natural gas processing facilities. One potential option is to apply an average
composition across all emissions sources for the reporting facility. Another option is to apply
specific composition estimates across similar streams in the same facility. For example, in
processing, the natural gas composition is similar for all streams upstream of the de-
methanizer. The same is true of all equipment downstream of the de-methanizer overhead.
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For onshore production and offshore production monthly or quarterly samples can be taken
to account for the variation in natural gas being produced from different combinations of
production wells throughout the reporting period.
v. Physical Access for Leak Measurement
All emissions measurement techniques require physical access to the leaking source. The
introduction of remote leak detection technologies based on infrared (IR) light absorption by
hydrocarbon gas clouds from atmospheric leaks makes leak detection quicker and possible
for sources outside of arms reach from the ground or fixed platforms. Leaks from flanges,
valve stems, equipment covers, etc. are generally smaller than emissions from vents.
Component leaks are expensive to measure where they are not accessible within arms reach
from the ground or a fixed platform. For these inaccessible sources, the use of emission
factors for emissions quantification may be appropriate. Vent stacks are often located out of
access by operators for safety purposes, but may represent large emission sources. Where
emissions are detected by optical gas imaging instruments, emissions measurement may be
cost-effective using the following source access techniques:
¦ Short length ladders positioned on the ground or a fixed platform where OSHA
regulations do not require personnel enclosure and the measurement technique can be
performed with one hand;
¦ Bucket trucks can safely position an operator within a full surround basket allowing
both hands to be used above the range of ladders or for measurement techniques
requiring both hands;
¦ Relatively flat, sturdy roofs of equipment buildings and some tanks allow safe access
to roof vents that are not normally accessible from fixed platforms or bucket trucks;
¦ Scaffolding is sometimes installed for operational or maintenance purposes that allow
access to emission sources not normally accessible from the ground, fixed platforms
and out of reach of bucket trucks.
7. Procedures for Estimating Missing Data
It is possible that some companies would be missing data necessary to quantify annual
emissions. In the event that data are missing, potential procedures to fill the data gap are
outlined below and are organized by data type.
In general, although there is always the possibility of using a previous periods' data point to
replace missing data in the current reporting period, this is not ideal since varying operating
conditions can dramatically impact emissions estimates. Where using previous reporting
periods' data are not desirable, then a reporting rule might require 100% data availability. In
other words, there would be no missing data procedures provided. If any data were identified
as missing, then there would be an opportunity to recollect the emissions data over the course
of the current reporting period.
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a. Emissions Measurement Data
Measured data can be collected by trained engineers using a high volume sampler, meter, or
calibrated bag. Over the course of the data collection effort, some of the measured emissions
rates could get lost temporarily or permanently due to human error, or storage errors such as
lost hard-drives and records. If measured data is missing then the field measurement process
may have to be repeated within the reporting period. If this proves to be impossible and the
company clearly certifies that they lost the data and can justify not repeating the survey
within the given reporting period, then the previous reporting period's data could be used to
estimate equipment leaks from the current reporting period.
b. Engineering Estimation Data
Engineering estimations rely on the collection of input data to the simulation software or
calculations. A potential procedure for missing input data is outlined below for each type of
input parameter.
• Operations logs. If operating logs are lost or damaged for a current reporting period,
previous reporting period's data could be used to estimate emissions. Again, using
previous reporting periods' data are not as desirable as there could be significant
differences from period to period based on operating conditions.
• Process conditions data. Estimating vented emissions from acid gas removal vent
stacks, blowdown vent stacks, dehydrator vents, natural gas driven pneumatic valve
bleed devices, natural gas driven pneumatic pumps, and storage tanks requires data on
the process conditions (e.g., process temperature, pressure, throughputs, and vessel
volumes). If, for any reason, these data are incomplete or not available for the current
reporting period, field operators or engineers could recollect data wherever possible.
If this data cannot be collected, then relevant parameters for estimation of emissions
can be used from previous reporting period. However, where possible current
reporting period parameters should be used for emissions estimation due to the
reasons listed above.
c. Emissions Estimation Data for Storage Tanks and Flares
Emissions from storage tanks and flares might require a combination of both direct
measurement and engineering estimation to quantify emissions. In such cases the storage
tank emissions calculation requires the measurement of "emissions per throughput" data. If
this data is missing then the previous reporting periods' estimate of "emissions per
throughput" measured data could be used with current period throughput of the storage tank
to calculate emissions.
Calculating emissions from flares requires the volume of flare gas measured using a meter. If
these data are missing then the flare gas in the current reporting period could be estimated by
scaling the flare gas volume from previous reporting period by adjusting it for current period
throughput of the facility.
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d. Emissions Estimation Data Using Emissions Factors
If population emissions factors are used then the only data required is activity data. In such a
case missing data should be easily replaceable by undertaking a counting exercise for
locations from which the data is missing. Alternatively, previous reporting period activity
data can be used to fill in missing data. However, if facility and/ or equipment modifications
have resulted in increase or decrease in activity data count then this may not be a feasible
approach.
If leaker emissions factors are used then activity data will have to be collected using some
form of equipment leak detection. In such case, missing data may not be easily replaceable.
Previous period reported activity data may be used but it may not be representative of current
period emissions. A detection survey to replace missing data may be warranted.
8. QA/QC Requirements
a. Equipment Maintenance
Equipment used for monitoring, both emissions detection and measurement, should be
calibrated on a scheduled basis in accordance with equipment manufacturer specifications
and standards. Generally, such calibration is required prior to each monitoring cycle for each
facility. A written record of procedures needed to maintain the monitoring equipment in
proper operating condition and a schedule for those procedures could be part of the QA/QC
plan for the facility.
An equipment maintenance plan could be developed as part of the QA/QC plan. Elements of
a maintenance plan for equipment could include the following:
• Conduct regular maintenance of monitoring equipment.
o Keep a written record of procedures needed to maintain the monitoring system
in proper operating condition and a schedule for those procedures;
o Keep a record of all testing, maintenance, or repair activities performed on
any monitoring instrument in a location and format suitable for inspection. A
maintenance log may be used for this purpose. The following records should
be maintained: date, time, and description of any testing, adjustment, repair,
replacement, or preventive maintenance action performed on any monitoring
instrument and records of any corrective actions associated with a monitor's
outage period.
b. Data Management
Data management procedures could be included in the QA/QC Plan. Elements of the data
management procedures plan are as follows:
• Check for temporal consistency in production data and emission estimate. If outliers
exist, can they be explained by changes in the facility's operations, etc.?
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o A monitoring error is probable if differences between annual data cannot be
explained by:
¦ Changes in activity levels,
¦ Changes concerning monitoring methodology,
¦ Changes concerning change in equipment,
¦ Changes concerning the emitting process (e.g. energy efficiency
improvements).10
• Determine the "reasonableness" of the emission estimate by comparing it to previous
year's estimates and relative to national emission estimate for the industry:
o Comparison of emissions by specific sources with correction for throughput,
if required,
o Comparison of emissions at facility level with correction for throughput, if
required,
o Comparison of emissions at source level or facility level to national or
international reference emissions from comparable source or facility, adjusted
for size and throughput,
o Comparison of measured and calculated emissions.10
• Maintain data documentation, including comprehensive documentation of data
received through personal communication:
o Check that changes in data or methodology are documented
c. Calculation checks
Calculation checks could be performed for all reported calculations. Elements of calculation
checks could include:
• Perform calculation checks by reproducing a representative sample of emissions
calculations or building in automated checks such as computational checks for
calculations:
o Check whether emission units, parameters, and conversion factors are
appropriately labeled,
o Check if units are properly labeled and correctly carried through from
beginning to end of calculations,
o Check that conversion factors are correct,
o Check the data processing steps (e.g., equations) in the spreadsheets,
o Check that spreadsheet input data and calculated data are clearly differentiated
o Check a representative sample of calculations, by hand or electronically,
o Check some calculations with abbreviated calculations (i.e., back of the
envelope checks),
10 Official Journal of the European Union, August 31, 2007. Commission Decision of 18 July 2007,
"Establishing guidelines for the monitoring and reporting of GHG emissions pursuant to Directive 2003/87/EC
of the European Parliament and of the Council. Available at http://eur-
lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2007:229:0001:0085:EN:PDF.
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o Check the aggregation of data across source categories, business units, etc.,
o When methods or data have changed, check consistency of time series inputs
and calculations.11
9. Reporting Procedure
(a) The facilities that cross the potential threshold for reporting could report the following
information to EPA:
(1) Emissions monitored at an aggregate source level for each facility, separately identifying
those emissions that are from standby sources. In several onshore natural gas processing
plants CO2 is being capture for Enhanced Oil Recovery operations. Therefore, these CO2
emissions may have to be separately accounted for in the reporting.
(2) Activity data, such as the number of sources monitored, for each aggregated source type
level for which emissions will be reported.
(3) The parameters required for calculating emissions when using engineering estimation
methods.
In addition, the following reporting requirements could be considered for a reporting rule;
(b) Equipment leaks by nature occur randomly within the facility, therefore, where emissions
are reported on an annual basis, it may not be possible to determine when the equipment
leaks began. As discussed in more detail in Section (I)(ii) of the TSD, under these
circumstances, annual emissions could be determined assuming that the equipment leaks
were continuous from the beginning of the reporting period or from the last recorded not
leaking in the current reporting period and until the equipment leak is repaired or the end of
the reporting period.
(c) Due to the point-in-time nature of direct measurements, reports of annual emissions levels
should take into account equipment operating hours according to standard operating
conditions and any significant operational interruptions and shutdowns, to convert direct
measurement to an annual figure.
10. Verification of Reported Emissions
As part of the data verification requirements, the owner or operator could submit a detailed
explanation of how company records of measurements are used to quantify equipment leaks
and vented emissions measurement within 7 days of receipt of a written request from EPA or
from the applicable State or local air pollution control agency (the use of electronic mail can
be made acceptable).
11 U.S. EPA 2007. Climate Leaders, Inventory Guidance, Design Principles Guidance, Chapter 7 "Managing
Inventory Quality". Available at
http://www.epa.gov/climateleaders/documents/resources/design_princ_ch7.pdf.
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Appendix A: Segregation of Emissions Sources using the Decision Process
The tables provided in this appendix represent the outcome of the decision process used to
identify a starting list of potential sources that were evaluated for inclusion in the final rule.
The decision process was applied to each emission source in the natural gas segment of the
U.S. GHG Inventory. The petroleum onshore production segment has emission sources that
either are equivalent to their counter-parts in the natural gas onshore production segment or
fall in the exclusion category. Petroleum transportation was not analyzed further due to the
level of emissions and refineries are treated separately in Subpart Y.
Sources Contributing to 80% of Equipment Leaks and Vented Emissions from Each Industry
Segment
Source
Offshore
Production
Onshore
Prod uction
Processing
Transmission
Storage
LNG Storage
LNG Import and
Export
Distribution
Separators
4%
Meters/Piping
4%
Small Gathering Reciprocating Comp.
2%
Pipeline Leaks
7%
CBM Powder River
2%
Pneumatic Device Vents
43%
0.26%
12%
13%
Gas Pneumatic Pumps
9%
0.49%
Dehydrator Vents
2%
3%
3%
Well Clean Ups (LP Gas Wells)/ Blowdowns
7%
Plant/Station/ Platform Fugitives
4%
5%
16%
14%
3%
Reciprocating Compressors
48%
40%
45%
54%
14%
Centrifugal Compressors
22%
16%
8%
6%
19%
4%
Acid Gas Removal Vents
2%
Vessel BlowdownsA/enting
6%
Routine Maintenance/Upsets - Pipeline venting
10%
Station venting
8%
2%
M&R (Trans. Co. Interconnect)
4%
Pipeline Leaks Mains
36%
Services
16%
Meter/Regulator (City Gates)
37%
Residential Customer Meters
Flare stacks
1%
Non-pneumatic pumps
0.03%
Open ended lines
0.005%
Pump seals
0.41%
Storage tanks
50%
Wellhead fugitive emissions
4%
Well completions
0.0004%
Well workovers
0.04%
NOTE: Pink cells represent sources that were included over riding the decision tree process. Blue cells represent
sources that are not present in the respective segments. Green cells represent sources that are not explicitly
identified in the U.S. GHG Inventory; however, these sources may potentially be found in the respective segments.
Blank cells are sources in the U.S. GHG Inventory.
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Inventory of Methane Emissions from Natural Gas Systems
Total Emissions
% of total
PRODUCTION OFFSHORE
Nationally
(MMcf/year)
Tonnes
C02 e/ Year
% of Sector
Emissions
Inventory
Emissions
Activity
Factors
Leak
Detection
Direct
Measurement
Engineering
Estimate
Accesible
Source
Amine gas sweetening unit
0.2
80
0.01%
0.0001 %
NE
c
c
a
n
Boiler/heater/burner
0.8
332
0.05%
0.0002%
c
d
a
n
Diesel or gasoline engine
0.01
6
0.001%
0.000004%
c
d
a
n
Drilling rig
3
1,134
0.17%
0.001 %
c
d
a
n
Flare
24
9,583
1.47%
0.01 %
c
c
b
n
Centrifugal Seals
358
144,547
22%
0.10%
a
a
a
b
Connectors
0.8
309
0.05%
0.0002%
b
b
b
b
Flanges
2.38
960
0.15%
0.001 %
b
b
b
b
OEL
0.1
32
0.005%
0.00002%
b
b
b
b
Other
44
17,576
2.70%
0.01 %
b
b
b
b
Pump Fugitive
0.5
191
0.03%
0.0001%
b
b
a
b
Valves
19
7,758
1%
0.01 %
b
b
b
b
Glycol dehydrator
25
9,914
2%
0.01%
c
c
b
n
Loading operation
0.1
51
0.01%
0.00004%
c
d
a
n
Separator
796
321,566
49%
0.23%
c
c
b
b
Mud degassing
8
3,071
0.47%
0.002%
c
d
a
n
Natural gas engines
191
77,000
12%
0.05%
Natural gas turbines
3
1,399
0.22%
0.001 %
Pneumatic pumps
7
2,682
0.41%
0.002%
c
b
a
b
Pressure/level controllers
2
636
0.10%
0.0005%
c
b
a
b
Storage tanks
7
2,933
0.45%
0.002%
c
c
a
n
VEN exhaust gas
121
48,814
8%
0.03%
c
c
b
n
NOTES: Leak Detection: a - Yes and cost effective; b - Yes but cost burden c - No. Cost effectiveness based on expert judgment.
Direct Measurement: a - Accurate and cost effective; b - Accurate but cost burden; c - Questionable; d - No direct measurement.
Engineering Estimate: a - Exists; b - does not exist.
Accessible Source: y - Yes; n - No; b - Both.
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Total Emissions
% of total
PRODUCTION ONSHORE
Nationally
Tonnes
% of Sector
Inventory
Activity
Leak
Direct
Engineering
Accesible
(MMcf/year)
C02e/ Year
Emissions
Emissions
Factors
Detection
Measurement
Estimate
Source
\Normal Fugitives
Gas Wells
Non-associated Gas Wells (less Unconventional)
.' ' ¦: 12
1,083,539
2%
0.77%
376784
b
b
b
b
Unconventional Gas Wells
'19
27,690
0.06%
0.02%
35440
b
b
b
Field Separation Equipment
Heaters
1,463
591,023
1%
0.42%
89720
a
b
b
b
Separators
4,718
1,906,206
4%
1%
247919
b
b
b
b
Dehydrators
1,297
524,154
1%
0.37%
37925
a
b
b
b
Meters/Piping
4,556
1,840,683
4%
1%
315487
b
b
b
b
Gathering Compressors
Small Reciprocating Comp.
2,926
1,182,06^
1%
28490
a
a
b
b
Large Reciprocating Comp.
664
268,133
0.54%
0.19%
112
a
a
b
b
Large Reciprocating Stations
45
18,178
0.04%
0.01%
14
a
a
b
b
Pipeline Leaks
8,087
3,267,306
7%
2%
392624
b
b
b
n
\ Vented and Combusted
188
597
c
n
38,946
35600
c
-
Powder River
2.924
1.181,246
2%
1%
396920
c
c
a
n
Black Warrior
543
219,249
0.44%
0.16%
c
c
a
n
Normal Operations
Pneumatic Device Vents
52,421
21,178,268
43%
15%
c
b
a
b
Chemical Injection Pumps
2,814
1,136,867
2%
0.81%
c
b
a
b
Kimray Pumps
11,572
4,674,913
9%
3%
c
b
a
n
Dehydrator Vents
3,608
1,457,684
3%
1%
c
c
a
n
Condensate Tank Vents
Condensate Tanks without Control Devices
1,225
494,787
1%
c
b
Condensate Tanks with Control Devices
245
98,957
0.20%
0.07%
d
b
11.680
4.718.728
3%
Well Workovers
47
18.930
0.04%
0.01%
d
b
-
3.639.271
3%
d
a
n
Vessel BD
31
12,563
0.03%
0.01%
c
d
a
n
Pipeline BD
129
52,040
0.10%
0.04%
c
d
a
b
Compressor BD
113
45,648
0.09%
0.03%
c
d
a
n
Compressor Starts
253
102,121
0.20%
0.07%
c
d
a
n
Pressure Relief Valves
29
11,566
0.02%
0.01%
c
d
b
n
Mishaps
70
28,168
0.06%
0.02%
c
d
b
n
Notes: Leak Detection: a - Yes and cost effective; b - Yes but cost burden; c - No. Cost effectiveness based on expert judgment.
Direct Measurement: a - Accurate and cost effective; b - Accurate but cost burden; c - Questionable; d - No direct measurement.
Engineering Estimate: a - Exists; b - does not exist.
Accessible Source: y - Yes; n - No; b - Both.
Background Technical Support Document - Petroleum and Natural Gas Industry
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Total Emissions
% of total
GAS PROCESSING PLANTS
Nationally
(MMcf/year)
Tonnes
C02el Year
% of Sector
Emissions
Inventory
Emissions
Activity
Factors
Leak
Detection
Direct
Measurement
Engineering
Estimate
Accesible
Source
\Normal Fugitives
Plants
1,634
660,226
5%
0.47%
a
a
b
b
Recip. Compressors
17,351
7,009,755
48%
5%
a
a
b
b
Centrifugal Compressors
5,837
2,358,256
16%
2%
a
a
b
b
Vented and Combusted
Normal Operations
Compressor Exhaust
Gas Engines
6,913
2,792,815
19%
2%
Gas Turbines
195
78,635
1%
0.06%
AGR Vents
643
259,592
2%
0.18%
c
c
a
n
Kimray Pumps
177
71,374
0.49%
0.05%
c
b
a
b
Dehydrator Vents
1,088
439,721
3%
0.31%
c
c
a
n
Pneumatic Devices
93
37,687
0.3%
0.03%
c
b
a
b
Routine Maintenance
|Blowdowns/Venting
2,299
928,900
6%
1%
c
d
a
n
Notes: Leak Detection: a - Yes and cost effective; b - Yes but cost burden; c - No. Cost effectiveness based on expert judgment.
Direct Measurement: a - Accurate and cost effective; b - Accurate but cost burden; c - Questionable; d - No direct measurement.
Engineering Estimate: a - Exists; b - does not exist.
Accessible Source: y - Yes; n - No; b - Both.
Background Technical Support Document - Petroleum and Natural Gas Industry 79
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TRANSMISSION
Total Emissions
Nationally
(MMcf/year)
Tonnes
C02el Year
% of Sector
Emissions
% of total
Inventory
Emissions
Activity
Factors
Leak
Detection
Direct
Measurement
Engineering
Estimate
Accesible
Source
Fugitives
Pipeline Leaks
166
67,238
0.17%
0.05%
a
c
a
n
Compressor Stations (Transmission)
Station
5,619
2,270,177
6%
2%
a
a
b
b
Recip Compressor
38,918
15,722,907
40%
11%
a
a
b
b
Centrifugal Compressor
7,769
3,138,795
8%
2%
a
a
b
b
M&R (Trans. Co. Interconnect)
3,798
1,534,238
4%
1%
a
a
b
b
M&R (Farm Taps + Direct Sales)
853
344,646
1%
0.25%
b
b
b
b
Vented and Combusted
Normal Operation
Dehydrator vents (Transmission)
105
42,329
0.11%
0.03%
c
c
a
n
Compressor Exhaust
Engines (Transmission)
10,820
4,371,314
11%
3%
Turbines (Transmission)
61
24,772
0.06%
0.02%
Generators (Engines)
529
213,911
0.55%
0.15%
Generators (Turbines)
0
60
0.0002%
0.00004%
Pneumatic Devices Trans + Stor
Pneumatic Devices Trans
11,393
4,602,742
12%
3%
c
b
a
b
Routine Maintenance/Upsets
Pipeline venting
9 287
3,752,013
10%
3%
c
d
a
b
Station venting Trans + Storage
Station Venting Transmission
7,645
3,088,575
8%
2%
c
d
a
n
Notes: Leak Detection: a - Yes and cost effective; b - Yes but cost burden; c - No. Cost effectiveness based on expert judgment.
Direct Measurement: a - Accurate and cost effective; b - Accurate but cost burden; c - Questionable; d - No direct measurement.
Engineering Estimate: a - Exists; b - does not exist.
Accessible Source: y - Yes; n - No; b - Both.
Background Technical Support Document - Petroleum and Natural Gas Industry
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STORAGE
Total Emissions
Nationally
(MMcf/year)
Tonnes
C02el Year
% of Sector
Emissions
% of total
Inventory
Emissions
Activity
Factors
Leak
Detection
Direct
Measurement
Engineering
Estimate
Accesible
Source
| Fugitives
Compressor Stations (Storage)
Station
2,801
1,131,492
16%
1%
a
a
b
b
Recip Compressor
8,093
3,269,454
45%
2%
a
a
b
n
Centrifugal Compressor
1,149
464,354
6%
0.33%
a
a
b
n
Wells (Storage)
695
280,891
4%
0.20%
a
a
b
y
Vented and Combusted
Normal Operation
Dehydrator vents (Storage)
217
87,514
1%
0.06%
c
c
a
n
Compressor Exhaust
Engines (Storage)
1,092
441,108
6%
0.31%
Turbines (Storage)
9
3,680
0.05%
0.003%
Pneumatic Devices Trans + Stor
Pneumatic Devices Storage
2,318
936,324
13%
1%
c
b
a
b
Station venting Trans + Storage
Station Venting Storage
1,555
628,298
9%
0.45%
c
d
a
n
Notes: Leak Detection: a - Yes and cost effective; b - Yes but cost burden; c - No. Cost effectiveness based on expert judgment.
Direct Measurement: a - Accurate and cost effective; b - Accurate but cost burden; c - Questionable; d - No direct measurement.
Engineering Estimate: a - Exists; b - does not exist.
Accessible Source: y - Yes; n - No; b - Both.
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81
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Total Emissions
% of total
LNG STORAGE
Nationally
(MMcf/year)
Tonnes
C02el Year
% of Sector
Emissions
Inventory
Emissions
Activity
Factors
Leak
Detection
Direct
Measurement
Engineering
Estimate
Accesible
Source
LNG Storage
LNG Stations
552
222,824
14%
0.16%
b
b
b
b
LNG Reciprocating Compressors
2,084
842,118
54%
1%
b
b
b
b
LNG Centrifugal Compressors
715
288,756
19%
0.21%
b
b
b
b
LNG Compressor Exhaust
LNG Engines
172
69,632
5%
0.05%
LNG Turbines
1
261
0.02%
0.0002%
LNG Station venting
306
123,730
8%
0.09%
c
d
a
n
LNG IMPORT AND EXPORT
TERMINALS
Total Emissions
Nationally
(MMcf/year)
Tonnes
C02el Year
% of Sector
Emissions
% of total
Inventory
Emissions
Activity
Factors
Leak
Detection
Direct
Measurement
Engineering
Estimate
Accesible
Source
LNG Import Terminals
LNG Stations
22
8,880
3%
0.01%
b
b
b
b
LNG Reciprocating Compressors
105
42,347
14%
0.03%
b
b
a
b
LNG Centrifugal Compressors
27
10,820
4%
0.01 %
b
b
a
b
LNG Compressor Exhaust
LNG Engines
586
236,647
78%
0.17%
LNG Turbines
3
1,370
0.45%
0.001%
LNG Station venting
12
4,931
2%
0.004%
c
d
a
n
Notes: Leak Detection: a - Yes and cost effective; b - Yes but cost burden; c - No.
Direct Measurement: a - Accurate and cost effective; b - Accurate but cost burden; c - Questionable; d - No direct measurement.
Engineering Estimate: a - Exists; b - does not exist.
Accessible Source: y - Yes; n - No; b - Both.
Export Terminals are not currently included in the U.S. GHG Inventory, therefore they were not included in this analysis. There is currently only one export
terminal, located in Alaska.
Background Technical Support Document - Petroleum and Natural Gas Industry
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DISTRIBUTION
Total Emissions
Nationally
(MMcf/year)
Tonnes
C02 el
Year
% of Sector
Emissions
% of total
Inventory
Emissions
Activity
Factors
Leak
Detection
Direct
Measurement
Engineering
Estimate
Accesible
Source
\Normal Fugitives
Pipeline Leaks
Mains - Cast Iron
9,222
3,725,675
14%
3%
a
b
b
n
Mains - Unprotected steel
6,515
2,632,209
10%
2%
a
b
b
n
Mains - Protected steel
1,422
574,529
2%
0.41 %
a
b
b
n
Mains - Plastic
6,871
2,775,759
10%
2%
a
b
b
n
Total Pipeline Miles
36%
7%
Services - Unprotected steel
7,322
2,957,970
11%
2%
a
b
b
n
Services Protected steel
2,863
1,156,473
4%
1%
a
b
b
n
Services - Plastic
315
127,210
0.47%
0.09%
a
b
b
n
Services - Copper
47
19,076
0.07%
0.01%
a
b
a
n
Total Services
16%
3%
Meter/Regulator (City Gates)
37%
7%
M&R >300
5,037
2,034,986
7%
1%
3,198
a
a
b
b
M&R 100-300
10,322
4,170,101
15%
3%
12,325
b
b
b
b
M&R <100
249
100,480
0.37%
0.07%
6,587
a
c
b
b
Reg >300
5,237
2,115,726
8%
2%
3,693
a
a
b
b
R-Vault >300
25
9,976
0.04%
0.01%
2,168
a
a
b
b
Reg 100-300
4,025
1,625,929
6%
1%
11,344
b
b
b
b
R-Vault 100-300
8
3,247
0.01%
0.002%
5,097
a
c
b
b
Reg 40-100
306
123,586
0.45%
0.09%
33,578
b
b
b
b
R-Vault 40-100
23
9,115
0.03%
0.01%
29,776
b
b
b
b
Reg <40
Customer Meters
17
6,690
0.02%
0.005%
14,213
b
b
b
b
Residential
5,304
2.142.615
8%
2%
37017342
b
b
a
y
Commercial/Industry
203
81,880
0.30%
0.06%
4231191
b
b
a
y
Vented
Rountine Maintenance
Pressure Relief Valve Releases
63
25,346
0.09%
0.02%
c
d
b
n
Pipeline Blowdown
122
49,422
0.18%
0.04%
c
d
a
n
Upsets
Mishaps (Dig-ins)
1,907
770,405
3%
1%
c
d
b
n
NOTES: Leak Detection: a - Yes and cost effective; b - Yes but cost burden; c - No. Cost effectiveness based on expert judgment.
Direct Measurement: a - Accurate and cost effective; b - Accurate but cost burden; c - Questionable; d - No direct measurement.
Engineering Estimate: a - Exists; b - does not exist.
Accessible Source: y - Yes; n - No; b - Both.
Background Technical Support Document - Petroleum and Natural Gas Industry
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Appendix B: Development of revised estimates for four U.G. GHG
Inventory emissions sources
Well Completion and Workover Venting
This discussion describes the methods used to estimate total U.S. methane emissions from
well completion and workover venting. For the purposes of this estimate, it is assumed that
all unconventional wells are completed with hydraulic fracturing of tight sand, shale or coal
bed methane formations (i.e. completions involving high rate, extended back-flow to expel
fracture fluids and sand proppant, which also leads to greater gas venting or flaring emissions
than conventional well completions). It is understood that not all unconventional wells
involve hydraulic fracturing, but some conventional wells are hydraulically fractured, which
is assumed to balance the over-estimate.
~Estimate the Number of Gas Wells Completed
The data in Exhibit B-l was extracted from EPA (2008)12. The unconventional well column
only includes CBM wells and shale gas wells, but does not include tight sands formations
because that data is not readily available either publically or in the U.S. Inventory. Thus, this
analysis underestimates the activity associated with unconventional well completions and
workover s.
Exhibit B-l. 2007 Natural Gas Wells
Year
Appi'oxiiiiiilo N u in her of
Onshore I iieon\enlion;il
(,;is Wells
Appi'oxiiiiiilo N u in her ol'
Onshore ('un\cnlion;il (.;is
Wells
Tolsil Nil ill her ol' (>:is W oils
(hoih c<>ii\i-iilioii;il iiiid
iincon\enlion;ih
2006
35,440
375,601
411,041
2007
41,790
389,245
431,035
Exhibit B-l was used to calculate that there was a net increase of 19,994 wells (both
conventional and unconventional) between 2006 and 2007. Each of these wells is assumed
to have been completed over the course of 2006. EPA (2008) also estimates that 35,600 gas
wells were drilled in 2006. This includes exploratory wells, dry holes, and completed wells.
EPA (2008) also indicates that 19,994 of those natural gas wells were drilled and completed.
The difference between the 35,600 drilled and 19,994 new wells is 15,606 wells, which we
assume are replaced for shut-in or dry holes. This analysis assumed that 50% of those
remaining 15,606 wells were completed. Thus, the total number of gas well completions,
both conventional and unconventional, was estimated to be 27,797 wells in 2006.
19,994wells + (50% x (35,600we//s -\9,994wells)) = 21,191 wells
That is 78%) of the total gas wells drilled in 2006. We assumed this same percentage of
completed wells applies to the year 2007. EPA (2008) estimates 37,196 gas wells were
12 EPA.. (2008) U.S. Inventory of Greenhouse Gas Emissions and Sinks: 1990 - 2007. Available online at:
.
Background Technical Support Document - Petroleum and Natural Gas Industry 84
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drilled in 2007, so applying this completion factor, 78% of 37,196 wells equals 29,043 gas
wells completed in 2007.
~Estimate the Number of Conventional and Unconventional Well Completions
Exhibit B-l shows a net increase of 6,350 unconventional wells from 2006 to 2007. This is
32% of the 19,994 net increase in all wells over that period. It was assumed that 32% of the
estimated 29,043 well completions in 2007 (see previous section) were unconventional wells.
The remaining gas well completions were assumed to be conventional wells. These results
are summarized in Exhibit B-2. This analysis also assumed that all unconventional wells
require hydraulic fracture upon completion. Because these completions and workovers only
account for CBM wells and shale gas wells, it is a significant underestimate since tight sands
formations are omitted.
Exhibit B-2. 2007 Completions Activity Factors
200"7 (
Well ( oiii plot ion s
19,819
2007 l ncon\eiilion;il
Well ( oiii plot ion s
9,224
~Estimate the Number of Conventional and Unconventional Well Workovers
GRI (1996)13 provides activity data for 1992 on conventional workovers. It reported that
9,324 workovers were performed with 276,014 producing gas wells. This activity data was
projected to 2007 using the ratio of 2007 producing gas wells to 1992 producing gas wells; as
shown in Exhibit 3:
Exhibit B-3. Calculation of 2007 Conventional Workover Activity Factor
2007Gas JVclls
2007ConventionalWorhovers = 1992ConventionalWorhovers x
1992GasWells
431,03 5iveils
2007ConventionalWorkovers = 9,324workovers
276,01 Aw ells
Unconventional gas wells were assumed to be re-fractured once every 10 years. Thus, the
number of unconventional gas well workovers was 10% of the existing unconventional well
count in 2007.
The resulting activity factors for conventional and unconventional gas well workovers are
summarized in Exhibit B-4.
Exhibit B-4. Summary of 2007 Workover Activity Factors
13 GRI. Methane Emissions from the Natural Gas Industry. 1996. Available online at:
.
Background Technical Support Document - Petroleum and Natural Gas Industry
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200"7 C oil\ oillion;il
Well Worko\ers
, 431,035we//s
9,324workovers x =
276,0 Uwells
14,569
2HII"7 I ncnii\cn(inn;il
Well Worko\ers
10% x 4 l,790w//s =
4,179
~Estimate the Emission Factor for Conventional Well Completions
GRI (1996) estimated that conventional well completions emit 0.733 Mcf of methane each.
GRI (1996) assumed that all completion flowback was flared at 98% combustion efficiency
and the produced gas was 78.8% methane by volume. This analysis estimated the amount of
gas sent to the flare by dividing the reported GRI factor by the 2% un-combusted gas. The
resulting emission factor for conventional well completions was 36.65 Mcf of
methane/completion.
~Estimate the Emission Factor for Conventional Well Workovers
The GRI (1996) emission factor for well workovers was accepted for this analysis. That
emission factor is 2.454 Mcf of methane/workover for conventional wells.
~Estimate the Emission Factor for Unconventional Well Completions
The emission factor for unconventional well completions was derived using several
experiences presented at Natural Gas STAR technology transfer workshops.
One presentation14 reported that the emissions from all unconventional well completions
were approximately 45 Bcf using 2002 data. The emission rate per completion can be back-
calculated using 2002 activity data. API Basic Petroleum Handbook15 lists that there were
25,520 wells completed in 2002. Assuming Illinois, Indiana, Kansas, Kentucky, Michigan,
Missouri, Nebraska, New York, Ohio, Pennsylvania, Virginia, and West Virginia produced
from low-pressure wells that year, 17,769 of those wells can be attributed to onshore, non-
low-pressure formations. The Handbook also estimated that 73% (or 12,971 of the 17,769
drilled wells) were gas wells, but are still from regions that are not entirely low-pressure
formations. The analysis assumed that 60% of those wells are high pressure, tight formations
(and 40% were low-pressure wells). Therefore, by applying the inventory emission factor for
low-pressure well cleanups (49,570 scf/well-year1) approximately 5,188 low-pressure wells
emitted 0.3 Bcf.
40% x 12,971 wells x A9>510scf x lBcf ~ 0.3Bcf
well 10 9scf
The remaining high pressure, tight-formation wells emitted 45 Bcf less the low-pressure 0.3
Bcf, which equals 44.7 Bcf. Since there is great variability in the natural gas sector and the
resulting emission rates have high uncertainty; the emission rate per unconventional (high-
pressure tight formation) wells were rounded to the nearest thousand Mcf.
14 EPA. Green Completions. Natural Gas STAR Producer's Technology Transfer Workshop. September 21,
2004. Available online at: .
15 API. Basic Petroleum Data Handbook. Volume XXIV, Number 1. February, 2004.
Background Technical Support Document - Petroleum and Natural Gas Industry
86
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44.75c/ 10 6 Mcf ^nnntrr,
x « 6,000Mcf / completion
60% x\2,91\wells Bcf
The same Natural Gas STAR presentation14 provides a Partner experience which shares its
recovered volume of methane per well. This analysis assumes that the Partner recovers 90%
of the flowback. Again, because of the high variability and uncertainty associated with
different completion flowbacks in the gas industry, this was estimated only to the nearest
thousand Mcf - 10,000 Mcf/completion.
A vendor/service provider of "reduced emission completions" shared its experience later in
that same presentation14 for the total recovered volume of gas for 3 completions. Assuming
that 90% of the gas was recovered, the total otherwise-emitted gas was back-calculated.
Again, because of the high variability and uncertainty associated with different completion
flowbacks in the gas industry, this was rounded to the nearest hundred Mcf - 700
Mcf/completion.
The final Natural Gas STAR presentation16 with adequate data to determine an average
emission rate also presented the total flowback and total completions and re-completions.
Because of the high variability and uncertainty associated with different completion
flowbacks in the gas industry, this was rounded to the nearest 10,000 Mcf - 20,000
Mcf/completion.
This analysis takes the simple average of these completion flowbacks for the unconventional
well completion emission factor: 9,175 Mcf/completion.
~Estimate the Emission Factor for Unconventional Well Wor hovers ("re-completions")
The emission factor for unconventional well workovers involving hydraulic re-fracture ("re-
completions") was assumed to be the same as unconventional well completions; calculated in
the previous section.
~Estimate the Total National Emissions (disregarding reductions)
The estimated activity factors were multiplied by the associated emission factors to estimate
the total emissions from well completions and workovers in the U.S. for 2007. This does not
reflect reductions due to control technologies such as flares or bringing portable treatment
units onsite to perform a practice called "reduced emission completions." The results are
displayed in Exhibit B-5 below.
Exhibit B-5. Summary of Flowback: U.S. Completion and Workover Venting 2007
Acli\ i(\
Acli\il\ l";ic(or
l-'missitui l';ic(or
1 oliil I .S. Emissions
Conventional Gas Well
Completions
19,819 completions
36.65 Mcf/completion
-0.7 Bcf
Conventional Gas Well
Workovers
14,569 workovers
2.454 Mcf/workover
« 1 Bcf
16 EPA. Reducing Methane Emissions During Completion Operations. Natural Gas STAR Producer's
Technology Transfer Workshop. September 11, 2007. Available online at:
.
Background Technical Support Document - Petroleum and Natural Gas Industry
87
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Unconventional Gas
Well Completions
9,224 completions
9,175 Mcf/completion
-85 Bcf
Unconventional Gas
Well Workovers
4,179 workovers
9,175 Mcf/workover
-38. Bcf
Note: The emission factors and calculated emissions
as presented in this table were rounded independently.
TOTAL: -120 Bcf
~Estimate the Volume of Emissions That Are Not Flared
Some states regulate that completion and re-completion (workover) flowbacks must be flared
or recovered. Industry representatives have shared with EPA that flaring of completions and
workovers is required in Wyoming; however, it is not required in Texas, New Mexico, and
Oklahoma. EPA assumed that no completions were flared in the Texas, New Mexico, and
Oklahoma, then took the ratio of unconventional wells in Wyoming to the unconventional
wells in all four sample states to estimate the percentage of well completions and workovers
that are flared. EPA assumed that this sample was indicative of the rest of the U.S. This
ratio was estimated to be approximately 51%.
The portion of flared natural gas was deducted from the results of Exhibit B-5 so that only
the vented portion of natural gas from well completions and workovers was estimated. It
then converted these natural gas emissions to methane emissions using an average methane
content in produced natural gas of 78.8% by volume. The results are in Exhibit B-6, below.
Exhibit B-6. Summary of Methane Emissions: U.S. Completion and Workover Venting
2007
Activitv
Un mitigated Flow hack
Natural Gas Vented
Methane Vented
Conventional Gas Well
Completions
-0.7 Bcf
-0.37 Bcf
-0.29 Bcf
Conventional Gas Well
Workovers
« 1 Bcf
« 1 Bcf
« 1 Bcf
Unconventional Gas
Well Completions
-85 Bcf
-43 Bcf
-34 Bcf
Unconventional Gas
Well Workovers
-38. Bcf
-19 Bcf
-14 Bcf
Note: The emission factors and calculated emissions
as presented in this table were rounded independently.
TOTAL: -48 Bcf
The final resulting methane emissions from well completions and workovers is 48 Bcf. This
estimate does not include hydraulic fracturing due to completions and workovers of gas wells
in tight sands formations. Tight sands wells are not tracked by the U.S. Inventory and may
substantially increase this estimate of unconventional well completions and workovers. A
2008 INGAA study17 estimated that, in fact, approximately twice as many unconventional
wells were completed than this analysis and approximately twice as many unconventional
wells exist, 10% of which may require workover. This increase in activity is due to the
inclusion of tight sands formations. If this analysis were to account for that activity level, not
only would the number of hydraulic fractures increase substantially, but also the distribution
of wells that are required to flare by law would be shifted such that only 15% of hydraulic
17 INGAA Foundation Inc.. Availability, Economics, And Production Potential of North American
Unconventional Natural Gas Supplies. November 2008.
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fracture flowbacks would be estimated to be flared. Using INGAA's estimates of activity,
emissions would increase to 141 Bcf.
Well Blowdown Venting for Liquid Unloading
This discussion describes the methods used to estimate total U.S. methane emissions from
low-pressure well blowdowns for liquid unloading.
~Estimate the Fraction of Conventional Wells that Require Liquid Unloading
This analysis assumed that the survey of 25 well sites conducted by GRI (1996) for the base
year 1992 provides representative data for the fraction of conventional wells requiring
unloading. That is, 41.3% of conventional wells required liquid unloading.
~ Calculate Emissions per Blowdown
This analysis used a fluid equilibrium calculation to determine the volume of gas necessary
to blow out a column of liquid for a given well pressure, depth, and casing diameter. The
equation for this calculation is available in an EPA, Natural Gas STAR technical study18.
The equation is displayed in Exhibit B-7.
Exhibit B-7. Well Blowdown Emissions for Liquid Unloading
A combination of GASIS19 and LASSER20 databases provided well depth and shut-in
pressures for a sample of 35 natural gas basins. The analysis assumed an average casing
diameter of 10-inches for all wells in all basins.
~Estimate the Annual Number of Blowdowns per Well that Require Unloading
For wells that require liquid unloading, multiple blowdowns per year are typically necessary.
A calibration using the equation in the previous section was performed using public data for
the shared experiences of two Natural Gas STAR Partners.
One Partner reported that it recovered 4 Bcf of emissions using plunger lifts with "smart"
automation (to optimize plunger cycles) on 2,200 wells in the San Juan basin21. Using the
18 EPA. Installing Plunger Lift Systems in Gas Wells: Lessons Learned from Natural Gas STAR Partners.
October, 2003. Available online at: .
19 DOE. GASIS, Gas Information System. Release 2 - June 1999.
20 LASSER™ database.
21 EPA. Natural Gas STAR Partner Update: Spring 2004. Available online at:
.
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Vv= (0.37x10~6)xD2 xhxP
where,
Vv
D
h
P
Vent volume (Mcf/blowdown)
casing diameter (inches)
well depth (feet)
shut-in pressure (psig)
-------
data for San Juan basin in the equation in Exhibit B-6 required approximately 51 blowdowns
per well to match the 4 Bcf of emissions.
Another Partner reported that it recovered 12 MMcf of emissions using plunger lifts on 19
wells in Big Piney18. Using information for the nearest basin in the equation in Exhibit B-6
required approximately 11 blowdowns per well to match the 12 MMcf of emission.
The simple average of 31 blowdowns per well requiring liquid unloading was used in the
analysis to determine the number of well blowdowns per year by basin.
~Estimate the Percentage of Wells in Each Basin that are Conventional
GASIS and LASSER provided approximate well counts for each basin and GRI provided the
percentage of conventional wells requiring liquid unloading for 35 sample basins. However,
many of those basins contain unconventional wells which will not require liquid unloading.
EIA posts maps that display the concentration of conventional gas wells in each basin22, the
concentration of gas wells in tight formations by basin23, and the concentration of coal bed
methane gas wells by basin24. These maps were used to estimate the approximate percentage
of wells that are conventional in each basin. These percentages ranged from 50% to 100%.
~Estimate Emissions from 35 Sample Basins
The total well counts for each basin were multiplied by the percentage of wells estimated to
be conventional for that basin to estimate the approximate number of conventional wells in
each of the basins. The resulting conventional well counts were multiplied by the percentage
of wells requiring liquid unloading, as estimated by the GRI survey (41.3%). The number of
wells in each basin that require liquid unloading were multiplied by an average of 31
blowdowns/well to determine the number of well blowdowns for each basin. The emissions
per blowdown, as calculated using the equation in Exhibit B-6, were then multiplied by the
number of blowdowns for each basin to estimate the total well venting emissions from each
of the 35 sample basins due to liquid unloading. Using the GRI estimate that the average
methane content of production segment gas is 78.8% methane by volume, the total methane
emissions from the sample of 35 basins were calculated to be 149 Bcf.
~Extrapolate Sample Data to Entire U.S.
The sample of 35 gas well basins represented only 260,694 conventional gas wells. EPA's
national inventory25 estimated that there were 389,245 conventional gas wells in 2007. The
emission estimates were extrapolated to the entire nation by the ratio of the conventional gas
wells. The final resulting emissions from gas well venting due to liquid unloading were
estimated to be 223 Bcf.
22 EIA. Gas Production in Conventional Fields, Lower 48 States. Available online at:
.
23 EIA. Major Tight Gas Plays, Lower 48 States. Available online at:
.
24 EIA. Coal Bed Methane Fields, Lower 48 States. Available online at:
.
25 EPA. Lnventory of US Greenhouse Gas Emissions and Sinks: 1990-2006. 2007. Available online at
http://www.epa.gov/climatechange/emissions/usinventorvreport.html.
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This estimate does not include emission reductions from control methods such as plunger
lifts, plunger lifts with "smart" automation, or other artificial lift techniques.
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Appendix C: Development of threshold analysis
As the main text has pointed out the petroleum and natural gas sector includes hundreds, and
in some cases thousands, of operators, many of them with few emission sources as well as
ones with over 100 emission sources. Requiring all operators to report would impose a large
burden on the industry and also on EPA. A rule-of-thumb, substantiated by survey work, is
that 80 percent of the emissions come from 10 percent of the analysis. Therefore, a threshold
analysis was performed so that the large emitters would be identified and small insignificant
emitters could be excluded from the reporting requirement.
Threshold Analysis for Onshore Production
The following points lay out the methodology for the threshold analysis for the onshore
petroleum and natural gas production segment
• The threshold analysis for onshore (including EOR) production sector estimated the
equipment leaks, vented emissions, and combustion emissions per unique operator
per basin.
• The oil and gas production volumes per operator per basin were obtained from the
HPDI™ database 2006. The total onshore oil and gas production process and
combustion (CH4 and CO2) emissions estimated in the U.S. GHG Inventory 2006
were apportioned to each operator based on the oil or gas production volumes.
• The U.S. GHG Inventory emissions estimates for the following sources were revised:
gas well hydraulic fracture completion venting, gas well liquids unloading venting,
and gas well workover venting following hydraulic fracture. Natural Gas STAR
emission reductions reported by partners from these sources are higher than the
current inventory emission estimates. As a result emissions from these sources are
currently under-estimated in the inventory. The methodology used to revise these
emissions estimates can be found in Appendix B. In addition, emissions from storage
tanks vented and flared emissions are believed to be under estimated in the U.S. GHG
Inventory. EPA independently estimated the storage tank emissions using publicly
available data described in docket memo "Analysis of Tank Emissions" (EPA-HQ-
OAR-2009-0923-0002). EPA's estimated emissions from onshore production storage
tanks may be as high as 75 billion cubic feet (Bcf) as compared with the 12 Bcf
estimate provided in the 2006 inventory. In addition, the threshold analysis does not
account for several sources that are not represented in the U.S. GHG Inventory such
as associated gas venting and flaring, well testing venting and flaring and gas well
hydraulic fracture completion venting in tight sands, the latter because these wells are
not included in state data (See Appendix B). For all of these sources which are
believed to be under estimated in the U.S. GHG Inventory, there are Natural Gas
STAR reductions reported by production partners for year 2006 of 67 Bcf. However,
Natural Gas STAR reports generally do not state exactly where the reported
reductions were made, and in the case of production, whether they were onshore or
offshore or included oil and gas gathering equipment. Therefore, EPA has concluded
that the increase in emissions not accounted for in the U.S. GHG Inventory
approximately offset the reductions reported by Natural Gas STAR production
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partners. Because it is not feasible to map the emissions reductions reported by
Natural Gas STAR Partners to their respective facilities, apportioning reductions
equally would distort the threshold analysis. Hence, the threshold analysis does not
include both the revised estimates from storage tanks (and other missing sources) and
reductions from Natural Gas STAR because they cancel out.26
• The combustion emissions from the following sources were estimated separately as
they are not included in the U.S GHG Inventory: heater-treater, well drilling (oil and
gas), dehydrator reboiler, and acid gas removal (AGR) units.
o Heater-Treaters Combustion: The total national combustion emissions
from heater-treaters were calculated by estimating the total fuel required to
increase the temperature by 10°C of total oil produced in 2006. CO2 and N2O
combustion emission factor for natural gas from the API compendium 2004
was used to estimate the total national CO2 and N2O emissions. The total
emissions were apportioned to the operators based on their oil production
volumes.
o Dehydrator and AGR Combustion: The total national combustion
emissions from dehydrators and AGR units were estimated by applying the
fuel consumption factor of 17 Mcf of natural gas/ MMcf of gas throughput,
obtained from the EPA's Lesson Learned 2006, Replacing Glycol
Dehydrators with Desiccant Dehydrator. The total national throughput was
assumed to be equal to the total national gas produced obtained from the EIA.
C02 and N20 combustion emission factor for natural gas from the API
compendium 2004 was used to estimate the total national CO2 and N2O
emissions. The total emissions were apportioned to the operators based on
their gas production volumes.
o Well Drilling Combustion: The total national combustion emissions from
well drilling was estimated by multiplying the emissions per well drilled with
the national number of oil and gas wells drilled in the year 2006. The
emissions per well was estimated by assuming the use of two 1500 hp diesel
engines over a period of 90 days to drill each well. C02 and N20 combustion
emission factor for diesel from the API compendium 2004 was used to
estimate the total national C02 and N20 emissions. The total emissions were
apportioned to different states based on the percentage of rigs present in the
state. The number of rigs per state was obtained from Baker Hughes. The total
oil and gas well drilling combustion emissions per state was apportioned to
each operator in the state based on their oil and gas volumes respectively.
• The total barrels of oil produced per field and operator using EOR operations was
obtained from the OGJ (2006) EOR/Heavy Oil Survey.
26 A similar issue occurs with the other segments of the industry. For processing facilities, emissions from
flares are not included in the threshold analysis. For transmission segment, emissions from scrubber dump
valves and compressor unit isolation valves are not included in the threshold analysis. For the distribution
segment, the emission from combustion sources are not included in the threshold analysis. The missing and
under accounted emissions estimates roughly offset the Natural Gas STAR reductions reported. Hence, EPA
has assumed that the missing and under-accounted cancel out the Natural Gas STAR Reductions and therefore
did not include them in the threshold analyses.
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• The total make-up CO2 volume required for EOR operations was estimated using
0.29 metric tons CO2/ bbl oil produced from EOR operations obtained from DOE,
Storing CO2 with Enhanced Oil Recovery. The total recycled CO2 volumes per
operator was estimated using a factor of 0.39 metric tons C02/bbl estimated from
DOE, Storing CO2 with Enhanced Oil Recovery.
• The equipment count for EOR operations was estimated by apportioning the U.S.
GHG Inventory activity factors for onshore petroleum production to each field using
the producing well count or throughput (bbl) based on judgment. E.g. the total
number of compressors in the US used in EOR onshore production operations per
field was estimated by using the ratio of the throughput per field to the national
throughput and multiplying it by the total number of national compressors in onshore
operations.
• The emission factors in the U.S. GHG Inventory and the re-estimated activity factors
for EOR operations were used to estimate total methane emissions by volume for
EOR operations. This volume was adjusted for methane composition (assumed to be
78.8% from GRI) to estimate the natural gas emissions from EOR operations. The
composition of 97% CO2 and 1.7% CH4 was applied to the total natural gas emissions
to estimate CO2 and CH4 emissions from leaking, vented, and combustion sources
covered in the U.S. GHG Inventory 97% CO2 and 1.7% CH4 composition was
obtained from Summary of Carbon Dioxide Enhanced Oil Recovery (CO2 EOR)
Injection Well Technology.
• The following EOR emissions sources are not covered in the U.S. GHG Inventory
and therefore were estimated separately:
o Recycled injection CO2 dehydrator vented emissions
o Recycled injection CO2 compressor - vented and combustion emissions
o CO2 injection pumps - combustion and vented emissions
o Water injection pumps - combustion emissions
o Orifice meter - vented emissions from calibration
Emissions from the above mentioned sources were calculated in the following manner:
• Recycled CO2 Dehydrator: The number of dehydrators per EOR field was estimated
by using the ratio of gas throughput to the number of dehydrators indicated in the
GRI report and multiplying it by the recycled CO2 volumes. The recycled dehydrator
vented emissions were estimated using readjusted U.S. GHG Inventory emission
factor. The GRI methane emission factor was divided by 78.8% methane composition
to calculate the natural gas emission factor. The natural gas emission factor was
adjusted to EOR operation using the critical density of C02. 97% CO2 and 1.7% CH4
composition obtained from Summary of Carbon Dioxide Enhanced Oil Recovery
(CO2EOR) Injection Well Technology was used to estimate emissions.
• Recycled CO2 Injection compressor: The recycled CO2 injection compressor fuel
gas requirement was estimated using an assumed value of 65 kWhr/metric ton C02
injected. The assumption was based on the DOE study, Electricity use of EOR with
Carbon dioxide. It is assumed that only 50% of the injected C02 requires natural gas
powered compressors. CH4 and CO2 combustion emissions were estimated by
applying API compendium relevant combustion emission factors to the fuel gas used
by each operator. The fuel gas consumption was estimated using the horsepower
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requirements of engines per operator. N2O (C02e) combustion emissions were
estimated by applying API compendium N20 combustion emission factors to the fuel
gas used by each plant. The number of compressor per field was estimated using an
assumed number of 12 hp/ bbl of EOR produced oil. This number was obtained from
Enhanced Recovery Scoping Study conducted by the state of California. It is assumed
that a typical compressor used in EOR operations is 3000 hp. This number is obtained
from DOE study, Electricity use of EOR with Carbon dioxide. The compressor
blowdown emissions was estimated assuming one blowdown event per year, the
estimated number of compressors per field, and compressor blowdown emission
factor obtained from the U.S GHG inventory. The compressor blowdown emission
factor was adjusted for critical CO2 density, CO2 and CH4 gas composition. 97% CO2
and 1.7% CH4 composition obtained from Summary of Carbon Dioxide Enhanced Oil
Recovery (C02E0R) Injection Well Technology was used to estimate emissions. .
• C02 Injection pumps: The supercritical CO2 injection pumps are assumed to be
electrically driven and therefore have no combustion emissions. 97% C02 and 1.7%
CH4 composition obtained from Summary of Carbon Dioxide Enhanced Oil Recovery
(C02E0R) Injection Well Technology was used to estimate emissions. The pump
blowdown emissions were estimated assuming an internal diameter of 12 inches and
length of 30 feet with a 50% void volume. The pipe length between the blowdown
valve and unit valve was assumed to be 10 feet with a diameter of 5.38 inches. It is
assumed that the pump and pipeline vent gas equivalent to their volume once a year
during blowdown operations. The number of supercritical pumps required per field
was estimated by assuming that the EOR operations use pumps with 600 hp with a
throughput of 40 Mcf/day. These pump specifications were obtained from an
unnamed Natural Gas STAR Partner.
• Water injection pumps: The injection pump fuel gas requirement was estimated
using an assumed value of 6 kWhr/bbl of oil produced. The assumption was based on
the DOE study, Electricity use of EOR with Carbon dioxide. It is assumed that only
50% of the injection pumps are natural gas powered. CH4 and CO2 combustion
emissions were estimated by applying API compendium (2004) relevant combustion
emission factors to the fuel gas used by each operator. The fuel gas consumption was
estimated using the horsepower requirements of engines per operator. N20 (C02e)
combustion emissions were estimated by applying API compendium N2O combustion
emission factors to the fuel gas used by each plant.
• Orifice Meter Vented Emissions: It is assumed that there are 5 orifice meters for
each field based on data provided by an unnamed Natural Gas STAR Partner. The
orifice meters are assumed to be calibrated once per year during which the volume of
meter is vented to the atmosphere. The orifice meters are assumed to be 8 inches in
diameter and 12 feet in length. 97% C02 and 1.7% CH4 composition obtained from
Summary of Carbon Dioxide Enhanced Oil Recovery (C02EOR) Injection Well
Technology was used to estimate emissions.
• The total emissions per operator were calculated by summing up all the process and
combustion emissions for EOR operations and onshore production.
• Each operator was assigned a "1" if it crossed a threshold and a "0" otherwise, by
running the following logic checks:
o IF(operator total emissions > 1000) then reporting
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o IF(operator total emissions > 10000) then reporting
o IF(operator total emissions > 25000) then reporting
o IF(operator total emissions >100000) then reporting
Threshold Analysis for Offshore Production
• Federal GOM offshore platforms, by their complex ID, and their corresponding CO2
combustion and equipment leak emissions (C02e), CH4 equipment leaks (C02e), CH4
vented emissions (C02e), and N20 combusted emissions (C02e) for the year 2000
was obtained from the BOEMRE Goads Summary Access File "Final GOADS
Emissions Summaries"
• The ratio of 2006 to 2000 Gulf of Mexico offshore productions was calculated and
applied to the emissions from each platform to estimate emissions for the year 2006.
• The total number of GOM offshore production platforms was obtained from the
BOEMRE website.
• Each platform was assigned a "1" or "0" based on if it crossed an emissions threshold
by running the following logic checks:
o IF(operator total emissions > 1000) then reporting
o IF(operator total emissions > 10000) then reporting
o IF(operator total emissions > 25000) then reporting
o IF(operator total emissions >100000) then reporting
• The total number of state platforms (Alaska and Pacific) was obtained from the
Alaska Division of Oil and Gas and Emery et al27 respectively. The number of state
and federal offshore oil and gas wells for GOM, Pacific, and Alaska was obtained
from the LASSER™ database. The ratio of federal GOM oil and gas wells to federal
platforms and the number of state offshore oil and gas wells were used to estimate the
state GOM platform count.
• The ratio of gas to oil platforms was obtained from the U.S GHG Inventory 2006. All
the state offshore platforms were assumed to be shallow water platforms.
• The state offshore equipment leak, vented, and combustion emissions were estimated
by applying the ratio of state to federal platforms and multiplying it by the federal
offshore equipment leak, vented, and combustion emissions.
• The percentage of platforms that fall within each emissions threshold (1000, 10,000,
25,000 and 100,000 metric tons C02e) for the federal GOM offshore was calculated
and applied to the estimated state equipment leak, vented, and combustion emissions
to calculate the volume of state offshore emissions that fall within each threshold.
• The number of state platforms that fall within each category was estimated by taking
the ratio of federal emissions to platform count within each threshold and multiplying
it by the state emissions covered by each threshold.
• The emissions from state and federal offshore platforms were summed up to estimate
the total emissions from offshore operations
27
Emery, Brian M. et al. Do oil and gas platforms off California reduce recruitment ofbocaccio (Sebastes
paucispinis) to natural habitat? An analysis based on trajectories derived from high
frequency radar, http://www.icess.ucsb.edu/iog/pubs/DrifterSimulationsFinal v5 .pdf
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Threshold Analysis for Processing
• US gas processing plants, plant throughputs, and equipment count per plant were
obtained from the OGJ (2006). 2005 and 2006 emissions are assumed to be the same
on a plant basis as the total national throughput from 2005 to 2006 did not change
significantly and were 45,685 MMcf/d and 45,537.4 MMcf/d respectively as
indicated by the U.S. GHG Inventory
• CH4 and CO2 process emissions (C02e) per facility were estimated by multiplying the
equipment count per plant (activity factor) obtained from the Gas Processing Survey
with their corresponding emission factors obtained from GRI/ EPA 1996 reports. The
national processing sector average composition (CH4 and CO2 content) of natural gas
was obtained from GTI and applied to the GRI emission factors. Emission factor for
centrifugal compressor wet seals was obtained from Bylin et al5. Due to the
uncertainty in centrifugal compressor wet seal emissions, the point that it is not
possible to ascribe Natural Gas STAR processing partner emission reductions to a
particular processing plant or even to processing plants in general as opposed to gas
gathering equipment, the Natural Gas STAR reported processing reductions of 6
Bcf/year were not incorporated into this analysis26.
• CH4, CO2 and N2O combustion emissions (C02e) were estimated by applying CH4,
CO2 and N2O API compendium relevant combustion emission factors to the fuel gas
used by each plant. The fuel gas consumption was estimated using the horsepower
requirements of engines and turbines per plant.
• N20 combustion emissions (C02e) were estimated by applying API compendium
N2O combustion emission factors to the fuel gas used by each plant.
• The different emissions per plant was summed up to provide total emissions (C02e)
• Each facility was assigned a "1" or "0" based on if it crossed a threshold by running
the following logic checks:
o IF(operator total emissions > 1000) then reporting
o IF(operator total emissions > 10000) then reporting
o IF(operator total emissions > 25000) then reporting
o IF(operator total emissions >100000) then reporting
• Summing the results of the above logic checks for each threshold provided the
number of facilities exceeding that threshold.
• Multiplying the logic checks above by the total emissions for each facility, then
summing the results yielded the total emissions covered at each threshold.
• The resulting O&M and capital costs from the cost burden analyses were entered for
each facility in the spreadsheet. The sum of the product of O&M or capital costs and
the logic checks described above provides the total cost burdens for each reporting
threshold. Dividing the total cost burdens by the number of reporting facilities
(calculated above) provides the average facility cost burdens at each reporting
threshold.
Threshold Analysis for Transmission
• "Facility" in the natural gas transmission segment is defined as a compressor station.
Data for individual compressor stations on interstate transmission pipelines are
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reported to FERC Form 228, and data for compressor stations on intrastate pipelines
were obtained from EIA through personal contact. However, the data collected for
intrastate pipelines were incomplete.
• For intrastate pipeline facilities that did not have the number of compressor stations
listed, it was assumed that each facility has one compressor. The compressor
horsepower per intrastate pipeline was estimated by multiplying design throughput
per intrastate pipeline with the ratio of total interstate pipeline compressor
horsepower (engine and turbine) to the total interstate design throughput.
• The FERC data, supplemented with intrastate data and assumptions, list pipeline
states, names, designed throughput capacity, and in some cases the type of
compressor (centrifugal, reciprocating, and/or electric), and the installed horsepower
for each station.
• In cases where the installed reciprocating horsepower is provided, it was used for
installed engine capacity (Hp). In cases where the installed capacity was provided,
but the type of compressor was not specified, the analysis assumes that 81% of the
installed capacity is reciprocating. In cases where the provided installed capacity is
both centrifugal and reciprocating, it is assumed that 81% is for engines. The 81%
assumption is the ratio of reciprocating compressor engine capacity in the
transmission sector to centrifugal turbine drivers for 2006 taken from the U.S. GHG
Inventory
• The ratio of reciprocating compressor engine driver energy use (MMHphr, EPA1) to
interstate station design throughput capacity (MMcfd, FERC28) was calculated. Then,
the reciprocating compressor energy use for each station was assigned by multiplying
the installed station throughput capacity by the ratio calculated previously in this
bullet.
• In cases where the installed centrifugal horsepower is provided, it was used directly
for installed turbine capacity (Hp). In cases where the installed capacity was
provided, but the type of compressor was not specified, the analysis assumes that
19% of the installed capacity is centrifugal. In cases where the provided installed
capacity is both centrifugal and reciprocating, it is assumed that 19% is for turbines.
The 19%) assumption is the ratio of centrifugal compressor turbine capacity in the
transmission sector to reciprocating engine drivers taken from the U.S. GHG
Inventory.
• The ratio of centrifugal compressor engine driver energy use (MMHphr, EPA1) to
interstate station design throughput capacity (MMcfd, FERC28) was calculated. Then,
the reciprocating compressor energy use for each station was assigned by multiplying
the installed station throughput capacity by the ratio calculated previously in this
bullet.
• The total emissions for 2006, both vented and equipment leak methane and non-
energy C02, were estimated in the U.S. GHG Inventory. Emission factor for
centrifugal compressor wet seals was obtained from Bylin et al5. Due to the
uncertainty in centrifugal compressor wet seal emissions, the point that it is not
possible to ascribe Natural Gas STAR transmission partner emission reductions to a
28 FERC. Form 2 Major and Non-major Natural Gas Pipeline Annual Report. Available online at:
.
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particular compressor station or even to transmission in general as opposed to gas
storage equipment, the Natural Gas STAR reported transmission reductions of 25
Bcf/year were not incorporated into this analysis26. The total emissions were
allocated to each facility based on its portion of the segment's total station throughput
capacity, as shown in the following equation:
. . StationCapacity,
Station i process emissions = -= — xTotallnventoryEmissions
/ StationCapacity
i
• Combustion C02 and N20 emissions were estimated for each facility by applying the
following emission factors:
EFc02 = 719 metric tons C02e/MMHphr
EFN2o = 5.81 metric tons C02e/MMHphr
EmissionsCo2orN2o = EFCo2orN2o x Compressor energy; (MMHphr)
• The total emissions for each facility were calculated by summing the calculated
process and the combustion emissions.
• Each facility was assigned a "1" or "0" based on if it crossed a threshold by running
the following logic checks:
o IF(operator total emissions > 1000) then reporting
o IF(operator total emissions > 10000) then reporting
o IF(operator total emissions > 25000) then reporting
o IF(operator total emissions >100000) then reporting
• Summing the results of the above logic checks for each threshold provided the
number of facilities exceeding that threshold.
• Multiplying the logic checks above by the total emissions for each facility, then
summing the results yielded the total emissions covered at each threshold.
Threshold Analysis for Underground Storage
• "Facility" in the underground natural gas storage segment is defined as storage
stations and the connected storage wellheads. Underground storage data by operator
are collected in form EIA-17629.
• The data collected in EIA-176 contained each underground storage operator, field,
and location as well as the storage capacity and maximum daily delivery.
• The total compressor energy use in 2006 for the underground storage segment was
estimated in the U.S. GHG Inventory. This total energy use, in millions of
horsepower hours (MMHphr), is allocated to each facility based on its portion of the
segment's total maximum daily delivery capacity; as described in the following
equation:
29 EIA. EIA-176 Query System. Available online at:
.
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^ MaximumDailyDelivery,
Compressor energy; (MMHphr) = = — x TotalSegmentMMHphr
/ Maxim umDailyDelivery
i
Where, index denotes an individual facility
• The total process emissions for 2006, both vented and equipment leak methane and
non-energy CO2, were estimated in the U.S. GHG Inventory. These total process
emissions were allocated to each facility based on its portion of the segment's total
maximum daily delivery capacity, using the same methods as compressor energy use.
• Combustion C02 and N20 emissions were estimated for each facility by applying the
following emission factors:
EFc02 = 719 metric tons C02e/MMHphr
EFN2o = 5.81 metric tons C02e/MMHphr
EmissionsCo2orN2o = EFCo2orN2o x Compressor energy; (MMHphr)
• The total emissions for each facility were calculated by summing the calculated
process and the combustion emissions.
• Each facility was assigned a "1" or "0" based on if it crossed a threshold by running
the following logic checks:
o IF(operator total emissions > 1000) then reporting
o IF(operator total emissions > 10000) then reporting
o IF(operator total emissions > 25000) then reporting
o IF(operator total emissions >100000) then reporting
• Summing the results of the above logic checks for each threshold provided the
number of facilities exceeding that threshold.
• Multiplying the logic checks above by the total emissions for each facility, then
summing the results yielded the total emissions covered at each threshold.
Threshold Analysis for LNG Storage
• "Facility" in LNG storage segment is defined as LNG storage plants (peak shaving or
satellite). Data for each peak shaving facility is provided in The World LNG Source
Book - An Encyclopedia of the World LNG Industry. Summary data for all satellite
facilities is estimated in the Additional Changes to Activity Factors for Portions of the
Gas Industry background memo for EPA's U.S. GHG Inventory.
• The data reported in The World LNG Source Book - An Encyclopedia of the World
LNG Industry includes the operator, liquefaction capacity, storage capacity,
vaporization design capacity for each individual peak shaving plant.
• U.S GHG Inventory reports that in addition to peak shaving plants there are
approximately 100 satellite facilities with a total storage capacity of 8.7 Bcf. The ICF
memo also provides several key assumptions that will be discussed at the appropriate
locations below.
• The total liquefaction compressor energy use for the segment was estimated using the
methods and assumptions detailed in the background memo for EPA's U.S. GHG
Inventory. LNG company contacts provided the memo's assumption that 750
MMHphr are required for liquefaction for each million cubic feet per day of
liquefaction capacity. It assumes the liquefaction takes place over a 200-day "fill"
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season. It assumes that approximately 50% of compressors are driven by gas-fired
engines or turbines. EIA provides the LNG storage additions for 2006 on its website,
totaling 38,706 MMcf. Thus, the total liquefaction energy use for the segment was
calculated using the following formula:
LEU = 38.706M^/ ximL x 1^1.x 200^ X 50%x. WMHphr
IQQdays \ MMcfd day 1,000,000Hphr
where,
LEU = total liquefaction energy use for the segment, gas fired (MMHphr)
The total calculated liquefaction compressor energy use was apportioned to individual
facilities based on their share of the total liquefaction capacity for the segment, as
shown in the following equation:
LC
Facility "i" liquefaction MMHphr = -=rJ—xTotalSegmentMMHphr
Z_,LC
i
Where "i" indexes facilities and LC = liquefaction capacity.
Storage capacity, provided in gallons by The World LNG Source Book - An
Encyclopedia of the World LNG Industry, was converted to million cubic feet with a
conversion factor of 1 gallon of LNG =81.5 standard cubic feet of natural gas.
Boil-off liquefaction compressor energy use was calculated using assumptions
outlined in the U.S GHG Inventory. The memo assumes that 0.05% of storage
capacity boils off and is recovered by vapor recovery compressors and liquefied.
These compressors must operate all year and require the same 750 Hp per 1 MMcfd
liquefied. The boil-off liquefaction compressor energy use was thus estimated for
each facility using the following equation:
_ 5'Cjx0.05% ISO Hp (24hours) MMHphr
FBEUi =
where,
365daysx
365days MMcfd I day J 1,000,000Hphr
FBEUi = Facility "i" boil-off liquefaction compressor energy use
(MMHphr)
SC = Facility "i" storage capacity (MMcf)
Vaporization and send-out compressor energy use was also calculated based on
assumptions from the U.S GHG Inventory. It estimates that with an average send-out
pressure of 300 psia and inlet pressure of 15 psia, using 2-stage compression, a
satellite facility requires 1.86 MMHphr for each MMcfd of send-out. The send-out
period lasts all year, unlike the "fill" season. The memo also estimates that 75 Bcf of
gas were sent out from peak shaving facilities compared to 8.7 Bcf from satellite
facilities in 2003. This equates to 89.6% of send-out coming from peak shaving
plants in 2003; the analysis assumes the same is true for 2006. EIA30 provides that in
2006, total LNG withdrawals were 33,743 MMcf. The send-out compressor energy
30 EIA. Liquefied Natural Gas Additions to and Withdrawals from Storage. Available online at:
.
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use by all peak shaving plants in the segment was calculated using the following
equation:
^ , , 33,743Mkfc/ IMMMHphr
Total send-out energy use = x x 89.6%
365days MMcfd
• Send-out compressor energy use was apportioned to each peak shaving facility by its
share of the total peak shaving segment's send-out capacity; using the same method
as apportioning liquefaction energy use. (See liquefaction bullet).
• The 100 satellite facilities were assumed to be equal size and capacity. That is, 8.7
Bcf storage capacity, all of which is sent out each year. It was assumed that satellite
facilities have no liquefaction, except for that which is necessary for boil-off We
performed the above analysis on the "average" satellite facility to estimate its energy
use and emissions. The only difference was that 10.4% of EIA reported LNG
withdrawals was attributed to the satellite facilities.
• The total process emissions for 2006, both vented and equipment leak methane and
non-energy CO2, were estimated in the U.S. GHG Inventory. These total emissions
were allocated to each facility based on its portion of the segment's total storage
capacity, using the same methods as apportioning liquefaction and send-out
compressor energy use.
• Combustion CO2 and N2O emissions were estimated for each facility by applying the
following emission factors:
EFc02 = 719 metric tons C02e/MMHphr
EFN20 = 5.81 metric tons C02e/MMHphr
EmissionsCo2orN20 = EFCo2orN2o x Compressor energy; (MMHphr)
• The total emissions for each facility were calculated by summing the calculated
equipment leak, vented, and combustion emissions.
• Each facility was assigned a "1" or "0" based on if it crossed a threshold by running
the following logic checks:
o IF(operator total emissions > 1000) then reporting
o IF(operator total emissions > 10000) then reporting
o IF(operator total emissions > 25000) then reporting
o IF(operator total emissions >100000) then reporting
• Summing the results of the above logic checks for each threshold provided the
number of facilities exceeding that threshold.
• Multiplying the logic checks above by the total emissions for each facility, then
summing the results yielded the total emissions covered by each threshold.
• Satellite facilities crossed the 1,000 and 10,000-metric ton reporting threshold, but
fell well short of the 25,000-metric ton threshold.
Threshold Analysis for LNG Import Terminals
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• "Facility" in the LNG import segment is defined as the import terminals. Data is
available for this on the FERC website31. It provides the owner, location, capacity,
and 2006 import volumes for each LNG terminal.
• ICF Additional Changes to Activity Factors for Portions of the Gas Industry
background memo for EPA's U.S. Inventory assumptions were used to estimate
liquefaction, boil-off liquefaction, and send-out compressor energy use for each of the
LNG import terminals.
• It was assumed that import terminals do not have liquefaction capacity.
• Boil-off liquefaction compressor energy use was calculated using assumptions
outlined in ICF Additional Changes to Activity Factors for Portions of the Gas
Industry background memo for EPA's U.S. Inventory. The memo assumes that
0.05% of capacity boils off and is recovered by vapor recovery compressors and
liquefied. These compressors must operate all year and require the same 750 Hp per
1 MMcfd liquefied. The boil-off liquefaction compressor energy use was thus
estimated for each facility using the following equation:
FBEU, = IV- X 0 050/0 X 2ME. x ( i6idays x fours'] x MMHphr
365days MMcfd ^ day J 1,000,000Hphr
where,
FBEUj = Facility "i" boil-off liquefaction compressor energy use
(MMHphr)
IVi = Facility "i" import volume (MMcf)
• Vaporization and send-out compressor energy use was also calculated based on
assumptions from ICF Additional Changes to Activity Factors for Portions of the Gas
Industry background memo for EPA's U.S. GHG Inventory. It estimates that with an
average send-out pressure of 300 psia and inlet pressure of 15 psia, using 2-stage
compression, satellite facilities require 1.86 MMHphr for each MMcfd of send-out.
The following equation estimates the energy use at each facility:
_ ... tt.„ , IV, \.%6MMHphr
Facility 1 send-out energy use = — x —
365days MMcfd
• The total process emissions for 2006, both vented and equipment leak methane and
non-energy CO2, were estimated in the U.S. GHG Inventory. These total process
emissions were allocated to each facility based on its portion of the segment's total
import volume, using the following equation:
IV
Facility "i" process emissions InventorySegmentEmissions
i
where,
IV, = import volume and "i" represents individual facilities
• Combustion CO2 and N2O emissions were estimated for each facility by applying the
following emission factors:
EFco2 = 719 metric tons C02e/MMHphr
31 FERC. Import Terminals. Available online at: .
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EFN2o =5.81 metric tons C02e/MMHphr
EmissionsCo2orN2o = EFCo2orN20 x Compressor energy; (MMHphr)
• The total emissions for each facility were calculated by summing the calculated
process and the combustion emissions.
• Since there were only 5 active import terminals, all were assumed to be "medium" in
size.
• Each facility was assigned a "1" or "0" based on if it crossed a threshold by running
the following logic checks:
o IF(operator total emissions > 1000) then reporting
o IF(operator total emissions > 10000) then reporting
o IF(operator total emissions > 25000) then reporting
o IF(operator total emissions >100000) then reporting
• Summing the results of the above logic checks for each threshold provided the
number of facilities exceeding that threshold.
• Multiplying the logic checks above by the total emissions for each facility, then
summing the results yielded the total emissions covered by each threshold.
Threshold Analysis for Distribution
• "Facility" in the natural gas distribution segment is defined as the local distribution
company (LDC). The Department of Transportation (DOT)32 provides a set of data
that contains distribution main pipelines miles by pipeline materials and distribution
service counts by pipeline material for each LDC.
• CO2 and CH4 equipment leaks from distribution mains were evaluated for each
facility by multiplying its pipeline data by the appropriate emission factor,
summarized in the table below, from the U.S GHG Inventory1.
Exhibit C-8: LDC's Equipment I.eak Emission Factors
Pipeline 1 vpe/.Malerial
Kqiiipmenl Leak Emission
l-'aelor
Mains - Unprotected Steel
110 Mcf/mile/year
Mains - Protected Steel
3.07 Mcf/mile/year
Mains - Plastic
9.91 Mcf/mile/year
Mains - Cast Iron
239 Mcf/mile/year
Services - Unprotected
Steel
1.70 Mcf/service/year
Services - Protected Steel
0.18 Mcf/service/year
Services - Plastic
0.01 Mcf/service/year
Services - Copper
0.25 Mcf/service/year
• The total miles of mains pipelines of all materials were summed for each LDC.
• The total emissions from metering and regulating (M&R) stations for 2006, both
vented and equipment leak methane and non-energy CO2, were estimated by EPA
32 DOT. 2006 Distribution Annuals Data. Available online at:
.
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U.S GHG Inventory. These total emissions were allocated to each facility based on
its portion of the segment's total import volume, using the following equation:
MM
Facility "i" M&R emissions =-=—— x InventorySegmentEmissions
2_mm
i
where,
MM = total miles of mains pipeline, and "i" represents individual
facilities
• The total emissions for each facility were calculated by summing the calculated
pipeline leaks and M&R station emissions26.
• Each facility was assigned a "1" or "0" based on if it crossed a threshold by running
the following logic checks:
o IF(operator total emissions > 1000) then reporting
o IF(operator total emissions > 10000) then reporting
o IF(operator total emissions > 25000) then reporting
o IF(operator total emissions >100000) then reporting
• Summing the results of the above logic checks for each threshold provided the
number of facilities exceeding that threshold.
• Multiplying the logic checks above by the total emissions for each facility, then
summing the results yielded the total emissions covered at each threshold.
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Appendix D: Analysis of potential facility definitions for onshore
petroleum and natural gas production
The purpose of this appendix is to determine the barriers in using a physical definition of a
facility for the onshore petroleum and natural gas production segment. The paper also
discusses a potential alternative to a physical definition by using a corporate level reporter
definition.
A. Facility Definition: Any production sector reporting configuration will need specific
definitions on what constitutes a facility.
i. Field level - A field may be defined by either physically aggregating certain
surface equipment, referred to as physical field definition. Or the field may be
defined by demarcation of geographical boundaries, referred to as Geographic
field definition.
Physical field definition:
The challenge in defining a field as a facility is to recognize a common structure
through the oil and gas production operations. Such a definition can be achieved
by identifying a point in the system upstream of which all equipment can be
collectively referred to as a field level facility. All oil and gas production
operators are required by law to meter their oil and gas production for paying
royalties to the owner of the gas and taxes to the state, referred to as the lease
meter. All equipment upstream of this meter can be collectively referred to as a
facility.
There is no precedence for such a definition in the CAA. It must be noted,
however, that the facility definitions commonly used in the CAA pertain
specifically to pollutants whose concentration in the ambient atmosphere is the
deciding factor on its impact. This is not necessarily true of GHGs that have the
same overall impact on climate forcing irrespective of how and where they occur.
Geographic field definition:
An alternative to the lease meter field level definition is to use the EIA Oil and
Gas Field Code Master33 to identify each geological field as a facility. This
definition is structurally similar to the corporate basin level definition, i.e. it uses
geological demarcations to identify a facility rather than the above ground
operational demarcation.
ii. Basin level - The American Association of Petroleum Geologists (AAPG)
provides a geologic definition of hydrocarbon production basins which are
referenced to County boundaries. The United States Geological Survey (USGS)
33 EIA Oil and Gas Field Master - 2007,
http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/field_code_master_list/current/pdf/fcml_all.
pdf
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also provides such a definition, which is different than the AAPG definition. The
AAPG definition identified by the "geologic province code" is most commonly
used by the industry and can be used to report emissions from each basin. The
individual counties in each state are allocated to different geologic province codes
and therefore there is no ambiguity in associating an operation with the relevant
basin (geologic province code). An operation physically located on a basin as
defined by the AAPG can be identified with that particular basin, irrespective of
which basins the wells are producing from. (Well pads may have multiple wells
producing from different fields and zones in a reservoir, and possibly different
basins as well).
B. Level of Reporting: It is important to clearly distinguish the level of reporting- i.e., the
facility level or the corporate level. The level of reporting is where the threshold level is
applied and thus determination on whether reporting is required. In some cases, the
owner or operator of the facility itself is the reporter and in other cases it is the overall
company that is the reporter. For example, in subpart NN of the MRR published on
September 22, 2009, reporting for natural gas sent to the end use customers is at the local
distribution company, and not the individual physical locations (or facilities) that send the
natural gas into the economy. Alternatively, in subpart MM of the initial rule proposal,
the owner or operator of the individual refinery is the reporter as opposed to the company
owning multiple refineries.
For the purposes of onshore petroleum and natural gas production reporting can be at
either the facility level or the corporate level. If the level of reporting is at the corporate
level, it could still be required that data be reported for individual facilities.
C. Qualitative Analysis of Facility Options
The following qualitative evaluation provides a discussion on the advantages and
disadvantages of using any of the three reporting level definitions, based on expert opinion.
i. Ease of practical application of reporter and facility definitions
1) Field level facility definition - In this case the physical demarcation of field
level by aggregating field equipment is difficult to implement. On the other
hand, field level definition based on boundaries identified by the EIA Oil and
Gas Field Code Master should be easy to implement, since the classification if
widely used in the industry.
Physical Field Definition:
There are no standard guidelines or operational practices on how many wells
can be connected to one lease meter. The choice of whether multiple wells are
connected to the same lease meter depends on; the well spacing, number of
owners of leases, volume of hydrocarbons produced per well, geographical
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boundaries, and ease of operation. Therefore, such a definition will lead to
facilities of all kinds of sizes; at one extreme several well pads with multiple
wells could be connected to one lease meter, while at the other extreme where
situation demands only one well with no equipment could directly be
connected to a lease meter. In addition there will be thousands of facilities that
will be under purview.
Any lease meters located upstream of a compression system will exclude
compressors from the facility definition. This means that the required
threshold for emissions reporting may not be reached due to exclusion of the
equipment leaks as well as the combustion emissions from compressors.
Alternatively, the threshold will have to be set very low to capture any
reasonable amount of emissions from field level definition.
Geographic field definition:
The EIA publishes its Field Code Master on a yearly basis. Also, the
classification system is widely used in the industry. Hence such a definition
should be easy to implement.
2) Basin level facility definition - Basin level definition is more practical to
implement given that operational boundaries and basin demarcations are
clearly defined. Furthermore, more emissions will be captured under this
facility definition than the field level or well level definitions.
3) Corporate reporting -
It can be difficult to identify who the corporation is that would be responsible
for reporting. If the corporation can be readily identified and defined then
applying a field level facility definition using the EIA field classification or
basin level facility definition using AAPG classification becomes practical.
ii. Coverage that can be expected from each definition type
1) Field level facility definition - This definition (both physical and
geographical) provides the highest level of detail possible on emissions
sources. However, any field level definition along with a 25,000 metric tons
C02e/year threshold for reporting could potentially exclude a large portion of
the U.S. oil and gas operations. Hence only a portion of the entire emissions
from the U.S. oil and gas operations will get reported.
2) Basin level facility definition - Basin level information will throw light on the
difference in patterns of emissions from sources both as a result of being
located in different basins and as a result of different operational practices in
different companies. This definition will result in the reporting of a significant
portion of the emissions for the identified sources from the entire U.S. onshore
oil and gas operations.
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3) Corporate reporting - This definition will result in reporting of a significant
portion of the emissions for the identified sources from the entire US onshore
oil and gas operations. Since the reporting will be at a company level,
variations in emissions from sources due to location on different basins may
not be evident. However, if corporate national level reporter definition is used
in addition to field and/or basin level reporting then all possible patterns in
emissions will be evident.
D. Data Sources for Research and Analysis
i.
Clean Air Act
ii.
United States Geological Survey
iii.
Natural Gas STAR Technical Documents
iv.
EPA National GHG Inventory
v.
DOE GASIS database
vi.
Lasser® database
vii.
Energy Information Administration
viii.
Oil & Gas Journal
ix.
HARC - VOC Emissions from Oil and Condensate Storage Tanks
X.
State Oil and Gas Commissions
xi.
American Association of Petroleum Geologists
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Appendix E: Development of multipliers to scale emissions or
miscellaneous sources connected to storage tanks
This method of quantifying tank emissions assumes that thermodynamically based models
such as E&P Tank can accurately predict the effect of flashing emissions from hydrocarbons
in fixed roof storage; but are unable to predict or account for emissions from vortexing or
dump valves. Either direct measurement or a correction factor is required to represent the
total emissions from hydrocarbon storage tanks.
This appendix compares two methods of correcting E&P Tank (GEO-RVP) data to account
for non-flashing emission effects on tanks. Actual measurement data from a Texas
Commission on Environmental Quality (TCEQ) report34 were compared to E&P Tank
(GEO-RVP) data runs on the same tanks to develop a correction factor which can be applied
to E&P Tank (GEO-RVP) results in which additional non-flashing emissions or vortexing are
detected.
Selected Data
All data considered were presented in a TCEQ-funded report that compared tank emission
predicting equations, charts, and models to actual measured data. Data from the E&P Tank
2.0 GEO-RVP setting were compared against to direct measurement results. The TCEQ
study focused on comparing the various methods of predicting VOC portion of emissions;
however, for the purposes of this analysis, the total gas-oil ratios were compared.
Where direct measurement results were within ±100% of E&P Tank (GEO-RVP) results,
those tanks were assumed to be exhibiting typical flashing emissions only. Direct
measurement results greater or less than ±100% of E&P Tank (GEO-RVP) results were used
to develop a correction factor for non-flashing effects on tank emissions.
The data were separated into two regimes:
• Hydrocarbon liquids with API gravities less than 45 "API were considered "oil"
• Hydrocarbon liquids with API gravities greater than 45 "API were considered
"condensate"
Correction factors were developed for both ranges.
Method 1 - Least Squares Analysis of Emission Difference
The first method sorts qualifying tanks in ascending order of emission rates estimated by the
E&P Tank (GEO-RVP) runs. The difference between the measured emission rate and E&P
Tank (GEO-RVP) emission rates was plotted against the E&P Tank (GEO-RVP) emission
rates and a trend line was fitted to the equation, as shown in Exhibits E-9 and E-10.
Exhibit E-9. Oil Tank Correction Factors
34 Texas Commission on Environmental Quality (TCEQ). Upstream Oil and Gas Storage Tank Project Flash
Emissions Models Evaluation. July 16,2009.
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500
400
300
o- -8
08 fi 200
UJ o
100
(100)
Oil Tanks ("APK45)
y = -1.5592x+ 139.23
R2 = 0.0719
— ~
% ~ _____
40 + 50 60 70
E&P Tank Estimate (scf/bbl)
+ Measurement - E&P Tank Linear (Measurement - E&P Tank)
Exhibit E-l 0. Condensate Tank Correction Factors
Condensate Tanks (°API>45)
y = -0.6673X + 248.34
R2 = 0.0045
E&P Tank Estimate (scf/bbl)
# Measurement - E&P Tank Linear (Measurement - E&P Tank)
The equation for the line of best fit can be used on E&P Tank (GEO-RVP) results where
non-flashing emission affects are detected to estimate the true tank emissions. The data used
to derive this relationship range from oil gravities from 29.1 to 44.8°API and separator
pressures from 15 to 70 psig; and for condensate gravities from 45.3 to 82.2°API and
separator pressures from 30 to 231 psig.
The E&P Tank (GEO-RVP) emission estimates can be corrected with the following
equations:
• For oil: CE = (-0.5592 x EE) + 139.23
• For condensate: CE = (0.3327 x EE) + 248.34
Where "EE" is the E&P Tank (GEO-RVP) emission estimate and "CE" is the corrected
emission estimate.
As demonstrated in Exhibits E-9 and E-10, the correlations for the correction factor are very
weak, with R2 values of 0.0719 for oil and 0.0045 for condensate.
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Method 2 - Average Emissions Ratio Analysis
This method takes the simple average of the ratio of qualifying measured emission rates to
simulated emission rates generated by E&P Tank (GEO-RVP) for the oil and condensate
ranges.
Using this method, E&P Tank (GEO-RVP) emission estimates can be corrected with the
following equations:
• For oil: CE = 3.87 x EE
• For condensate: CE = 5.37 x EE
Where "EE" is the E&P Tank (GEO-RVP) emission estimate and "CE" is the corrected
emission estimate.
Summary
Predicting and evaluating non-flashing effects on emissions (such as dump valves or
vortexing) has not yet been thoroughly studied or quantified. The methods above have
significant weaknesses as:
1. The sample data set is limited
2. Only weak correlations were observed for the available data.
Method 1 naturally suggests that very low estimates are underestimating the tank emissions
and very high estimates (over 89 scf/bbl for oil) are overestimating the emissions. This will
tend to "even out" estimates so that none are extremely high or extremely low. It also
suggests that if E&P Tank (GEO-RVP) estimates 0 scf/bbl flashing emissions, the emission
rates are actually higher than if E&P Tank (GEO-RVP) estimates large (near 89 scf/bbl for
oil) emission rates.
Method 2 does not "even out" emission rates, and assumes that in all cases where non-
flashing effects are present, each case is uniformly underestimated.
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Appendix F: Development of leaker emission Factors
Natural Gas Emission Factors for Onshore Production
Leaker Emission Factors - All Components, Light Crude Service
Methodology
Average emission factors by facility type are taken from API's Emission Factors for Oil and
Gas Production Operations3,5. Hydrocarbon liquids greater than or equal to 20°API are
considered "light crude." The methane content of associated natural gas with onshore light
crude is 61.3% is taken from the same API publication, Table ES-4, page ES-3.
Component EF, scf/hour/component = ((Component EF, lb/day THC) * (A)) / ((B) * (C))
Component Name
Component EF,
scf/hour/comp
Component EF,
lb/day THC
Valve
2.03
3.381
Connector
0.90
1.497
Open-Ended Line
0.96
1.6
Pump
2.35
3.905
Other
2.31
3.846
EF: Emission Factor
THC: Total Hydrocarbons
Conversions:
A: 0.613 - CH4 content of onshore light crude associated natural gas
B: 0.04246 CH4 density lb/scf
C: 24 hours/day
Leaker Emission Factors - All Components, Heavy Crude Service
Methodology
Average emission factors by facility type are taken from API's Emission Factors for Oil and
Gas Production Operations3,5. Hydrocarbon liquids less than 20°API are considered "heavy
crude." The methane content of associated natural gas with onshore heavy crude is 94.2%
taken from the same API publication, Table ES-4, page ES-3.
Component EF, scf/hour/component = ((Component EF, lb/day THC) * (D)) / ((B) * (C))
Component Name
Componenl I'.l".
scf/hoiir/componenl
Componenl I'.l".
Ih/(l;i\ 1 IK
Valve
3.13
3.381
Flange
4.15
4.49
Connector (other)
1.38
1.497
Open-Ended Line
1.48
1.6
Other
3.56
3.846
35 API. Emission Factors for Oil and Gas Production Operations. Table 10, page 16. API Publication Number
4615. January 1995.
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EF: Emission Factor
THC: Total Hydrocarbons
Conversions:
B: 0.04246 CH4 density lb/scf
C: 24 hours/day
D: 0.942 - CH4 content of onshore heavy crude associated natural gas
Total Hydrocarbon Emission Factors for Processing
Leaker Emissions Factors - Reciprocating Compressor Components, Centrifugal
Compressor Components, and Other Components, Gas Service
Methodology
The leaker emissions factors are from Clearstone Engineering's Identification and Evaluation
of Opportunities to Reduce Methane Losses at Four Gas Processing Plants36 and
Clearstone's Cost-Effective Directed Inspection and Maintenance Control Opportunities at
Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites37.
The components were categorized into three groups: reciprocating compressor related,
centrifugal compressor related and all other components. Furthermore, the components
related to reciprocating and centrifugal compressor were segregated into components before
and after the de-methanizer. Once categorized, the sum of the leak rates from components
known to be leaking was divided by the sum of number of leaking components.
Component EF, scf/hour/component = (Leak rate, Mscf/day/component) * (E) / (C)
( ouipouciH
Niimo
Kccipmciiliii^ Compressor
( (tinponcnl. (scl'/hou r/comp)
< ciilril'uuiil Compressor
( (Milponcnl. (scl'/hou r/comp)
Oilier
Components.
(scl'/hou r/comp)
IKTorc Ik-
\lc(h;mi/or
Al'lcr l)o-
\le(h;mi/or
liiTorc Ik-
MiMhsiiii/cr
All or l)o-
Mclhsini/cr
Valve
15.88
18.09
0.67
2.51
6.42
Connector
4.31
9.10
2.33
3.14
5.71
Open-Ended
Line
17.90
10.29
17.90
16.17
11.27
Pressure
Relief Valve
2.01
30.46
-
-
2.01
Meter
0.02
48.29
-
-
2.93
Conversions:
C: 24 hours / day
E: 1000 scf/Mscf
36 EPA. Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas Processing
Plants. Clearstone Engineering Ltd. June 20, 2002.
37 National Gas Machinery Laboratory, Kansas State University; Clearstone Engineering, Ltd; Innovative
Environmental Solutions, Inc. Cost-Effective Directed Inspection and Maintenance Control Opportunities at
Five Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites. For EPA Natural
Gas STAR Program. March 2006.
Background Technical Support Document - Petroleum and Natural Gas Industry 114
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Total Hydrocarbon Emission Factors for Transmission
Leaker Emission Factors - All Components, Gas Service
Methodology
Gas transmission facility emissions are drawn from the Handbook for Estimating Methane
Emissions from Canadian Natural Gas Systems38 and the Measurement of Natural Gas
Emissions from the Canadian Natural Gas Transmission and Distribution Industry39. All
compressor related components were separated from the raw data and categorized into the
component types. Once categorized, the sum of the leak rates from components known to be
leaking was divided by the sum of number of leaking components.
Component EF, scf/hour/component = (Gas Transmission Facility Emissions, kg/h/src) * (F)
/(B)
(omponcnl Niimo
( oiiipoiienl 111'.
( scI'/Ikmi r/ci tin p)
Connector
2.7
Block Valve
10.4
Control Valve
3.4
Compressor Blowdown Valve
543.5
Pressure Relief Valve
37.2
Orifice Meter
14.3
Other Meter
0.1
Regulator
9.8
Open-Ended Line
21.5
Conversions:
B: 0.04246 CH4 density lb/scf
F: 2.20462262 lb/kg
Methane Emission Factors for LNG Storage
Leaker Emission Factors - LNG Storage Components, LNG Service
Methodology
38 Clearstone. Handbook for Estimating Methane Emissions from Canadian Natural Gas Systems. Clearstone
Engineering Ltd., Enerco Engineering Ltd, and Radian International. May 25, 1998.
39 Clearstone. Measurement of Natural Gas Emissions from the Canadian Natural Gas Transmission and
Distribution Industry. Clearstone Engineering Ltd., Canadian Energy Partnership for Environmental Innovation
(CEPEI). April 16, 2007.
Background Technical Support Document - Petroleum and Natural Gas Industry 115
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The light liquid emission factors with leak concentrations greater than or equal to 10,000
ppmv were taken from Protocol for Equipment Leak Emission Estimates40. The emissions
are assumed to be 100% methane.
Component EF, scf/hour/component = (Light Liquid >= 10,000 ppmv Emission Factor) * (F)
/(B)
( oinpoiiciil ViiiH'
( 0111 ponent 111',
scl'/hoii r/ccuii p
l.iiihl l.i(|iii(l F.I-'.
k»/hr Tll(
Valve
1.19
2.30E-02
Pump Seal
4.00
7.70E-02
Connector
0.34
6.50E-03
Other
1.77
3.40E-02
t
Greater or equal to 10,000 ppmv
Conversions:
B: 0.04246 CH4 density lb/scf
F: 2.20462262 lb/kg
Total Hydrocarbon Emission Factors for Processing, Transmission, and
Underground Storage
Leaker Emissions Factors -Compressor Components, Non-Compressor Components,
Gas Service
Methodology
Several leaker emission factors for the processing segment, such as open-ended lines before
the de-methanizer for reciprocating compressors, did not have sufficient data points to justify
a representative emission factor. To eliminate this issue, the segregation of components into
reciprocating versus centrifugal and before the de-methanizer versus after the de-methanizer
was eliminated.
In addition, the leaker emission factors from transmission were combined with those from
processing. Equipment leak emissions from transmission compressors and processing
compressors are similar because they are comparable in size and discharge pressure.
Compressors in processing either inject residue gas into high pressure transmission pipelines
or pressurize large volumes of production gas for processing facility processes.
The same LEFs can also be used for compressor related components in underground natural
gas storage because compressors in this sector have a large throughput and inject gas at high
pressure into the ground or into transmission pipelines. The final emission factors were
corrected to 68°F and 14.7 psia per the definition of "standard conditions" set forth in subpart
A of Title 40 CFR98.
40 EPA. Protocol for Equipment Leak Emission Estimates. Emission Standards Division. U.S. EPA. SOCMI
Table 2-7. November 1995.
Background Technical Support Document - Petroleum and Natural Gas Industry 116
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Component EF, scf/hour/component = (Leak rate, Mscf/day/component) * (E) / (C)
Component Name
Kniission I'aclor (siT/hour/componcnt)
Leaker Emission Factors - Compressor Components, Gas Service
Valve
15.07
Connector
5.68
Open-ended Line
17.54
Pressure Relief Valve
40.27
Meter
19.63
Leaker Emission Factors - Non -Compressor Components, Gas Service
Valve
6.52
Connector
5.80
Open-ended Line
11.44
Pressure Relief Valve
2.04
Meter
2.98
Conversions:
C: 24 hours / day
E: 1000 scf/Mscf
Methane Emission Factors for LNG Terminals
Leaker Emission Factors - LNG Terminals Components, LNG Service
Methodology
See methodology for Leaker Emission Factors - LNG Storage Components, LNG Service for
LNG Storage40.
Methane Emission Factors for Distribution
Leaker Emission Factors - Above Grade M&R Stations Components, Gas Service
Methodology
Gas distribution meter/regulator station emissions are drawn from: Handbook for Estimating
Methane Emissions from Canadian Natural Gas Systems38 and Measurement of Natural Gas
Emissions from the Canadian Natural Gas Transmission and Distribution Industry3,9.
Component EF, scf/hour/component = (Gas Distribution Meter/Regulator Station Emissions,
kg/h/src) * (F) / (B)
Component Name
Component 111-',
scr/hoiii'/comp
Gas Dislrihulion Melcr/Rciiiilalor
Station I'lmissions. kti/h/sre
Connector
0.67
0.01292
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Block Valve
1.49
0.02872
Control Valve
3.94
0.07581
Pressure Relief Valve
5.24
0.1009
Orifice Meter
0.46
0.0088
Other Meter
0.01
0.0002064
Regulator
2.14
0.04129
Open-Ended Line
6.01
0.1158
Conversions:
B: 0.04246 CH4 density lb/scf
F: 2.20462262 lb/kg
Leaker Emission Factors - Distribution Mains and Services, Gas Service
Methodology
Emission factors for pipeline leaks (mains and services) are drawn from GRI's Methane
Emissions from the Natural Gas Industry41.
Component EF, scf/hour/leak = (Pipeline Leak, scf/leak-year) / (G)
( OIlipoilClll NillllC
Compuncnl 111-'
(Miiins).
siT/hoiir/lciik
Pipeline l.c;ik 111'
(Miiins).
scl'/lc;ik-\ r
(ompnncnl 111'.
(Sen ices)
sclVlioiii'/lciik
Pipeline l.ciik 111'
(Sen ices).
scl'/lc;ik-\ r
Unprotected Steel
O.02
52 "48
¦> v.
20433
Protected Steel
2.38
20891
1.08
9438
Plastic
11.63
101897
0.35
3026
Copper
0.88
7684
Conversions:
G: 8,760 hours/year
NATURAL GAS EMISSION FACTORS FOR ONSHORE PRODUCTION
Onshore production
Emission Factor
(scf/hour/component)
Leaker Emission Factors - All Components, Gas Service
Valve
NA
Connector
NA
Open-ended Line
NA
Pressure Relief Valve
NA
Low-Bleed Pneumatic Device Vents
NA
Gathering Pipelines
NA
CBM Well Water Production
NA
Compressor Starter Gas Vent
NA
Conventional Gas Well Completion
NA
41 GRI. Methane Emissions from the Natural Gas Industry. Volume 9. Tables 8-9 and 9-4. June 1996.
Background Technical Support Document - Petroleum and Natural Gas Industry 118
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Conventional Gas Well Workover
NA
Leaker Emission Factors - All Components, Light Crude Service1
Valve
2.03
Connector
0.90
Open-ended Line
0.96
Pump
2.35
Other
2.31
Leaker Emission Factors - All Components, Heavy Crude Service2
Valve
3.13
Flange
4.15
Connector (other)
1.38
Open-ended Line
1.48
Other
3.56
1 Hydrocarbon liquids greater than or equal to 20°API are considered "light crude"
2 Hydrocarbon liquids less than 20°API are considered "heavy crude"
TOTAL HYDROCARBON EMISSION FACTORS FOR PROCESSING
Before De-Methanizer
After De-Methanizer
Processing1
Emission Factor
Emission Factor
(scf/hour/component)
(scf/h o u r/co m po n e nt)
Leaker Emission Factors - Reciprocating Compressor Components, Gas Service
Valve
15.88
18.09
Connector
4.31
9.10
Open-ended Line
17.90
10.29
Pressure Relief Valve
2.01
30.46
Meter
0.02
48.29
Leaker Emission Factors - Centrifugal Compressor
Components, Gas Service
Valve
0.67
2.51
Connector
2.33
3.14
Open-ended Line
17.90
16.17
Leaker Emission Factors - Other Components, Gas Service2
Valve
6.42
Connector
5.71
Open-ended Line
11.27
Pressure Relief Valve
2.01
Meter
2.93
METHANE EMISSION FACTORS FOR TRANSMISSION
Transmission
Emission Factor (scf/hour/component)
Leaker Emission Factors - All Components, Gas Service
Connector
2.7
Block Valve
10.4
Background Technical Support Document - Petroleum and Natural Gas Industry 119
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Control Valve
3.4
Compressor Blowdown Valve
543.5
Pressure Relief Valve
37.2
Orifice Meter
14.3
Other Meter
0.1
Regulator
9.8
Open-ended Line
21.5
Leaker Emission Factors - Other Components, Gas Service
Low-Bleed Pneumatic Device Vents
NA
1 Emission Factor is in units of "scf/hour/mile"
METHANE EMISSION FACTORS FOR UNDERGROUND STORAGE
Underground Storage
Emission Factor (scf/hour/component)
Leaker Emission Factors - Storage Station, Gas Service
Connector
0.96
Block Valve
2.02
Control Valve
3.94
Compressor Blowdown Valve
66.15
Pressure Relief Valve
19.80
Orifice Meter
0.46
Other Meter
0.01
Regulator
1.03
Open-ended Line
6.01
Leaker Emission Factors - Storage Wellheads, Gas Service
Connector
NA
Valve
NA
Pressure Relief Valve
NA
Open-ended Line
NA
Leaker Emission Factors - Other Components, Gas Service
Low-Bleed Pneumatic Device Vents
NA
TOTAL HYDROCARBON EMISSION FACTORS FOR PROCESSING, TRANSMISSION, AND, UNDERGROUND
STORAGE
Processing, Transmission, and Underground Storage
Emission Factor (scf/hour/component)
Leaker Emission Factors - Compressor Components, Gas Service
Valve
15.07
Connector
5.68
Open-Ended Line
17.54
Pressure Relief Valve
40.27
Meter
19.63
Leaker Emission Factors - Non-compressor Components , Gas Service
Valve
6.52
Connector
5.80
Open-Ended Line
11.44
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120
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Pressure Relief Valve
2.04
Meter
2.98
1
Valves include control valves, block valves, and regulator valves.
METHANE EMISSION FACTORS FOR LNG STORAGE
LNG Storage
Emission Factor
(scf/hour/component)
Leaker Emission Factors - LNG Storage Components, LNG Service
Valve
Pump Seal
Connector
Other
1.19
4.00
0.34
1.77
Leaker Emission Factors - LNG Storage Compressor, Gas Service
Vapor Recovery Compressor
NA
METHANE EMISSION FACTORS FOR LNG TERMINALS
LNG Terminals
Emission Factor
(scf/hour/component)
Leaker Emission Factors - LNG Terminals Components, LNG Service
Valve
Pump Seal
Connector
Other
1.19
4.00
0.34
1.77
Leaker Emission Factors - LNG Terminals Compressor, Gas Service
Vapor Recovery Compressor
NA
METHANE EMISSION FACTORS FOR DISTRIBUTION
Distribution
Emission Factor
(scf/hour/component)
Leaker Emission Factors - Above Grade M&R Stations Components, Gas Service
Connector
Block Valve
Control Valve
Pressure Relief Valve
Orifice Meter
Regulator
Open-ended Line
1.69
0.557
9.34
0.270
0.212
26.131
1.69
Leaker Emission Factors - Below Grade M&R Stations Components, Gas Service
Below Grade M&R Station, Inlet Pressure > 300 psig
Below Grade M&R Station, Inlet Pressure 100 to 300 psig
Below Grade M&R Station, Inlet Pressure < 100 psig
NA
NA
NA
Leaker Emission Factors - Distribution Mains, Gas Service1
Unprotected Steel | 6.02
Background Technical Support Document - Petroleum and Natural Gas Industry
121
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Protected Steel
2.38
Plastic
11.63
Cast Iron
NA
Leaker Emission Factors - Distribution Services, Gas Service1
Unprotected Steel
2.33
Protected Steel
1.08
Plastic
0.35
Copper
0.88
1 Emission Factor is in units of "scf/hour/leak"
Summary
This Appendix provides leaker emissions factors that can be applied to any individual
emissions source which meets the leak detection definition in a leak detection survey. These
emissions factors provide an estimate of real emissions as opposed to potential emissions
since they are applied only to leaking emissions sources. However, it must be noted that
these leaker emissions factors assume that any emissions source found leaking has been
leaking for the duration of an entire year.
Background Technical Support Document - Petroleum and Natural Gas Industry 122
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Appendix G: Development of population emission factors
Natural Gas Emission Factors for Onshore Production
Whole Gas Population Emission Factors - All Components, Gas Service
Methodology
The well counts and emission factors were taken from GRI's Methane Emissions from the
Natural Gas Industry42. The emission factors for each source are calculated using gas
production for the Eastern and Western United States. The average methane content of
produced natural gas is assumed to be 78.8%.
Eastern/Western U.S. Component EF, scf/hour/component = (EF Eastern/Western U.S.,
mscf/yr) * (A) * (B) / (C) / (D)
( omponcnl
I'.sislcrn I .S. IP\/(,UI I I (nisei"
CI l4/> o;i rt
I'.iislorn I .S. Siihpiirl \\ HI-" (scf
n;iliir;il liiis/hour)
Valve
0.184
0.027
Connector
0.024
0.004
Open-Ended Line
0.420
0.062
Pressure Relief Valve
0.279
0.041
(omponcnl
\\cslcrn I .S. IP\/(,UI 111- (mscl
( ll4/>Oill )
Western I .S. Suhpiii'l \\ 111-" (scf
iiiiliii'iil tills/hour)
Valve
0.835
0.123
Connector
0.114
0.017
Open-Ended Line
0.215
0.032
Pressure Relief Valve
1.332
0.196
Conversions:
A: 1,000 scf/mscf
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
C: 8,760 hours/year
D: 78.8% methane by volume in produced natural gas
"High Continuous Bleed Pneumatic Device Vents" Methodology
Methane emissions per pneumatic device are from API's Compendium of Greenhouse Gas
Emissions Methodologies for the Oil and Gas Industry 43. The average methane content of
natural gas is assumed to be 78.8%.
48.1 scf/hour/component EF = (896 [scfd CH4/pneumatic devises, high bleed]) * (B) / (D) /
(E)
42 GRI. Methane Emissions from the Natural Gas Industry. Volume 8. June 1996.
43 API. Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry. American
Petroleum Institute. Table 5-15, page 5-68. August 2009.
Background Technical Support Document - Petroleum and Natural Gas Industry
123
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Conversions:
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
D: 78.8% - production quality of natural gas (% methane) 44
E: 24 hours/day
"Low Continuous Bleed Pneumatic Device Vents" Methodology
Methane emissions per pneumatic device are from API's Compendium of Greenhouse Gas
Emissions Methodologies for the Oil and Gas Industry43. The average methane content of
natural gas is assumed to be 78.8%.
1.80 scf/hour/component EF = (33.4 [scfd CHVpneumatic devises, low bleed]) * (B) / (D) /
(E)
Conversions:
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
D: 78.8% - production quality of natural gas (% methane)
E: 24 hours/day
"Intermittent Bleed Pneumatic Device Vents" Methodology
Methane emissions per pneumatic device are from API's Compendium of Greenhouse Gas
Emissions Methodologies for the Oil and Gas Industry43. The average methane content of
natural gas is assumed to be 78.8%.
17.4 scf/hour/component EF = (323 [scfd CH4/pneumatic devises, low bleed]) * (B) / (D) /
(E)
Conversions:
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
D: 78.8% - production quality of natural gas (% methane)44
E: 24 hours/day
"Pneumatic Pumps" Methodology
Methane emissions per pneumatic pump are from GRI's Methane Emissions from the
Natural Gas Industry45. The average methane content of natural gas is assumed to be 78.8%.
13.3 scf CH4/hour/component EF = (248 [scfd CH4/pneumatic devises, low bleed]) * (B) /
(D) / (E)
44 GRI. "Vented and Combustion Source Summary," Methane Emissions from the Natural Gas Industry, U.S.
EPA, Volume 6, Appendix A, page A-2.
45 GRI. Methane Emissions from the Natural Gas Industry. Volume 13. Tables 4-4. June 1996.
.
Background Technical Support Document - Petroleum and Natural Gas Industry
124
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Conversions:
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
D: 78.8% - production quality of natural gas (% methane)46
E: 24 hours/day
Population Emission Factors - All Components, Light Crude Service
Methodology
Average emissions factors by facility type were taken from API's Emission Factors for Oil
and Gas Production Operations.47 Hydrocarbon liquids greater than or equal to 20°API are
considered "light crude."
Component EF, scf/hour/component = (Average Emissions Factors by Facility Type,
lb/component-day) * (B) / (E) / (F)
('(MllJ)OIKMII Nil Mil*
Component 111-',
scl'/h r/conip
A\er;ilic I.I In l ;icilil\ T\|H\
II>/coiii ponen I-(I;i>
Valve
0.U4
7.UUE-U2
Flange
0.002
4.07E-03
Connector
0.005
8.66E-03
Open-Ended Line
0.04
6.38E-02
Pump
0.01
1.68E-02
Other
0.23
3.97E-01
Conversions:
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
D: 24 hours/day
F: 0.072 gas density lb/scf- assumes a gas composition of 61.2% methane, 20% ethane,
10%) propane, 5% butane, and 3.8%> pentanes+
Population Emission Factors - All Components, Heavy Crude Service
Methodology
Average emissions factors by facility type were taken from API's Emission Factors for Oil
and Gas Production Operations4*. Hydrocarbon liquids less than 20°API are considered
"heavy crude." The methane content of associated natural gas with onshore light crude is
94.2% from the same study.
46 GRI. "Vented and Combustion Source Summary," Methane Emissions from the Natural Gas Industry, U.S.
EPA, Volume 6, Appendix A, page A-2.
47 API. Emission Factors for Oil and Gas Production Operations. Table 9, page 10. API Publication Number
4615. January 1995.
48 API. Emission Factors for Oil and Gas Production Operations. API Publication Number 4615. page ES-3,
Table ES-4, January 1995.
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125
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Component EF, scf/hour/component = (Average Emissions Factors by Facility Type,
lb/component-day) * (B) / (D) / (F)
('umpoiK'iil Niimo
( oinpoiiciil 111-',
scl'/h r/com p
A\emtio 111' In l';icili(\ T\|H\
Ih/com poiioii l-«l;i>
Valve
0.0004
6.86E-U4
Flange
0.0002
1.16E-03
Connector (Other)
0.0004
4.22E-04
Open-Ended Line
0.004
8.18E-03
Other
0.002
3.70E-03
Conversions:
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
D: 24 hours/day
F: 0.072 gas density lb/scf- assumes a gas composition of 61.2% methane, 20% ethane,
10%) propane, 5% butane, and 3.8%> pentanes+
Methane Emission Factors For Processing
Population Emission Factors - All Components, Gas Service
There are no population emission factors in subpart W for the onshore natural gas processing
segment.
Methane Emission Factors for Transmission
Population Emission Factors - All Components, Gas Service
Gas transmission facility emission factors were taken from the Handbook for Estimating
Methane Emissions from Canadian Natural Gas Systems49. "Connector" includes flanges,
threaded connections, and mechanical couplings. "Block Valve" accounts for emissions
from the stem packing and the valve body, and it applies to all types of block valves (e.g.,
butterfly, ball, globe, gate, needle, orbit, and plug valves). Leakage past the valve seat is
accounted for the Open-Ended Line emission category. Leakage from the end connections
is accounted for by the connector category (i.e., one connector for each end). "Control
Valve" accounts for leakage from the stem packing and the valve body. Emissions from the
controller and actuator are accounted for by the Instrument Controller and Open-Ended Line
categories respectively. This factor applies to all valves with automatic actuators (including
fuel gas injection valves on the drivers of reciprocating compressors). "Orifice Meter"
accounts for emissions from the orifice changer. Emissions from sources on pressure tap
lines etc. are not included in the factor (i.e., these emissions must be calculated separately).
49 CEPEI. Handbook for Estimating Methane Emissions from Canadian Natural Gas Systems. May 25, 1998.
Background Technical Support Document - Petroleum and Natural Gas Industry
126
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"Other Meter" accounts for emissions from other types of gas flow meters (e.g., diaphragm,
ultrasonic, roots, turbine, and vortex meters).
Component EF, scf/hour/component = (Gas Transmission Facility Emissions, kg/h/src) * (B)
* (I) / (F)
('(MllJ)OIKMII Nil Mil*
( oinpniu'iil 111',
scl'/hou r/conip
(>iis Tmnsmission l';icili(\
A\ii. Emissions. ku/hr/siv
Connector
0.01
2.732L-04
Block Valve
0.11
2.140E-03
Control Valve
1.04
1.969E-02
Pressure Relief Valve
14.74
2.795E-01
Orifice Meter
0.18
3.333E-03
Other Meter
0.0005
9.060E-06
Regulator
0.17
3.304E-03
Open-Ended Line
4.40
8.355E-02
Conversions:
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
F: 0.04246 CH4 density lb/scf
I: 2.20462262 lb/kg
Population Emission Factors - Other Components, Gas Service
"Low Continuous Bleed Pneumatic Device Vents" Methodology
Methane emissions per pneumatic device are from API's Compendium of Greenhouse Gas
Emissions Methodologies for the Oil and Gas Industry43. The average methane content of
natural gas is assumed to be 78.8%.
1.41 scf/hour/component EF = (33.4 [scfd CH4/pneumatic devises, low bleed]) * (B) * (J) /
(D) / (E)
Conversions:
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
D: 78.8% - production quality of natural gas (% methane) from: "Vented and
Combustion Source Summary," Methane Emissions from the Natural Gas Industry,
U.S. EPA, Volume 6, Appendix A, page A-2.
E: 24 hours/day
J: 93.4% - pipeline quality natural gas (% methane) from: "Vented and
Combustion Source Summary," Methane Emissions from the Natural Gas Industry,
U.S. EPA, Volume 6, Appendix A, page A-2.
"High Continuous Bleed Pneumatic Device Vents" Methodology
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127
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Methane emissions per pneumatic device are from GRI's Methane Emissions from the
Natural Gas Industry50. The average methane content of natural gas is assumed to be 78.8%.
18.8 scf/hour/component EF = (162,197 [scfy CH4/pneumatic devises, low bleed]) * (B) /
(C)
Conversions:
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
C: 8,760 hours/year
"Intermittent Bleed Pneumatic Device Vents" Methodology
Methane emissions per pneumatic device are from GRI's Methane Emissions from the
Natural Gas Industry50. The average methane content of natural gas is assumed to be 78.8%.
18.8 scf/hour/component EF = (162,197 [scfy CH4/pneumatic devises, low bleed]) * (B) /
(C)
Conversions:
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
C: 8,760 hours/year
Methane Emission Factors for Underground Storage
Population Emission Factors - Storage Station, Gas Service
Methodology
See methodology for "Population Emission Factors - All Components, Gas Service" for
Transmission.
Population Emission Factors - Storage Wellheads, Gas Service
Methodology
Emission factors for injection/withdrawal wellheads are from GRT s Methane Emissions from
the Natural Gas Industry4,2.
Component EF, scf/hour/component = (Injection/Withdrawal Wellhead) (A) * (B) / (C)
( oilipniK'iM Niiino
(ompnncnl Ml-',
scl'/li r/coni |>
Injcclions/W i(hdr;i\\;il
WcIIIk-skI. McI/m-
Connector
0.01
0.125
50GRI. Methane Emissions from the Natural Gas Industry. Volume 12. Page 52. June 1996.
.
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Valve
0.10
0.918
Pressure Relief Valve
0.17
1.464
Open-Ended Line
0.03
0.237
Conversions:
A: 1,000 scf/mscf
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
C: 8,760 hours/year
Population Emission Factors - Other Components, Gas Service
Methodology
"Low Continuous Bleed Pneumatic Device Vents" Methodology
See "Low Continuous Bleed Pneumatic Device Vents" Methodology for Population
Emission Factors - Other Components, Gas Service for Transmission.
"High Continuous Bleed Pneumatic Device Vents" Methodology
See "High Continuous Bleed Pneumatic Device Vents" Methodology for Population
Emission Factors - Other Components, Gas Service for Transmission.
"Intermittent Bleed Pneumatic Device Vents" Methodology
See "Intermittent Bleed Pneumatic Device Vents" Methodology for Population Emission
Factors - Other Components, Gas Service for Transmission.
Methane Emission Factors for LNG Storage
Population Emission Factors - LNG Storage Components, LNG Service
Methodology
Component emission factors are from EPA's Inventory of U.S. Greenhouse Gas Emissions
and Sinks51. The emission factors were adjusted by an assumed average methane content of
93.4% by volume.
Component EF, scf/hour/component = (Component EF, Mscf/comp-yr) (B) * (I) / (F)
Component Vimc
Component 111-',
scl'/hou r/coiiip
Component 111-'.
Mscf/conip-v r
Valve
0.10
0.867
Open-ended Line
1.30
11.2
Connector
0.02
0.147
PRV
0.72
6.2
Conversions:
51 EPA. Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2006. Available online at
.
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B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
F: 0.04246 CH4 density lb/scf
I: 2.20462262 lb/kg
Population Emission Factors - LNG Storage Compressor, Gas Service
"Vapor Recovery Compressor" Methodology
The methane emissions per compressor are from the Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-200751.
4.23 scf/hour/component EF = (100 scfd CH4/compressor) * (B) / (D)
Conversions:
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
D: 24 hours/day
Methane Emission Factors for LNG Terminals
Population Emission Factors - LNG Terminals Components, LNG Service
Methodology
See methodology for Population Emission Factors - LNG Storage Components, LNG
Service for LNG Storage.
Population Emission Factors - LNG Terminals Compressor, Gas Service
Methodology
See "Vapor Recovery Compressor" Methodology for Population Emission Factors - LNG
Storage Compressor, Gas Service for LNG Storage.
Methane Emission Factors for Distribution
Population Emission Factors - Above Grade M&R Stations Components, Gas Service
Methodology
Gas distribution meter/regulator station average emissions from: Gas transmission facility
emissions are from the Handbook for Estimating Methane Emissions from Canadian Natural
Gas Systems49. "Connector" includes flanges, threaded connections, and mechanical
couplings. "Block Valve" accounts for emissions from the stem packing and the valve body,
and it applies to all types of block valves (e.g., butterfly, ball, globe, gate, needle, orbit, and
plug valves). Leakage past the valve seat is accounted for the Open-Ended Line emission
category. Leakage from the end connections is accounted for by the connector category
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(i.e., one connector for each end). "Control Valve" accounts for leakage from the stem
packing and the valve body. Emissions from the controller and actuator are accounted for by
the Instrument Controller and Open-Ended Line categories respectively. This factor applies
to all valves with automatic actuators (including fuel gas injection valves on the drivers of
reciprocating compressors). "Orifice Meter" accounts for emissions from the orifice
changer. Emissions from sources on pressure tap lines etc. are not included in the factor (i.e.,
these emissions must be calculated separately). "Other Meter" accounts for emissions from
other types of gas flow meters (e.g., diaphragm, ultrasonic, roots, turbine, and vortex meters).
Component EF, scf/hour/component = (Gas Distribution Meter/Regulator Station Emissions,
kg/h/src) * (B) * (I) / (F)
( omponcnl Niiino
Component 111-',
scl'/hou r/coiiip
(>:is Distribution Mckr/Riiiuhilnr
Sliilion \\\i. Emissions. kg/h/src
Connector
5.~9L-U3
1.U9SL-U4
Block Valve
5.85E-02
1.109E-03
Control Valve
1.04E+00
1.969E-02
Pressure Relief Valve
8.78E-01
1.665E-02
Orifice Meter
1.76E-01
3.333E-03
Other Meter
4.78E-04
9.060E-06
Regulator
1.01E-01
1.915E-03
Open-Ended Line
4.39E+00
8.355E-02
Conversions:
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
F: 0.04246 CH4 density lb/scf
I: 2.20462262 lb/kg
Population Emission Factors - Below Grade M&R Stations Components, Gas Service
Methodology
Average emission factors are from GRI's Metering and Pressure Regulating Stations in
Natural Gas Transmission and Distribution52. (Converted to 68 °F)
Below Grade M&R Station, Inlet Pressure > 300 psig: 1.32 scf/hour/station EF
Below Grade M&R Station, Inlet Pressure 100 to 300 psig: 0.20 scf/hour/station EF
Below Grade M&R Station, Inlet Pressure < 100 psig: 0.10 scf/hour/station EF
Population Emission Factors - Distribution Mains and Services, Gas Service
Methodology
52GRI. Methane Emissions from the Natural Gas Industry. Volume 10. Table 7-1. June 1996.
.
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Emission factors for pipeline leaks (mains and service) are from the Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-200753
Component EF, scf/hour/service = (Pipeline Leak mscf/mile/year) (A) * (B) / (C)
Component \;imc
Component 111-'
(.Miiins).
scl'/hr/scr\ ice
Pipeline l.e:ik 111-'
(Miiins).
Mscr/milc-\ r
Component 111-'
(Sen ices).
scf/hr/scr\ ice
Pipeline l.e:ik 111-'
(Sen ices).
Mscf/milc-\ r
Unprotected Steel
12.77
iiu.iy
U. 19
1 "u
Protected Steel
0.36
3.07
0.02
0.18
Plastic
1.15
9.91
0.001
0.01
Cast Iron
27.67
238.7
Copper
0.03
0.25
Conversions:
A: 1,000 scf/mscf
B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F per subpart A
definition of standard conditions
C: 8,760 hours/year
Nitrous Oxide Emission Factors for Gas Flaring
Population Emission Factors - Gas Flaring
Methodology
Emission factors are from API's Compendium of Greenhouse Gas Emissions Methodologies
for the Oil and Gas Industry.
Gas Production: 5.90E-07 metric tons/MMcf gas production or receipts EF
Sweet Gas Processing: 7.10E-07 metric tons/MMcf gas production or receipts EF
Sour Gas Processing: 1.50E-06 metric tons/MMcf gas production or receipts EF
Conventional Oil Production: 1.00E-04 metric tons/barrel conventional oil production EF
Heavy Oil Production: 7.30E-05 metric tons/barrel heavy oil production EF
Summary
This Appendix provides population emissions factors for potential emissions sources. These
population emissions factors could be used in conjunction with population counts that make
it more cost effective in estimating emissions. However, these population emissions factors
estimate potential emissions as the percentage of emissions sources leaking may or may not
53 EPA. Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2007. Available online at
.
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be the same as the assumption made when developing the emissions factors. Also, the
population emissions factors assume that a subset of leaking emission sources is leaking
continuously throughout the year.
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Appendix H: Glossary
The following definitions are based on common industry terminology for the respective
equipment, technologies, and practices.
Absorbent circulation pump means a pump commonly powered by natural gas
pressure that circulates the absorbent liquid between the absorbent regenerator and natural
gas contactor.
Acid gas means hydrogen sulfide (H2S) and/or carbon dioxide (CO2) contaminants
that are separated from sour natural gas by an acid gas removal unit.
Acid gas removal unit (AGR) means a process unit that separates hydrogen sulfide
and/or carbon dioxide from sour natural gas using liquid or solid absorbents or membrane
separators.
Acid gas removal vent emissions mean the acid gas separated from the acid gas
absorbing medium (e.g., an amine solution) and released with methane and other light
hydrocarbons to the atmosphere or a flare.
Air injected flare means a flare in which air is blown into the base of a flare stack to
induce complete combustion of gas.
Basin means geologic provinces as defined by the American Association of
Petroleum Geologists (AAPG) Geologic Note: AAPG-CSD Geologic Provinces Code Map:
AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr.,
Volume 75, Number 10 (October 1991) (incorporated by reference, see §98.7) and the
Alaska Geological Province Boundary Map, Compiled by the American Association of
Petroleum Geologists Committee on Statistics of Drilling in Cooperation with the USGS,
1978 (incorporated by reference, see §98.7).
Blowdown vent stack emissions mean natural gas and/or CO2 released due to
maintenance and/or blowdown operations including compressor blowdown and emergency
shut-down (ESD) system testing.
Calibrated bag means a flexible, non-elastic, anti-static bag of a calibrated volume
that can be affixed to an emitting source such that the emissions inflate the bag to its
calibrated volume.
Centrifugal compressor means any equipment that increases the pressure of a process
natural gas or C02 by centrifugal action, employing rotating movement of the driven shaft.
Centrifugal compressor dry seals mean a series of rings around the compressor shaft
where it exits the compressor case that operates mechanically under the opposing forces to
prevent natural gas or CO2 from escaping to the atmosphere.
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Centrifugal compressor dry seal emissions mean natural gas or CO2 released from a
dry seal vent pipe and/or the seal face around the rotating shaft where it exits one or both
ends of the compressor case.
Centrifugal compressor wet seal degassing vent emissions means emissions that occur
when the high-pressure oil barriers for centrifugal compressors are depressurized to release
absorbed natural gas or CO2. High-pressure oil is used as a barrier against escaping gas in
centrifugal compressor shafts. Very little gas escapes through the oil barrier, but under high
pressure, considerably more gas is absorbed by the oil. The seal oil is purged of the absorbed
gas (using heaters, flash tanks, and degassing techniques) and recirculated. The separated
gas is commonly vented to the atmosphere.
Component means each metal to metal joint or seal of non-welded connection
separated by a compression gasket, screwed thread (with or without thread sealing
compound), metal to metal compression, or fluid barrier through which natural gas or liquid
can escape to the atmosphere.
Continuous bleed means a continuous flow of pneumatic supply gas to the process
measurement device (e.g. level control, temperature control, pressure control) where the
supply gas pressure is modulated by the process condition, and then flows to the valve
controller where the signal is compared with the process set-point to adjust gas pressure in
the valve actuator.
Compressor means any machine for raising the pressure of a natural gas or C02 by
drawing in low pressure natural gas or CO2 and discharging significantly higher pressure
natural gas or C02.
Condensate means hydrocarbon and other liquid, including both water and
hydrocarbon liquids, separated from natural gas that condenses due to changes in the
temperature, pressure, or both, and remains liquid at storage conditions.
Dehydrator means a device in which a liquid absorbent (including desiccant, ethylene
glycol, diethylene glycol, or triethylene glycol) directly contacts a natural gas stream to
absorb water vapor.
Dehydrator vent emissions means natural gas and CO2 released from a natural gas
dehydrator system absorbent (typically glycol) reboiler or regenerator to the atmosphere or a
flare, including stripping natural gas and motive natural gas used in absorbent circulation
pumps.
De-methanizer means the natural gas processing unit that separates methane rich
residue gas from the heavier hydrocarbons (e.g., ethane, propane, butane, pentane-plus) in
feed natural gas stream.
Desiccant means a material used in solid-bed dehydrators to remove water from raw
natural gas by adsorption or absorption. Desiccants include activated alumina, pelletized
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calcium chloride, lithium chloride and granular silica gel material. Wet natural gas is passed
through a bed of the granular or pelletized solid adsorbent or absorbent in these dehydrators.
As the wet gas contacts the surface of the particles of desiccant material, water is adsorbed
on the surface or absorbed and dissolves the surface of these desiccant particles. Passing
through the entire desiccant bed, almost all of the water is adsorbed onto or absorbed into the
desiccant material, leaving the dry gas to exit the contactor.
Engineering estimation means an estimate of emissions based on engineering
principles applied to measured and/or approximated physical parameters such as dimensions
of containment, actual pressures, actual temperatures, and compositions.
Enhanced oil recovery (EOR) means the use of certain methods such as water
flooding or gas injection into existing wells to increase the recovery of crude oil from a
reservoir. In the context of this subpart, EOR applies to injection of critical phase or
immiscible carbon dioxide into a crude oil reservoir to enhance the recovery of oil.
Equipment leak means those emissions which could not reasonably pass through a
stack, chimney, vent, or other functionally-equivalent opening.
Equipment leak detection means the process of identifying emissions from
equipment, components, and other point sources.
External combustion means fired combustion in which the flame and products of
combustion are separated from contact with the process fluid to which the energy is
delivered. Process fluids may be air, hot water, or hydrocarbons. External combustion
equipment may include fired heaters, industrial boilers, and commercial and domestic
combustion units.
Natural gas distribution facility means the collection of all distribution pipelines,
metering stations, and regulating stations that are operated by a Local Distribution Company
(LDC) that is regulated as a separate operating company by a public utility commission or
that are operated as an independent municipally-owned distribution system.
Onshore petroleum and natural gas production facility means all petroleum or natural
gas equipment on a well pad or associated with a well pad and CO2 EOR operations that are
under common ownership or common control including leased, rented, or contracted
activities by an onshore petroleum and natural gas production owner or operator and that are
located in a single hydrocarbon basin as defined in §98.238. Where a person or entity owns
or operates more than one well in a basin, then all onshore petroleum and natural gas
production equipment associated with all wells that the person or entity owns or operates in
the basin would be considered one facility.
Farm Taps are pressure regulation stations that deliver gas directly from transmission
pipelines to generally rural customers. The gas may or may not be metered, but always does
not pass through a city gate station. In some cases a nearby LDC may handle the billing of
the gas to the customer(s).
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Field means oil and gas fields identified in the United States as defined by the Energy
Information Administration Oil and Gas Field Code Master List 2008, DOE/EIA 0370(08)
(incorporated by reference, see §98.7).
Flare stack emissions means C02 and N20 from partial combustion of hydrocarbon
gas sent to a flare plus CH4 emissions resulting from the incomplete combustion of
hydrocarbon gas in flares.
Flare combustion efficiency means the fraction of hydrocarbon gas, on a volume or
mole basis, that is combusted at the flare burner tip.
Gas conditions mean the actual temperature, volume, and pressure of a gas sample.
Gas to oil ratio (GOR) means the ratio of the volume of gas at standard temperature
and pressure that is produced from a volume of oil when depressurized to standard
temperature and pressure.
Gas well means a well completed for production of natural gas from one or more gas
zones or reservoirs. Such wells contain no completions for the production of crude oil.
High-bleed pneumatic devices are automated, continuous bleed flow control devices
powered by pressurized natural gas and used for maintaining a process condition such as
liquid level, pressure, delta-pressure and temperature. Part of the gas power stream that is
regulated by the process condition flows to a valve actuator controller where it vents
continuously (bleeds) to the atmosphere at a rate in excess of 6 standard cubic feet per hour.
Intermittent bleed pneumatic devices mean automated flow control devices powered
by pressurized natural gas and used for maintaining a process condition such as liquid level,
pressure, delta-pressure and temperature. These are snap-acting or throttling devices that
discharge the full volume of the actuator intermittently when control action is necessary, but
does not bleed continuously.
Internal combustion means the combustion of a fuel that occurs with an oxidizer
(usually air) in a combustion chamber. In an internal combustion engine the expansion of the
high-temperature and -pressure gases produced by combustion applies direct force to a
component of the engine, such as pistons, turbine blades, or a nozzle. This force moves the
component over a distance, generating useful mechanical energy. Internal combustion
equipment may include gasoline and diesel industrial engines, natural gas-fired reciprocating
engines, and gas turbines.
Liquefied natural gas (LNG) means natural gas (primarily methane) that has been
liquefied by reducing its temperature to -260 degrees Fahrenheit at atmospheric pressure.
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LNG boil-off gas means natural gas in the gaseous phase that vents from LNG
storage tanks due to ambient heat leakage through the tank insulation and heat energy
dissipated in the LNG by internal pumps.
Low-bleed pneumatic devices mean automated flow control devices powered by
pressurized natural gas and used for maintaining a process condition such as liquid level,
pressure, delta-pressure and temperature. Part of the gas power stream that is regulated by
the process condition flows to a valve actuator controller where it vents continuously (bleeds)
to the atmosphere at a rate equal to or less than six standard cubic feet per hour.
Natural gas driven pneumatic pump means a pump that uses pressurized natural gas
to move a piston or diaphragm, which pumps liquids on the opposite side of the piston or
diaphragm.
Offshore means 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.
Oil well means a well completed for the production of crude oil from at least one oil
zone or reservoir.
Onshore petroleum and natural gas production owner or operator means the person or
entity who holds the permit to operate petroleum and natural gas wells on the drilling permit
or an operating permit where no drilling permit is issued, which operates an onshore
petroleum and/or natural gas production facility (as described in §98.230(a)(2). Where
petroleum and natural gas wells operate without a drilling or operating permit, the person or
entity that pays the State or Federal business income taxes is considered the owner or
operator.
Operating pressure means the containment pressure that characterizes the normal state
of gas or liquid inside a particular process, pipeline, vessel or tank.
Pump means a device used to raise pressure, drive, or increase flow of liquid streams
in closed or open conduits.
Pump seals means any seal on a pump drive shaft used to keep methane and/or carbon
dioxide containing light liquids from escaping the inside of a pump case to the atmosphere.
Pump seal emissions means hydrocarbon gas released from the seal face between the
pump internal chamber and the atmosphere.
Reciprocating compressor means a piece of equipment that increases the pressure of a
process natural gas or CO2 by positive displacement, employing linear movement of a shaft
driving a piston in a cylinder.
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Reciprocating compressor rod packing means a series of flexible rings in machined
metal cups that fit around the reciprocating compressor piston rod to create a seal limiting the
amount of compressed natural gas or CO2 that escapes to the atmosphere.
Re-condenser means heat exchangers that cool compressed boil-off gas to a
temperature that will condense natural gas to a liquid.
Reservoir means a porous and permeable underground natural formation containing
significant quantities of hydrocarbon liquids and/or gases.
Residue Gas and Residue Gas Compression mean, respectively, production lease
natural gas from which gas liquid products and, in some cases, non-hydrocarbon components
have been extracted such that it meets the specifications set by a pipeline transmission
company, and/or a distribution company; and the compressors operated by the processing
facility, whether inside the processing facility boundary fence or outside the fence-line, that
deliver the residue gas from the processing facility to a transmission pipeline.
Sales oil means produced crude oil or condensate measured at the production lease
automatic custody transfer (LACT) meter or custody transfer tank gauge.
Separator means a vessel in which streams of multiple phases are gravity separated
into individual streams of single phase.
Sour natural gas means natural gas that contains significant concentrations of
hydrogen sulfide (H2S) and/or carbon dioxide (CO2) that exceed the concentrations specified
for commercially saleable natural gas delivered from transmission and distribution pipelines.
Sweet Gas is natural gas with low concentrations of hydrogen sulfide (H2S) and/or
carbon dioxide (CO2) that does not require (or has already had) acid gas treatment to meet
pipeline corrosion-prevention specifications for transmission and distribution.
Transmission pipeline means high pressure cross country pipeline transporting
saleable quality natural gas from production or natural gas processing to natural gas
distribution pressure let-down, metering, regulating stations where the natural gas is typically
odorized before delivery to customers.
Turbine meter means a flow meter in which a gas or liquid flow rate through the
calibrated tube spins a turbine from which the spin rate is detected and calibrated to measure
the fluid flow rate.
United States means the 50 States, the District of Columbia, the Commonwealth of
Puerto Rico, American Samoa, the Virgin Islands, Guam, and any other Commonwealth,
territory or possession of the United States, as well as the territorial sea as defined by
Presidential Proclamation No. 5928.
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Vapor recovery system means any equipment located at the source of potential gas
emissions to the atmosphere or to a flare, that is composed of piping, connections, and, if
necessary, flow-inducing devices, and that is used for routing the gas back into the process as
a product and/or fuel.
Vaporization unit means a process unit that performs controlled heat input to vaporize
LNGto supply transmission and distribution pipelines or consumers with natural gas.
Vented emissions means intentional or designed releases of CH4 or CO2 containing
natural gas or hydrocarbon gas (not including stationary combustion flue gas), including
process designed flow to the atmosphere through seals or vent pipes, equipment blowdown
for maintenance, and direct venting of gas used to power equipment (such as pneumatic
devices).
Well completions means the process that allows for the flow of petroleum or natural
gas from newly drilled wells to expel drilling and reservoir fluids and test the reservoir flow
characteristics, steps which may vent produced gas to the atmosphere via an open pit or tank.
Well completion also involves connecting the well bore to the reservoir, which may include
treating the formation or installing tubing, packer(s), or lifting equipment, steps that do not
significantly vent natural gas to the atmosphere. This process may also include high-rate
flowback of injected gas, water, oil, and proppant used to fracture or re-fracture and prop
open new fractures in existing lower permeability gas reservoirs, steps that may vent large
quantities of produced gas to the atmosphere.
Well workover means the process(es) of performing one or more of a variety of
remedial operations on producing petroleum and natural gas wells to try to increase
production. This process also includes high-rate flowback of injected gas, water, oil, and
proppant used to re-fracture and prop-open new fractures in existing low permeability gas
reservoirs, steps that may vent large quantities of produced gas to the atmosphere.
Wellhead means the piping, casing, tubing and connected valves protruding above the
earth's surface for an oil and/or natural gas well. The wellhead ends where the flow line
connects to a wellhead valve. Wellhead equipment includes all equipment, permanent and
portable, located on the improved land area (i.e. well pad) surrounding one or multiple
wellheads.
Wet natural gas means natural gas in which water vapor exceeds the concentration
specified for commercially saleable natural gas delivered from transmission and distribution
pipelines. This input stream to a natural gas dehydrator is referred to as "wet gas."
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Appendix I: References
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Guidelines for the Natural Gas Distribution Sector.
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Oil and Gas Industry.
.
API. (2007) Summary of Carbon Dioxide Enhanced Oil Recovery (C02E0R) Injection Well
Technology.
Bacharach, Inc. (2005) HiFlow® Sampler Natural Gas Leak Rate Measurement: Instruction
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Bureau of Economic Analysis (2007) Table 1.1.9. Implicit Price Deflators for Gross
Domestic Product. .
Bylin, Carey (EPA), et. al (2009) Methane's Role in Promoting Sustainable Development in
Oil and Natural Gas Industry.
California Environmental Protection Agency (2007) Rulemaking to Consider Adoption of a
Regulation for the Mandatory Reporting of Greenhouse Gas Emissions.
.
CCAR (2007) General Reporting Protocol. .
The Climate Registry (2007) General Reporting Protocol for the Voluntary Reporting
Program. < http://www.theclimateregistry.org/>.
DOE/ NETL (2009). Electricity Use of Enhanced Oil Recovery with Carbon Dioxide (CO 2-
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EOR.pdf>
DOE/ NETL (2008). Storing C02 with Enhanced Oil Recovery. DOE/NETL-402/1312/02-
07-08
EIA (2006) Underground Storage Field Level Data From EIA-191A.
.
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EIA (2008) Official Energy Statistics from the U.S. Government Glossary.
.
Emery, Brian et al. Do oil and gas platforms off California reduce recruitment of bocaccio
(Sebastes paucispinis) to natural habitat? An analysis based on trajectories derivedfrom
high .frequency radar<
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EPRI (1999). Enhanced Recovery Scoping Study.
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GRI (1992) GRI Report, Methane Emissions from the Natural Gas Industry, Volumes 1- 15.
Energy Information Agency (U.S. DOE)
EU ETS (2004) Establishing Guidelines for the Monitoring and Reporting of Greenhouse
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lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2004:059:0001:0074:EN:PDF>.
FERC (2008) ExistingLNG Terminals, .
FLIR (2006) ThermaCAM® GasFindIR™ Brochure.
.
GOADS (2000). Gulfwide Offshore Activity Data System.
GRI (1992) GRI Report, Methane Emissions from the Natural Gas Industry, Volumes 1- 15.
Energy Information Agency (U.S. DOE)
GRI (2008) GRI-GLYCalc™ Software Program.
.
GTI (1999), Gas Resource Database: Unconventional Natural Gas and Gas Composition
Databases, 2nd Edition CD-ROM
GTI(2007) The World Energy Source Book - Fourth Edition, An Encyclopedia of the World
LNG Industry, GTI 07/0002
INGAA (2008) Greenhouse Gas Emissions Estimation Guidelines for Natural Gas
Transmission and Storage, Volume 1. .
IPCC (2006) 2006IPCC Guidelines for National Greenhouse Gas Inventories.
.
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IPIECA (2003) Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions.
.
Lasser Production Data, Version 3.0.8
MMS (2000) Goads Summary Access File "Final GOADS Emissions Summaries".
.
NESHAP (accessed 2008) 40 CRF Part 63.
.
OGJ (2006) Worldwide Gas Processing Survey.
OGJ (2006) EOR/Heavy Oil Survey.
OGJ (2007) Worldwide Gas Processing Survey,
New England Governors and Eastern Canadian Premiers (2003) Resolution Concerning
Environmental Projects Issues, .
New Mexico State (2008) New Mexico Green House Gas Mandatory Emissions Inventory
Emissions Quantification Procedures.
.
OPS (2006) Transmission Annuals Data. .
Spring, P.S., R.H. Hugman, and E.H. Vidas, (1999) Unconventional Gas Field, Reservoir,
and Completion Analysis of the Continental United States - 1998 Update. Gas Research
Institute, Contract 5097-210-4018
TCEQ (2009) Upstream Oil and Gas Storage Tank Project Flash Emissions Models
Evaluations. Texas Commission on Environmental Quality, Air Quality Division. TX: 1-73.
TERC (2009) VOC Emissions from Oil and Condensate Storage Tanks. Texas Environmental
Research Consortium. The Woodlands, TX: 1-34 Available online at:
U.S. Department of Labor, Bureau of Labor Statistics National Compensation Survey -
Compensation Cost Trends, Employer Cost for Employee Compensation (ECEC),
Customized Tables
U.S. EPA (2002) Analytical Support Branch, Environmental Analysis Division, Office of
Environmental Information Wage Rates for Economic Analyses of the Toxics Release
Inventory Program.
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