FUGITIVE EMISSIONS REPORTING FROM THE
PETROLEUM AND NATURAL GAS INDUSTRY
BACKGROUND TECHNICAL SUPPORT DOCUMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
CLIMATE CHANGE DIVISION
WASHINGTON DC
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TABLE OF CONTENTS
(A) Description of Emissions Sources 4
(1) Segments in the Petroleum and Natural Gas Industry 4
(2 ) Types of Fugitive Emissions Sources and GHGs 6
(a) Combustion-related emissions 6
(b) Fugitive emissions: 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 Mandatory GHG Reporting Rule 7
(a) Review of Existing Regulations 8
(b) Review of Existing Programs 9
(c) Selection of Emissions Sources for Reporting 14
(i) Facility Definition Characterization 14
(i i) Selection of Potential Emissions Sources for Reporting 15
(i i i) Address Sources with Large Uncertainties 18
(i v) Identify Sources to be Included 18
(B) Options for Reporting Threshold 22
(1) Threshold Analysis 23
(C) Monitoring Method Options 25
(1) Review of Existing Relevant Reporting Programs/ Methodologies 25
(2 ) Potential Monitoring Instruments 25
(a) Fugitive Emissions Detection 25
(b) Fugitive Emissions Measurement 26
(c) Engineering Estimation 28
(3) Potential Monitoring Methods 28
(a) Direct Measurement 29
(b) Engineering Estimation 33
(c) Combination of Direct Measurement and Engineering Estimation 37
(d) Method 21 40
(e) Activity Factor and Emissions Factor for All Sources 40
( f) TV As/ OVAs for Leak Measurement 41
(4) Additional Questions Regarding Potential Monitoring Methods 41
(a) Source Level Fugitive Emissions Detection Threshold 41
(i) Instrument Performance Standards 42
(i i) Fugitive Emissions Definition 43
(b) Duration of Fugitive Emissions 43
(c) Unofficial Surveys 43
(d) Fugitive Emissions at Different Operational Modes 43
(e) Natural Gas Composition 44
(f) Physical Access for Leak Measurement 44
(D) Procedures for Estimating Missing Data 45
(E) QA/QC Requirements 46
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(F) Reporting Procedure 48
(G) Verification of Reported Emissions 49
APPENDIX A: Segregation of Emissions Sources using the Decision Process 50
APPENDIX B: Glossary 55
APPENDIX C: References 66
LIST OF TABLES
Table 1: Summary of Regulations Related to the Petroleum and Gas Industry 8
Table 2: Summary of Program and Guidance Documents on GHG Emissions Monitoring
and Reporting 10
Table 3: Segment Specific Facility Definition 21
Table 4: Threshold Analysis for the Oil and Gas Industry Segments 24
Table 5: Source Specific Monitoring Methods and Emissions Quantification 28
LIST OF FIGURES
Figure 1: Decision Process for Emissions Source Selection 17
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(A) Description of Emissions Sources
(1) Segments in the Petroleum and Natural Gas Industry
The U.S. petroleum and natural gas industry encompasses the production of raw gas from
wells to the delivery of processed gas to consumers. These steps, and everything in between,
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; and
• Natural Gas Industry -natural gas production, natural gas processing (including
gathering and boosting), natural gas transmission and underground storage, and
natural gas distribution.
Each industry segment uses common processes and equipment in its facilities, all of which
can be related to GHG emissions. Each of these industry segments is described in further
detail below.
Petroleum Industry
Petroleum Production. Petroleum or crude oil is produced from underground 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 fugitive emissions. Equipment counts and GHG gas emitting practices are related to the
number of producing crude oil wells and their production rates.
Petroleum Transportation. The stored crude oil at production sites is either pumped into
crude oil transportation pipelines or loaded onto tankers and/or rail freight. Along the way
the crude oil may be stored several times in tanks. These practices and storage tanks release
fugitive GHG emissions, as well as emissions from combustion. Emissions are related to the
amount of crude oil transported and transportation type.
Petroleum Refining. Crude oil is delivered to refineries where it is temporarily stored before
it is fractionated by distillation, treated, and the fractions are reformed or cracked to be
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 of and complexity at refineries.
Natural Gas Industry
Natural Gas Production. For natural gas production, wells are used to withdraw raw gas
from underground formations. First wells must be drilled to access the underground
formations, and often require natural gas well completion or other practices that vent gas
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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 it is directed into pipelines to the next segment. Combustion and fugitive
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 (including Gathering/Boosting stations). In this segment, natural
gas from the petroleum and natural gas production segment is compressed and injected into
gathering lines that transport it to natural gas processing facilities. 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. All equipment
and practices have associated GHG fugitive emissions, energy consumption related
combustion GHG emissions, and/or process control related GHG 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 long distances 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, which contain large reciprocating and turbine compressors, are used to move the
gas throughout the United States 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 liquefied as liquefied
natural gas (LNG) and stored in above ground storage tanks during periods of low demand
(e.g., spring or fall), and withdrawn, processed, and distributed during periods of high
demand (e.g., winter and summer). Compressors 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 LNG also requires transportation and storage. These processes are similar to above
ground LNG storage and require compression and cooling processes. GHG emissions in this
segment are related to the number of LNG import terminals and LNG storage facilities.
Further details are provided on the individual sources of GHG emissions for all of
transmission and storage in the Appendix A.
Natural Gas Distribution. Natural gas distribution pipelines take the 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. Between the distribution mains and many offshooting services are underground
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regulating vaults. 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 length of pipelines.
Further details are provided on the individual sources of GHG emissions in the Appendix A.
(2) Types of Fugitive Emissions Sources and GHGs
The three main GHGs that are relevant to the petroleum and gas industry are CH4, CO2, and
N2O. Of these CH4 and CO2 are naturally found in produced natural gas and petroleum,
whereas CO2, CH4andN20 are a result of various combustion processes. Therefore, CH4 and
CO2 emissions are a result of both fugitive and combustion emissions, whereas N2O is a
result of combustion emissions only. This technical document will focus mainly on CH4 and
CO2 emissions from fugitive emissions. However, all three gases will be 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:
(a) Combustion-related emissions:
Combustion-related emissions result from the use of petroleum 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 rarely 100 percent efficient, CH4 and N2O may also be
emitted. For methodologies to quantify GHG emissions from combustion, please
refer to the Background Technical Support Document (EPA-HQ-OAR-2008-0508-
004).
(b) Fugitive 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 some amount 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 natural gas
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. This document refers to both unintentional emissions and
intentional emissions together as fugitive emissions; hereafter referred to as
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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"fugitive emissions" or "emissions". This document includes methodologies to
quantify fugitive emissions of CO2 and CH4.
(3) GHG Emissions from the Petroleum and Natural Gas Industry
Fugitive CH4 and CO2 emissions from the petroleum and natural gas industry were 159.6
million metric tons of CO2 equivalent (MMTC02e) in 2006. Overall, the natural gas industry
emitted 102.4 MMTC02e of CH4 and 28.5 MMTC02e of C02 in 2006. Total CH4 and C02
emissions from the petroleum industry in 2006 were 28.4 MMTC02e and 0.3 MMTC02e
respectively.
Petroleum Segment
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 United States currently estimates C02 emissions from crude oil
production operations only in the U.S. GHG Inventory. Research is underway to include
other larger sources of fugitive C02 emissions in future inventories.
Natural Gas Segment
Emissions from natural gas production accounted for approximately 27 percent of CH4
emissions and about 25 percent of non-energy C02 emissions from the natural gas industry in
2006. Processing facilities accounted for about 12 percent of CH4 emissions and
approximately 74 percent of fugitive C02 emissions from the natural gas industry. CH4
emissions from the natural gas transmission and storage segment accounted for
approximately 37 percent of emissions, while C02 emissions from natural gas transmission
and storage accounted for less than 1 percent of the C02 emissions from the natural gas
industry. Natural gas distribution segment emissions, which account for approximately 24
percent of CH4 emissions from natural gas systems and less than 1 percent of C02 emissions,
result mainly from fugitive emissions from gate stations and pipelines.
(4) Methodology for Selection of Industry Segments and Emissions Sources Feasible
for Inclusion in a Mandatory GHG Reporting Rule
It is important to develop criteria to help identify those emissions sources in the petroleum
and natural gas industry most likely to be of interest to policymakers from a GHG emissions
perspective. To identify sources for potential inclusion in the proposed 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 amenable to inclusion in a mandatory 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.
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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 helped in
avoiding any missing emissions sources already being monitored for reporting under other
program(s). Both of these steps are described below.
(a) Review of Existing Regulations
The first step was to understand existing regulations and consider adapting elements of the
existing regulations to a mandatory reporting rule for GHG emissions. At this time, there are
two 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. Table 1 provides a summary of each of these six
regulations.
Table 1: Summary of Regulations Related to 1
he Petroleum and Natural Gas Industry
Ri'liiihilion
Tj |>C
Point/ Ami/
Mobile
Source
(j;iscs ( o\crcd
Segment iiud Sources
LPA 4U OR Pari 51
Consolidated
Emissions Reporting
Lniis>s>ioiis>
Reporting
Poinl, Area.
Mobile,
Biogenic
\ UCb, \Ov
CO, nh3, pm10,
pm25
All sjcgnienb of llie
petroleum and gas industry
DOE 10 CFR Part 300
- Voluntary GHG
Reporting
Voluntary
GHG
Reporting
Point, Area,
Mobile
co2, ch4, n2o,
HFCs, PFCs,,
SF6, and CFCs
All segments of the
petroleum and gas industry
EPA 40 CFR Part 60,
Subpart KKK
Standards of
Performance
Point
VOCs
Onshore processing plants;
sources include compressor
station, dehydration unit,
sweetening unit,
underground storage tank,
field gas gathering system,
or liquefied natural gas unit
located in the plant
EPA 40 CFR Part 60,
Subpart LLL
Standards of
Performance
Point
S02
Onshore processing plants;
Sweetening unit, and
sweetening unit followed by
a sulfur recovery unit
EPA 40 CFR Part 63 -
NESHAP1 - RIN
2060-AE34
MACT3
Point (Glycol
dehydrators,
natural gas
transmission
and storage
facilities)
HAPs
Glycol dehydrators
EPA 40 CFR Part 63 -
NESHAP1 - RIN
2060-AM16
MACT3
Point and Area
(petroleum and
gas
production, up
to and
including
processing
plants)
HAPs
Point Source - Glycol
dehydrators and tanks in
petroleum and gas
production; equipment leaks
at gas processing plants
Area Source - Triethylene
glycol (TEG) dehydrators in
petroleum and gas
production
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EPA 40 CFR Part 63 -
NESHAP1 - RIN 2060
AG-67
MACT3
Point
(Stationary
Combustion
Turbine)
HAPs
All segments of the
petroleum and gas industry
EPA 40 CFR Part 63 -
NESHAP1 - RIN 2060
AG-63
MACT3
Point
(Reciprocating
Internal
Combustion
Engines)
HAPs
All segments of the
petroleum and gas industry
Notes:
National Emission Standards for Hazardous Air Pollutants
2New Source Performance Standard
3Maximum Allowable Control Technology
From Table 1, it can be observed that only DOE 10 CFR Part 300 includes the monitoring or
reporting of CH4 emissions (or other GHGs). 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 regulations do not require any monitoring of emissions. Hence
there is no reporting of emissions, only reductions. This review of existing regulations
concludes that fugitive GHG emissions from oil and gas operations are not systematically
monitored and reported; therefore these regulations and programs can not serve as the
foundation for a mandatory reporting rule.
(b) Review of Existing Programs
The second step was to review existing monitoring and reporting programs to identify all
emissions sources that are already monitored under these programs. At this time, there are six
reporting programs and six guidance documents that were reviewed. Table 2 provides a
summary of the points of monitoring identified by the programs and guidance documents.
Table 2 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 a list of emissions sources as a starting point for determining the
emissions sources that can be potentially included in the proposed rule.
The preliminary review exercise 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 oil and gas
industry was then undertaken to identify the specific emissions sources (e.g., equipment or
component) that are of greatest interest for inclusion in a mandatory GHG reporting rule.
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Table 2: 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 fugitives, 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 fugitives, 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
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and other emission factors
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 -
Transmission/Sto
rage
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 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
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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 - Production
voc
Gas and oil wells
Equipment and process emissions rates
Emissions are quantified by calculation based method
using emission factors and activity factors. Methods
used are specified in chapter 2
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
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(c) Selection of Emissions Sources for Reporting
A key challenge in identifying emissions sources for inclusion in a mandatory reporting rule
is answering two related questions. The first is defining a facility. In other words, physically
what constitutes a facility? The second is determining which sources of emissions should a
facility report? It is difficult to include or exclude sources from a mandatory reporting rule
without knowing the definition of a facility. Therefore, to resolve this interdependence, both
the facility definition and emissions source inclusion (or exclusion) was studied
independently and finally reviewed together 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 control of the same person
(or persons under common control). This definition can be easily applied to onshore natural
gas processing and petroleum refining facilities since the operations are all located in a
clearly defined boundary. Onshore natural gas transmission stations also can be clearly
identified using this definition. However, this definition does not easily lend itself to onshore
petroleum and natural gas production, onshore natural gas transmission pipelines and natural
gas distribution, and the petroleum transportation segments of the industry.
Petroleum and natural gas production facilities can be very diverse in arrangement.
Sometimes crude oil and natural gas producing wellheads are far apart with individual
equipment at each wellhead. At other times several wells in close vicinity are connected to
common pieces of equipment. The choice of whether multiple wells are connected to
common 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,
finding a single definition of a facility that can be applied to all of onshore petroleum and
natural gas production can be challenging. In addition there are several hydrocarbon resource
ownership and operational equipment ownership issues relating to the onshore petroleum and
natural gas production segment. In many cases the mineral rights are not necessarily owned
by the land owner. This is prevalent mostly in the western half of the United States where the
Bureau of Land Management owns major portions of the minerals rights whereas the lands
are held by private owners. Also, in many cases multiple operators operate in a single
production operation. For example, in some cases in the onshore production segment,
multiple operators are responsible for different equipment in the same field under different
ownership. Such cases of multiple owner/ operators further complicate assigning
responsibilities of facilities for emissions reporting.
Natural gas transmission and petroleum transportation pipelines run over several hundred
thousand miles in the United States. There are no identifiers (or markers) that can be used to
readily assign a portion of the pipelines as a single facility. Moreover, emissions sources in
pipelines are spread across large geographical areas making it difficult to use the common
definition available from the CAA. The natural gas distribution segment has issues similar to
the onshore natural gas transmission segment in defining facilities for the extensive pipeline
network. The meters and regulators in the distribution segment are mainly in small
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underground vaults in urban areas. Individually defining each vault as a facility is again
impractical owing to the size and expected magnitude of emissions from a single vault. It
may also not be immediately obvious to include multiple vaults to define a facility, as they
are not in a contiguous area.
(i i) Selection of Potential Emissions Sources for Reporting
Given that there are over 160 emissions sources in the petroleum and gas industry, it is
important to target those sources that contribute significantly to total emissions from the
industry nationally. This is to avoid unnecessary reporting burden on the industry, but at the
same time to enable maximum coverage for emissions reporting. The selection of emissions
sources for 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 like type and number of sources across industry segments
and 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 best practice for each emissions source. If
there is more than one monitoring method available, each of which is equivalent in
monitoring 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 could be
included. A discussion of the factors follows below.
• Contribution to U.S. GHG Inventory - Emissions sources that contribute significantly
large emissions nationally can be considered for potential inclusion in a rule, since they
increase the coverage of emissions reporting. Where emissions from a source were
greater than one percent of the total national emissions from the petroleum or natural gas
industry they were considered to be a significant source. The U.S. GHG Inventory
estimates emissions from the natural gas industry and petroleum industry separately. The
one percent significance refers to a percentage of emissions from each source to its
respective inventory total emissions. For example, a source in the natural gas industry is
significant if its national emissions are equal to or greater than one percent of total
fugitive emissions from all sources only in the natural gas industry.
• Emissions per Unit - There are some emissions sources that may not contribute
significantly to national emissions, but emissions per unit of activity for the source may
be large enough that even a one time occurrence could lead to significant emissions. For
example, emergency releases from equipment and vessels are not frequent nor are they
necessarily significant on a national level, but the one time emissions are significant.
Therefore, those sources with significant emissions per unit, i.e. over 100 Mcf/unit/year,
could be considered for inclusion in a reporting rule.
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• Best Practice Monitoring Method(s) - Depending on the types of monitoring method
typically undertaken, 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 sensors
can determine the flow rate and composition of exhaust gases from a combustion
process. On the other hand, fuel meters monitor the amount of fuel consumed in
combustion equipment that can be used to estimate the amount of emissions,
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 leaks 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 vessel that the emissions gas occupies,
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.
By utilizing the various factors that relate to selection of potential sources, a decision process
was developed to identify the potential sources that could be included in a reporting rule.
Figure 1 shows the resulting decision tree that includes these criteria and supported the
decision-making process.
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Figure 1: Decision Process for Emissions Source Selection
Background Technical Support Document - Petroleum and Natural Gas Industry 17
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The decision process provided in Figure 1 was applied to each emissions source in the
natural gas industry inventory and petroleum industry inventory. Only methane emissions
were taken into consideration for this exercise given that, for most sources, fugitive CO2
emissions are negligible in comparison to CH4 emissions from the same sources. The
emissions sources were then segregated into four categories; "definitely include", "probably
include", "consider including", and "exclude".
(i i i) Address Sources with Large Uncertainties
The natural gas and petroleum industry inventories are based on a U.S. EPA and Gas
Research Institute Study2 published in 1996. There are several estimates of emissions factors
for emissions sources that do not correctly reflect the operational practices of today. Hence in
some cases the estimates are under or over accounting the amount of emissions from these
sources. From anecdotal evidence from the industry, it is believed that emissions from some
sources may be much higher than currently reported in the U.S. GHG Inventory. In most
cases sufficient information is not publicly available to make changes to the estimates. In
other cases where public data are available, it is often incomplete and does not represent the
industry at a national level. The decision tree was not necessarily ideal for sources known to
be over- or underestimated in current inventories, which use existing emission factors.
Therefore, the decision tree was overridden for these sources. The sources added for
consideration under this exception are:
o Condensate and oil storage tanks
o Natural gas well workovers
o Natural gas well completions
o Natural gas well blowdowns,
o Flares
In addition, the U.S. GHG Inventory includes fugitive CH4 and CO2 emissions from natural
gas engines and turbines, 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 (EPA-HQ-OAR-2008-0508-004) and Petroleum Refineries (EPA-HQ-OAR-
2008-0508-025), respectively.
(iv) Identify Sources to be Included
Based on the understanding of facility definitions for each segment of the oil and gas
industry and the identification of potential sources for inclusion in a mandatory reporting
rule, the potential segments and sources to be included were identified. A brief analysis for
each segment is as follows;
¦ Onshore Petroleum and Natural Gas Production Segment - Onshore production
operations are a challenge for emissions reporting using the conventional facility
definition of a contiguous area under a common owner/ operator. This is because
2 U.S. Environmental Protection Agency/ Gas Research Institute, Methane Emissions from the Natural Gas
Industry, June 1996.
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multiple operators and equipment share the same operation. A possible solution to
this issue is to define a hydrocarbon producing basin as a facility and all operators
report their emissions on a basin level. In such a case, the company (or corporation)
operating in multiple fields in the same basin can report at the basin level. Reporting
of emissions from all potential emissions sources at a basin level will substantially
increase reporting burden. However, complexity of reporting requirements will
substantially be reduced if companies are reporting at basin level.
One way to reduce the reporting burden due to the large number of sources in the
production segment would be to focus on the largest contributors to GHG emissions.
From the EPA Natural Gas STAR experience in mitigating methane emissions in the
onshore oil and gas production segment, the major contributors to emissions from the
onshore production segment are easily identifiable. These emissions sources are not
reflected as major sources in the U.S. GHG Inventory as the inventory estimates are
based on a 1992 measurement study2 that, in the case of these sources, was
incomplete. Based on current knowledge of the petroleum and natural gas industry,
the following seven emissions sources are known to be the major contributors to the
total petroleum and natural gas production segment fugitive emissions; natural gas
driven pneumatic valve and pump devices, well completion releases and flaring, well
blowdowns, well workovers, crude oil and condensate storage tanks, dehydrator vent
stacks, and reciprocating compressor rod packing. With a basin level facility
definition, onshore production segment operators or companies could report
emissions from the seven major emissions sources listed above.
Other options, like defining a single wellhead as a facility or defining all equipment
from wellhead to compression as a facility is more challenging, as these options could
lead to complex reporting requirements. This also could significantly increase the
number of reporters to a program, and potentially raise implementation issues.
Onshore petroleum and natural gas production would seem to be 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, there are challenges that would
have to be overcome in defining what is a facility, and therefore, who is the reporter.
For some segments of the industry, identifying a facility is straightforward since there
are clear physical boundaries and ownership structures that lend themselves to
identifying the scope of reporting and responsible reporting entities (e.g., onshore
natural gas processing facilities, natural gas transmission compression facilities, and
offshore petroleum and natural gas facilities). This is not the case for onshore
petroleum and natural gas production and therefore defining a facility is possible but
more complex.
Given these complexities, this document does not include any further analysis on this
segment. However, this is an important area for additional research.
Offshore Petroleum and Natural Gas Production Segment - All of the production
activities offshore take place on platforms. These platforms can be grouped into two
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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 - There are two types of operations in the
processing segment of the natural gas industry; gathering/ boosting stations and
processing facilities. Gathering/ boosting stations typically collect gas from several
producing zones, dehydrate the natural gas and compress it for transportation to
onshore natural gas processing plants. Processing facilities further process the gas to
remove hydrogen sulfide (H2S) and/ or CO2 in the natural gas, if any, separate the
higher 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. Both gathering/ boosting stations and natural gas processing facilities have a
well defined boundary within which all processes take place, hence there is no
ambiguity in defining them as a facility. Monitoring in an onshore natural gas
processing facility entails leak detection and survey facility wide. Hence all emissions
sources in the processing plant could be monitored and included in a mandatory GHG
reporting rule, including associated gathering and boosting stations.
Onshore Natural Gas Transmission Segment - Transmission compressor stations are
easily identifiable as a facility with all compressors and related equipment confined to
a defined boundary. Hence, transmission compressor stations are viable candidates
for inclusion in a mandatory GHG reporting rule. However, inclusion of transmission
pipelines in a mandatory reporting rule would be challenging due to the difficulty in
defining pipelines as a facility and the spread of emissions sources over large
geographical areas.
Underground Natural Gas Storage, LNG Storage, and LNG Import Segments - All
operations in an underground natural gas storage facility (except wellheads), LNG
storage facility, and LNG import facility 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. Since a facility is clearly defined in each case, all three
segments could be included in a mandatory reporting rule.
Natural Gas Distribution Segment - The distribution segment meter and regulation
vaults are identifiable as a facility. However, the magnitude of emissions from a
single vault is not significant. Although vaults collectively contribute to a significant
share of emissions from the natural gas industry nationally, it may not be possible to
group multiple vaults as a single facility as they are not in a contiguous area. Also,
emissions from vaults and pipelines are usually quickly dealt with given the safety
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concerns in a gas distribution segment. This might not allow any time for monitoring
of leaks. These issues would likely have to be addressed before distribution segment
emissions sources could be included in a mandatory GHG reporting rule.
¦ 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. Moreover, petroleum pipelines
face the same problem in terms of facility definition as onshore natural gas
transmission pipelines.
Table 3 provides a list of each segment and a corresponding facility definition. It also
provides a listing of all sources that can be monitored and could be reported as part of a
mandatory GHG reporting rule.
Table 3: Segment Specific Facility Definition
Segment
Facility Definition
Potential Emissions
Sources for Inclusion
Offshore Petroleum
and Natural Gas
Production
Any platform structure, floating in the ocean,
fixed on ocean bed, or located on artificial
islands in the ocean, that houses equipment to
extract hydrocarbons from the ocean floor and
transports it to storage or transport vessels or
onshore. In addition, offshore production
facilities may include equipments for
separation of liquids from natural gas
components, dehydration of natural gas,
extraction of H2S and C02 from natural gas,
crude oil and condensate storage tanks, both
on the platform structure and floating storage
tanks connected to the platform structure by a
pipeline, and compression or pumping of
hydrocarbons to vessels or onshore. The
facilities under consideration are located in
both State administered waters and Mineral
Management Services administered Federal
waters.
Acid gas removal (AGR) vent
stacks, centrifugal compressor dry
seals, centrifugal compressor wet
seals, compressor fugitive
emissions, dehydrator vent stacks,
flare stacks, natural gas driven
pneumatic pumps, non-pneumatic
pumps, open-ended lines (OELs),
pump seals, offshore platform
pipeline fugitive emissions,
platform fugitive emissions,
natural gas driven pneumatic
manual valve actuator devices,
natural gas driven pneumatic valve
bleed devices, reciprocating
compressor rod packing, and
storage tanks.
Onshore Natural Gas
Processing
Any processing site engaged in the extraction
of natural gas liquids from produced natural
gas, which may also include fractionation of
mixed Natural Gas Liquids (NGL) to natural
gas products, removal of contaminants such as
carbon dioxide, sulfur compounds, nitrogen,
helium, and water. In addition, processing
facilities encompass gathering and boosting
stations that include equipment that separate
natural gas liquids from natural gas, dehydrate
the natural gas, and transport the natural gas to
transmission pipelines or to a processing
facility with fractionation equipment.
AGR vent stacks, blowdown vent
stacks, centrifugal compressor dry
seals, centrifugal compressor wet
seals, compressor fugitive
emissions, dehydrator vent stacks,
open-ended lines (OELs), natural
gas driven pneumatic manual valve
actuator devices, natural gas driven
pneumatic valve bleed devices,
processing facility fugitive
emissions, reciprocating
compressor rod packing, and
storage tanks.
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Onshore Natural Gas
Transmission
Any permanent combination of compressors
that move natural gas at increased pressure
from production fields or natural gas
processing facilities, in transmission pipelines,
to natural gas distribution pipelines, or into
storage facilities. In addition, transmission
compressor stations may include equipment
for liquids separation, natural gas dehydration,
and storage of water and hydrocarbon liquids.
Centrifugal compressor dry seals,
centrifugal compressor wet seals,
compressor fugitive emissions,
dehydrator vent stacks, OELs,
natural gas driven pneumatic
manual valve actuator devices,
natural gas driven pneumatic valve
bleed devices, reciprocating
compressor rod packing, storage
tanks, and transmission station
fugitive emissions.
Underground Natural
Gas Storage
Any subsurface facility utilized for storing
natural gas that has been transferred from its
original location for the primary purpose of
load balancing, which is the process of
equalizing the receipt and delivery of natural
gas. Processes and operations that may be
located at an underground storage facility
include, but are not limited to, compression,
dehydration and flow measurement. The
storage facility also includes all the wellheads
connected to the compression units located at
the facility.
Centrifugal compressor dry seals,
centrifugal compressor wet seals,
compressor fugitive emissions,
dehydrator vent stacks, OELs,
pump seals, natural gas driven
pneumatic manual valve actuator
devices, natural gas driven
pneumatic valve bleed devices,
reciprocating compressor rod
packing, storage tanks, storage
station fugitive emissions, and
storage wellhead fugitive
emissions.
LNG Storage Facilities
Any onshore facility that stores liquefied
natural gas in above ground storage vessels.
The facility may include equipment for
liquefying natural gas, compressors to liquefy
boil-off-gas, re-condensers, and vaporization
units for re-gasification of the liquefied
natural gas.
Centrifugal compressor dry seals,
centrifugal compressor wet seals,
compressor fugitive emissions,
OELs, LNG storage station
fugitive emissions, and
reciprocating compressor rod
packing.
LNG Import Facilities
Any onshore and/or offshore facilities that
receive imported liquefied natural gas, store it
in storage tanks, re-gasify it, and deliver re-
gasified natural gas to natural gas transmission
or distribution systems. The facilities include
tanker unloading equipment, liquefied natural
gas transportation pipelines, pumps,
compressors to liquefy boil-off-gas, re-
condensers, and vaporization units for re-
gasification of the liquefied natural gas.
Centrifugal compressor dry seals,
centrifugal compressor wet seals,
compressor fugitive emissions,
OELs, LNG storage station
fugitive emissions, and
reciprocating compressor rod
packing.
(B) 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
an individual facility; 1,000 metric tons of CO2 equivalent (mtCC^e) per year, 10,000
mtC02e, 25,000 mtCC^e, and 100,000 mtCC^e. A threshold analysis was then conducted on
each segment to determine which level of threshold was most suitable for each industry
segment. CH4, CO2, and N2O emissions from each segment were included in the threshold
analysis.
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(1) 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 fugitive CH4 and CO2
emissions, and combustion CH4, CO2, and N2O emissions. The fugitive emissions estimates
available from the U.S. GHG Inventory were used in the analysis. 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 CO2
emissions factor to the natural gas consumed as fuel. N2O 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.
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 offshore production the emissions reporting coverage is 31 percent and the
corresponding reporting facilities coverage is 0.2 percent for a threshold of 100,000mtCC)2e
per year. The incremental emissions and facilities coverage is 20 and 1.8 percent (51 percent
minus 31 percent and 2 percent minus 0.2 percent), respectively, for a 25,000 mtCC^e per
year threshold. However, at the next reporting threshold level of 10,000 mtCC^e per year the
incremental emissions and entities coverage is 16 and 4 percent, respectively. It can be seen
that the incremental coverage of emissions decreases but the coverage of facilities increases.
Table 4 provides the details of the threshold analysis at all threshold levels for the different
segments in the oil and gas industry.
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Table 4: Threshold Analysis for the Oil and Gas Industry Segments
l-'.missions Covered
l-'iicililies Covered
Process
('oml)iislion
1 Olill
Tol;il
Number
r.missions
CO.
r.missions
Threshold
Niilioiiiil
of
(inlCO'C/ve
r.missions
(Ions
Source C;ile$>orv
Level
Emissions
facilities
sir;
(iiil/veiir)
iiilC02e/v n
Perce il l
Nuuihcr
Perce ill
Offshore Petroleum and Natural
Gas Production Facilities
100,000
10.162.179
2,525
2,931,777
204.408
3.136.185
31%
4
0.2%
25,000
10.162.179
2,525
3.969.694
1.168.382
5.138.076
51%
50
2%
10,000
10.162.179
2,525
4.678.145
2.095.741
6,773,885
67%
156
6%
1,000
10.162.179
2,525
5.951.766
3,831,730
9.783.496
96%
1,021
40%
Onshore Natural Gas Processing
Facilities
100,000
50,211,548
566
21,581,714
17,459,840
39,041,555
78%
125
22%
25,000
50,211,548
566
26,006,801
21,493,174
47,499,976
95%
287
51%
10,000
50,211,548
566
27,113,211
21,094,641
49,207,852
98%
394
70%
1,000
50,211,548
566
28,038,416
22,173,132
50,211,548
100%
566
100%
Onshore Natural Gas
Transmission Facilities
100,000
73,198,355
1.944
1.589.418
11.833.992
30.200.243
41%
216
11%
25,000
73,198,355
1.944
4.749.993
36.032.206
63.835.288
87%
874
45%
10,000
73,198,355
1.944
5.480.135
41.670.038
71.359.167
97%
1,311
67%
1,000
73,198,355
1.944
5,682,533
43.163.746
73,177,039
100%
1,659
85%
Underground Natural Gas
Storage Facilities
100,000
11,719,044
398
3,262,598
2,003,351
5,265,948
45%
35
9%
25,000
11,719,044
398
6,120,836
3,758,410
9,879,247
84%
131
33%
10,000
11,719,044
398
6,800,178
4,175,550
10,975,728
94%
197
49%
1,000
11,719,044
398
7,250,309
4,451,947
11,702,256
100%
346
87%
LNG Storage Facilities
100,000
1.956.435
157
469.981
167.496
637,477
33%
3
2%
25,000
1.956.435
157
1.338.416
332.011
1,670,427
85%
29
18%
10,000
1.956.435
157
1.504.228
356,085
1.860.314
95%
39
25%
1,000
1.956.435
157
1.549.469
390,734
1.940.203
99%
54
34%
LNG Import Facilities
100,000
1,896,626
5
813,899
1,081,254
1,895,153
99.9%
4
80%
25,000
1,896,626
5
813,899
1,081,254
1,895,153
99.9%
4
80%
10,000
1,896,626
5
813,899
1,081,254
1,895,153
99.9%
4
80%
1,000
1,896,626
5
814,531
1,082,095
1,896,626
100%
5
100%
Note: Totals may not add exactly due to rounding.
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(C) Monitoring Method Options
(1) Review of Existing Relevant Reporting Programs/ Methodologies
To determine applicability of the different monitoring methods available, existing programs
and guidance documents were reviewed. Six reporting programs and six guidance documents
were reviewed. All of the program and guidance documents provide direction on estimating
CH4 and/ or CO2 emissions, except the Western Regional Air Partnership, which deals
exclusively with Volatile Organic Compound (VOC) 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. Table 2 provides a summary of the programs
and guidance documents reviewed.
(2) Potential Monitoring Instruments
Depending on the particular source to be monitored in a facility, several of the currently
available monitoring methods for estimating emissions could be used.
(a) Fugitive Emissions Detection
Traditional technologies like Toxic Vapor Analyzer (TVA) and 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
fugitive emissions detection technologies have emerged and are currently being used in
the United States and internationally to very efficiently detect leaks across large
facilities. Considering these factors, one of the following three technologies can be used
to detect leaks in facilities depending on suitability;
¦ Infrared Remote Fugitive Emissions Detectors - Hydrocarbons in natural
gas emissions absorb infrared light. The infrared remote fugitive emissions 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 fugitive emissions from a source,
and b) those that point or aim an IR beam towards a potential source to indicate
presence of fugitive emissions.
An IR camera scans a given area and converts it into a moving image of the area
while distinctly identifying the location where infrared has been absorbed, i.e. the
fugitive emissions source. The camera can actually "see" fugitive emissions. 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 is involves substantial
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 are 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
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the fugitive emissions. Such devices do not have screens to view the fugitive
emissions, 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 fugitive
emissions from a distance (i.e. the instrument need not be in close proximity to the
emissions). But they take more time for screening, 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.
¦ Toxic Vapor Analyzer (or Organic Vapor Analyzer) - TVAs and OVAs
consist of a flame ionization detector that is used to detect the presence of
hydrocarbon and measure the concentration of the fugitive emissions. 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, such emissions estimates are unreliable and therefore TVAs
and OVAs could be used where required 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.
(b) Fugitive Emissions Measurement
Three types of technologies can be used where appropriate to measure or quantify the
magnitude of fugitive emissions once they have been detected.
¦ High Volume Sampler - A high volume sampler consists of a simple fixed rate
induced flow sampling system to capture the fugitive emissions and measure its
volume. The fugitive emissions and the air surrounding the emissions source is
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.
¦ Meters - Several types of meters measure natural gas flows and can be used for
measurement of fugitive 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 fugitive 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
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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 fugitive 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 fugitive emissions that can be entirely captured and
directed through the meter.
Hotwire Anemometer - Hotwire anemometers measure fugitive emissions
velocity by noting the heat convected 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. Fugitive 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 differential that is converted to mass
emissions rate.
¦ Calibrated Bagging - A calibrated bag made of anti-static material is used to
enclose a fugitive 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 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.
All of the fugitive emissions measurement instruments discussed above measure the
flow rate of the natural gas emissions. In order to convert the natural gas emissions
into CO2 and CH4 emissions, speciation factors determined from natural gas
composition analysis must be applied. Another key issue is that all measurement
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technologies discussed require physical access to the emissions source in order to
quantify emissions.
(c) Engineering Estimation
Several emissions sources do not require physical measurement of the emissions
using a measurement instrument. For example, fugitive 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.
(3) Potential Monitoring Methods
Using the potential monitoring instruments discussed in the previous section, monitoring
methods can be of two types; Direct Measurement or Engineering Estimation. In direct
measurement the fugitive emissions detection and measurement can be used. For
engineering estimation, no detection is required, but the fugitive emissions can be
estimated using engineering methods. Table 5 provides potential monitoring methods and
emissions quantification methods. This section also discusses the use of Method 21 and
emission factor approaches to estimate emissions.
Table 5: Source Specific Monitoring Methods and Emissions Quantification
Emission
Source
Monitoring Method Type
Emissions Quantification
Methods
Acid Gas Removal Vent
Stacks
Engineering estimation
Simulation software
Blowdown Vent Stacks
Engineering estimation
Gas law and temperature,
pressure, and volume between
isolation valves
Centrifugal Compressor
Dry Seals
Direct measurement
1) High volume sampler
2) Calibrated bag
3) Meter
Centrifugal Compressor
Wet Seals
Direct measurement
1) High volume sampler
2) Calibrated bag
3) Meter
Compressor Fugitive
Emissions
Direct measurement
1) High volume sampler
2) Calibrated bag
3) Meter
Dehydrator Vent Stacks
Engineering estimation
Simulation software
Flare Stacks
Engineering estimation and
direct measurement
Velocity meter and
mass/volume equations
Natural Gas Driven
Pneumatic Pumps
1) Engineering estimation
2) or direct measurement
1) Manufacturer data,
equipment counts, and
amount of chemical pumped
2) Calibrated bag
Natural Gas Driven
Pneumatic Manual Valve
Actuator Devices
1) Engineering estimation
2) or direct measurement
1) Manufacturer data and
actuation logs
2) Calibrated bag
Natural Gas Driven
Pneumatic Valve Bleed
Devices
1) Engineering estimation
2) or direct measurement
1) Manufacturer data and
equipment counts
2) High volume sampler
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3) Calibrated bag
4) Meter
Non-pneumatic Pumps
Direct measurement
High volume sampler
Offshore Platform
Pipeline Fugitive
Emissions
Direct measurement
High volume sampler
Open-ended Lines (OELs)
Direct measurement
1) High volume sampler
2) Calibrated bag
3) Meter
Pump Seals
Direct measurement
1) High volume sampler
2) Calibrated bag
3) Meter
Facility Fugitive
Emissions1
Direct measurement
High volume sampler
Reciprocating
Compressor Rod Packing
Direct measurement
1) High volume sampler
2) Calibrated bag
3) Meter
Storage Tanks
1) Engineering estimation
and direct measurement
2) or engineering
estimation
1) Meter
2) Simulation software
3) Vasquez-Beggs Equation
The specific details on methods of monitoring for each approach is as follows.
(a) Direct Measurement
1. Detection
Infrared Remote Fugitive Emissions Detection
Method
Infrared remote (IR) fugitive emissions detection instruments can identify specific emissions
sources as emitting. Such instruments have the capability to trace a fugitive emission back to
the specific point where it escapes the process and enters the atmosphere. There are several
IR technology instruments that can detect the presence of a plume of emissions from a
facility or general operational area.
For IR instruments that visually display an image of fugitive emissions, 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.
Other IR detection instruments, such as those based on IR laser reflection, are tuned to detect
the interaction of methane and other organic compounds with infrared light in a wavelength
range where methane has strong absorption bands. However, they do not visually display an
image of the fugitive emissions. Such instruments will 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 fugitive emissions along its circumference and
such surfaces will have to be monitored completely by tracing the instrument along each
surface.
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Calibration
The minimum detectable quantity of fugitive emissions depends on a number of factors
including manufacturer, viewing distance, wind speed, gas composition, ambient
temperature, gas temperature, and type of background behind the fugitive emissions. For best
survey results, fugitive emissions detection can be performed under 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. Fugitive emissions detection and measurement instrument
manuals can be used to determine optimal operating conditions to help ensure best results.
OVAs and TVAs
Method
TVAs and OVAs can be used for all fugitive emissions 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 fugitive emission, 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.
2. Measurement
High Volume Sampler
High volume samplers are moderate cost and have a maximum capacity adequate to measure
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 likely most cost-effective
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 cold and steady emissions for
which the instrument can intake the entire emission 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 fugitive 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 from the source then anti-static wraps or other aids can to be used to
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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.
To estimate CH4 and CO2 volumetric and mass emissions from volumetric natural gas
emissions, the following calculations can be used:
~ Volumetric Fugitive Emissions
Volumetric CH4 and CO2 fugitive emissions from natural gas emissions can be calculated
using the following equation:
Es,i =Es,n*M, Equation 1
where,
ESJ = GHG i (either CH4 or CO2) volumetric fugitive emissions at standard conditions
Es>n = natural gas volumetric fugitive emissions at standard conditions
M; = mole percent of a particular GHG i in the natural gas applicable to each source category
as follows;
• Facility specific GHG mole percent in produced natural gas for offshore petroleum
and natural gas production facilities.
• Facility specific GHG mole percent in feed natural gas for all fugitive emissions
sources upstream of the de-methanizer and GHG mole percent in facility specific
residue gas to transmission pipeline systems for all fugitive emissions sources
downstream of the de-methanizer for onshore natural gas processing facilities.
• Facility specific GHG mole percent in transmission pipeline natural gas that passes
through the facility for onshore natural gas transmission compression facilities.
• Facility specific GHG mole percent in natural gas stored in underground natural gas
storage facilities.
• Facility specific GHG mole percent in natural gas stored in LNG storage facilities.
• Facility specific GHG mole percent in natural gas stored in LNG import facilities.
• Each facility for all of the source categories shall use an annual average GHG mole
percent in natural gas in estimating GHG fugitive emissions.
~Mass Fugitive Emissions
Mass GHG fugitive emissions at standard conditions can be calculated using the following
equation:
Masssi =Esj*pj Equation 2
where,
MasSs.i = GHG i (either CH4 or CO2) mass fugitive emissions at standard conditions
ESJ = GHG i (either CH4 or CO2) volumetric fugitive emissions at standard conditions
pi = density of GHG i; 1.87 kg/m3 for CO2 and 0.68 kg/m3 for CH4
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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.
Calibrated Bags
Calibrated bags are the lowest cost measurement technique, 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 fugitive 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 (also known as vent bags) can be used only where the emissions are at near-
atmospheric pressures and the entire fugitive 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.
Ambient temperature and pressure of natural gas fugitive emissions can be converted to
standard temperature and pressure natural gas fugitive emissions using the following
equation;
E *(460 + T)*P
7 1 a.n V s' a -m-y <->
E, „ = —: Equation 3
(460+ Ta)*Ps
where,
Es>n = natural gas volumetric fugitive emissions at standard temperature and pressure (STP)
conditions
Ean = natural gas volumetric fugitive emissions at actual conditions
Ts = Temperature at standard conditions (°F)
Ta = Temperature at actual emission conditions (°F)
Ps = Absolute pressure at standard conditions (inches of Hg)
Pa = Absolute pressure at ambient conditions (inches of Hg)
Both CH4 and CO2 volumetric and mass fugitive emissions can be calculated from
volumetric natural gas fugitive emissions using the Equations 1 and 2.
Calibration
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To ensure accurate results, a technician can be trained to obtain consistent results when
measuring the time it takes to fill the bag with fugitive emissions.
Metering
Meters vary in cost and precision, but can be advantageous for measuring large fugitive
emissions rates exceeding high volume sampler range, unsafe for calibrated bagging as well
as non-continuous fugitive emissions rates. Total emissions measurement devices such as
rotameters can be as accurate as high volume samplers and calibrated bagging. Applicability
is limited to large fugitive emissions rates and the presence of an appropriately sized conduit
to direct all emissions through the meter. Velocity measurement devices such as pitot tubes
and hot wire anemometers used in conjunction with engineering calculations are much less
accurate but may be the only method safe for very hot, very cold, or difficult to safely access
the emissions flow.
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. Ambient temperature and pressure of natural gas
fugitive emissions can be converted to standard temperature and pressure natural gas fugitive
emissions using Equation 3. Equations 1 and 2 can be used to estimate CH4 and CO2
volumetric and mass emissions from volumetric natural gas emissions.
Calibration
The meters can be calibrated using either one of the two methods provided below:
• Develop calibration curves by following the manufacturer's instruction.
• 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 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 flowmeter output to the actual
flowrate as determined by the master weigh scale and use the difference as a correction
factor.
(b) Engineering Estimation
For several sources, direct measurement is not safe, cost-effective, or possible. These
sources are outlined below along with relevant engineering estimation methods that can be
used to estimate fugitive GHG gas emissions from each source.
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Acid Gas Removal Vent Stacks
Operators can calculate fugitive 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 units. 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;
• Fugitive emissions control method(s), if any, and associated reduction of
fugitive emissions;
• Exit temperature of natural gas; and
• Solvent pressure, temperature, circulation rate, and weight.
Natural Gas Driven Pneumatic Pumps
Fugitive emissions 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.
Operators can maintain a log of the amount of liquid pumped annually for individual
pneumatic pumps and use the following equation for calculating fugitive emissions:
Esn=Fs *V Equation 4
where,
Es>n = natural gas fugitive emissions at standard conditions
Fs = natural gas driven pneumatic pump gas emissions in "emissions per volume of liquid
pumped" units at standard conditions, as provided by the manufacturer
V = Volume of liquid pumped annually
Both CH4 and CO2 volumetric and mass fugitive emissions can be calculated from
volumetric natural gas fugitive emissions using the Equations 1 and 2.
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. This measurement can be converted to emissions at standard conditions
using Equation 3 and then substituted into the equation above for Fs to calculate GHG
fugitive emissions.
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Natural Gas Driven Pneumatic Manual Valve Actuators
Fugitive 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 the following equation:
Es n ~ As ^ TV Equation 5
where,
Es>n = natural gas fugitive 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
Both CH4 and CO2 volumetric and mass fugitive emissions can be calculated from
volumetric natural gas fugitive emissions using Equations 1 and 2.
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. This measurement can be converted to emissions at standard conditions using
Equation 3 and then substituted for As in the equation above to calculate GHG emissions.
Natural Gas Driven Pneumatic Bleed Devices
Fugitive emissions from natural gas driven pneumatic valve bleed devices can be calculated
using manufacturer data for the gas bleed rate of specific models during normal operations
using the following equation:
Esn=Bs * T Equation 6
where,
Es>n = natural gas fugitive emissions at standard conditions
Bs = natural gas driven pneumatic device bleed rate in "emissions per unit time" units at
standard conditions, as provided by the manufacturer
T = amount of time the pneumatic device has been operational through the reporting period
Both CH4 and CO2 volumetric and mass fugitive emissions can be calculated from
volumetric natural gas fugitive emissions using Equations 1 and 2.
As an alternative to manufacturer data, the operator could conduct a one-time measurement
to determine natural gas bleed rate using a high volume sampler or calibrated bag or meter
for each pneumatic device. This measurement can be converted to emissions at standard
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conditions using Equation 3 and then substituted for Bs in the equation above to calculate
GHG emissions.
Blowdowtt Vent Stacks
Fugitive emissions from blowdown vent stacks can be calculated using the total 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 the following equation:
Ea„ = N*Vv Equation 7
where,
Ea n = natural gas fugitive emissions from blowdowns
N = number of blowdowns for the equipment in given year
Vv = total volume of blowdown equipment chambers (including, but not limited to, pipelines
and vessels) between isolation valves
Ambient temperature and pressure of natural gas fugitive emissions can be converted to
standard temperature and pressure natural gas fugitive emissions using Equation 3. Equations
1 and 2 can be used to estimate CH4 and CO2 volumetric and mass emissions from
volumetric natural gas emissions.
Dehydrator Vent Stacks
Fugitive emissions from a dehydrator vent stack can be calculated using a simulation
software package, such as GLYCalc™. 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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(C)
Combination of Direct Measurement and Engineering Estimation
Flare Stacks
In the cases of flare stacks, an engineering estimation of fugitive emissions requires data that
typically is not available, i.e. the volume of natural gas sent to the flare system. For this
reason a measurement of the volume of natural gas flared will be necessary. But it is not a
direct measurement of the fugitive emissions. Thus, a combination of measurement and
engineering estimation can be used with the following equation:
Where,
Eaj = annual fugitive emissions from flare stack
Va = Volume of natural gas sent to flare stack
r| = percent of natural gas combusted by flare (default is 95% for non-steam aspirated flares
and 98% for steam aspirated of air injected flares)
X; = concentration of GHG i in the flare gas
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 j; 1 for methane, 2
for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus)
K = "1" when GHG i is methane and "0" when GHG i is CO2
Va and X; from flare stacks can be estimated using the following procedure:
• A flow velocity measuring device (such as hot wire anemometer or pitot tube) can
be inserted directly upstream of the flare stack to determine the velocity of natural
gas sent to flare.
• Actual temperature and pressure conditions of the natural gas sent to flare can be
recorded.
• A sample representative natural gas to the flare stack can be taken every quarter to
evaluate the composition of GHGs present in the stream. The average of the most
recent four natural gas composition analyses conducted using ASTM D1945-03
can be recorded.
Ambient temperature and pressure of GHG fugitive emissions can be converted to standard
temperature and pressure GHG fugitive emissions using the following equation;
Ea, = Vax(l-V)xX{ + (1 -K)*rj*Va*Yj*R} t
Equation 8
E _Ea*(460 + Ts)*Pa
s'' / AdC\ 1 T \ * D
(460 + rj*^
Equation 9
where,
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ESJ = GHG i volumetric fugitive emissions at standard temperature and pressure (STP)
conditions
Ea n = natural gas volumetric fugitive emissions at actual conditions
Ts = Temperature at standard conditions (°F)
Ta = Temperature at actual emission conditions (°F)
Ps = Absolute pressure at standard conditions (inches of Hg)
Pa = Absolute pressure at ambient conditions (inches of Hg)
Mass GHG fugitive emissions at standard conditions can be calculated using Equation 2.
Centrifugal 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 the following procedure:
• A flow velocity measuring device (such as hot wire anemometer or pitot tube) can
be inserted directly upstream of the degassing unit vent exit to determine the
velocity of gas sent to the vent. Then volume of natural gas sent to vent can be
calculated from the velocity measurement.
• Actual temperature and pressure conditions of the gas sent to degassing vent can
be recorded.
• 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. The average
of the most recent four natural gas composition analyses conducted using ASTM
D1945-03 can be recorded.
• Ambient temperature and pressure of natural gas fugitive emissions can be
converted to standard temperature and pressure natural gas fugitive emissions
using Equation 3. Equations 1 and 2 can be used to estimate CH4 and CO2
volumetric and mass emissions from volumetric natural gas emissions.
Storage Tanks
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 a one-time
measurement during a cycle of operation that is representative of the tank operations through
the year. The following equation can be used to calculate GHG emissions:
Eah = QxER Equation 10
where,
Ea,h = hydrocarbon vapor fugitive emissions at actual conditions
Q = storage tank total annual throughput
ER = measured hydrocarbon vapor emissions rate per throughput (e.g. cubic feet/barrel)
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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.
• 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.
Ambient temperature and pressure of natural gas fugitive emissions can be converted to
standard temperature and pressure natural gas fugitive emissions using Equation 3. Equations
1 and 2 can be used to estimate CH4 and CO2 volumetric and mass emissions from
volumetric natural gas emissions.
If this combination of direct measurement and engineering estimation is not feasible, a
second method is to use simulation software such as API TankCalc to estimate fugitive
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;
A third method for storage tank fugitive 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 11 demonstrates the use of this correlation
equation:
f /-. ^ >
GOR = AxGflashgas x 1
(p„P+14.7)
x exp
CxG
oil
T + 460
V seP V
Equation 11
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)
Gfiash gas = Specific gravity of the tank flash gas, where air = 1. A suggested default value for
Gflashgas is 1.22
Goii = API gravity of stock tank oil at 60°F
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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 Goii 30°API
B = 1.0937 for Goii 30°API
C = 25.724 for Goii 30°API
(d) Method 21
This is the authorized method for detecting and quantifying fugitive3 volatile organic carbon
(VOC) emissions under 40 CFR Part 60 VOC monitoring and control. The method specifies
the performance of emissions detection instruments such that it is equivalent to an OVA with
a probe not exceeding one fourth inch outside diameter, used to slowly circumscribe the
entire component interface where fugitive emissions could occur. The probe must be
maintained in close proximity to the interface unless it could be damaged by rotating shafts
or plugged with ingested lubricants or greases, in which case it can be no more than 1
centimeter away from the leak interface. Method 21 specifies a "leak/no-leak" threshold
definition, which this proposed rule is not adopting. Method 21 also allows certain alternative
fugitive emissions detection methods, such as soap solutions (where the fugitive emissions
source is below the boiling point and above the freezing point of the soap solution). Method
21 does not specify any emissions mass or volumetric quantification methods; only a
concentration definition of emissions expressed in parts per million concentration of
combustible hydrocarbon in the air stream of the instrument probe. Quantification is
generally done using EPA published quantification guidelines which are statistically
determined for a very large population of similar components, but not very accurate for
single leaks or small populations. Therefore, Method 21 is not considered to be appropriate
for measurement purposes for the proposed rule. Method 21 was recently amended with
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.
(e) Activity Factor and Emissions Factor for All Sources
Emissions factors for all the sources discussed are available in a study conducted in 1992 and
published in 1996 by the Gas Research Institute (GRI) and U.S. EPA4. There have been no
subsequent comparable studies published to replace or revise the estimates available from
this study. However, the industry operations have changed significantly with the introduction
of new technologies and improved industry operating/maintenance practices to mitigate
emissions. These are not reflected in the emissions factors available from the EPA/GRI
study. Also, in many cases the EPA study estimate of emissions factors are not representative
of industry operations because the estimates were based on limited or no field data and hence
not representative of the entire country. Therefore, this method for estimation of the
emissions is not is not considered to be appropriate for a mandatory GHG reporting program.
3 Again, in this TSD, "fugitive" refers to both intentional and unintentional leaks. Under Method 21, "fugitive"
refers only to what would be considered unintentional leaks
4 Gas Research Institute/ U.S. Environmental Protection Agency. June 1996. Methane Emissions from the
Natural Gas Industry. GRI-94/0257.22, EPA-600/R-96-080e
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( f) TVAs/ OVAs for Leak Measurement
As discussed above under Method 21, TVA and OVA 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. This
small size probe rarely ingests all of the fugitive emissions from a component leak.
Therefore, these instruments are used primarily for fugitive emissions detection. EPA
provides emissions quantification guidelines derived from emissions detection data using
OVA and TVA instruments. One choice of instrument emissions detection data is referred to
as "leak/no-leak" where a component is determined to be leaking when the OVA instrument
pegs at the Federal leak definition of 10,000 ppm, or the TVA reads a concentration of
10,000 ppm or higher. When the OVA or TVA reads a concentration less than 10,000 ppm,
the component is determined to be "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. OVA instruments normally peg at
10,000 ppm, and so are unsuitable for use with the "stratified" quantification factors. For the
proposed rule, fugitive emissions detection by more cost-effective screening technologies in
conjunction with direct measurement methodologies is deemed a better overall approach to
emissions quantification than the labor intensive OVA/TVA and potential use of highly
unreliable fugitive emission factors for these instruments.
(g) Mass Balance for Quantification. There are mass balance methods that could be
considered to calculate emissions from 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 fugitive emissions. Applicability to
other segments of the petroleum and natural gas industry is uncertain at this time.
(4) Additional Questions Regarding Potential Monitoring Methods
There are several additional issues regarding the potential monitoring methods that are
relevant to estimating fugitive emissions from the petroleum and natural gas industry.
(a) Source Level Fugitive Emissions Detection Threshold
This document does not indicate a particular fugitive emissions definition or detection
threshold requiring emissions measurement. This is because different potential fugitive
emissions 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
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
in limiting burden on emissions reporting. A facility can have hundreds of small emissions
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(as low as 3 grams per hour) and it might not be practical to measure all such small emissions
for reporting.
There are, however, two possible approaches to overcome this issue, as follows;
(i) Instrument Performance Standards
Performance standards can be provided for fugitive emissions detection instruments and
usage such that all instruments follow a common minimum detection threshold. The
Alternate Work Practice to Detect Leaks from Equipment standards for IR fugitive emissions
detection instruments recently developed by EPA can potentially be proposed. In such a case
all detected emissions from components subject to the proposed rule may require
measurement and reporting.
The current Method 21 practice is based on a 25 year old technology that uses gas
concentration measurement at the tip of a probe manually circumscribed on or within one
centimeter along the entire potential emissions surface to detect fugitive emissions. The
current threshold for a source to be identified as emitting is 10,000 parts per million by
volume (ppmv) of VOC and 500 ppmv of Hazardous Air Pollutants (HAPs) at any point. In a
study conducted by API at seven California refineries with over five years of measured data
(11.5 million data points), it was found that over 90 percent of the controllable emissions (i.e.
fugitive emissions that can be mitigated once detected) are contributed by about 0.13 percent
of the components. In a typical Method 21 program the costs of conducing 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
potential source is screened for emissions as described above. Given the fact that only a small
number of sources contribute to majority of the emissions, the detection of the remaining
sources emitting at smaller mass rates is not imperative to the success of the program. This
means that an alternative work practice/ technology that is more cost effective than the
current gas concentration in air measurement technology and that can detect equal or greater
amounts of controllable emissions is feasible for the Method 21 program.
The EPA Alternate Work Practice (AWP) promulgated the use of optical gas imaging
technologies that can detect in some cases emissions as small as 1 gram per hour. The AWP
requires technology effectiveness of emissions equal to 60 grams/hour, 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 emissions from valves are
equivalent to the 10,000 ppmv definition of an actionable emissions source in Method 21. To
implement the technology effectiveness, the AWP requires that the detection instrument meet
a minimum detection sensitivity mass flow rate. Or, alternatively, the mass flow rate for the
process being studied should be calculated by prorating a standard detection sensitivity
emissions rate using equations provided by the AWP proposal. For the purposes of a
mandatory reporting program, 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).
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(i i) Fugitive Emissions Definition
An emissions definition for detection using OVA/TVA can be provided. When using IR
fugitive emissions detection instruments all potential sources that have emissions detected
may require emissions quantification. Alternatively, the operator can be given a choice of
first detecting emissions sources using the IR detection instrument and then verifying for
measurement status using the emissions definition for an OVA/TVA.
(b) Duration of Fugitive Emissions
Some fugitive emissions by nature occur randomly within the facility. Therefore, there is no
way of knowing when a particular source started emitting. The potential monitoring method
requires a one time fugitive emissions detection and measurement. But the emissions
detected and measured will have to be assumed to be emitting throughout the reporting year,
unless no emissions detection was recorded at an earlier and/or later point in the reporting
period. However, where this does not occur, emissions reported could be higher than actual.
(c) Unofficial Surveys
Natural gas is a saleable commodity and rising natural gas prices are providing an economic
incentive to reduce emissions. The petroleum and natural industry is already selectively
implementing voluntary fugitive emissions detection and repair programs. Such voluntary
programs are desired, but can pose an accounting problem with respect to emissions
reporting for a mandatory GHG reporting program. The potential monitoring method does
not preclude any program from detecting and repairing fugitive emissions just prior to the
official detection, measurement, and reporting of emissions in which case the repaired
emissions may not get reported. In developing a reporting program, one would have to decide
whether such a scenario could lead to a misrepresentation of emissions estimates, or whether
this would be an acceptable outcome.
(d) Fugitive 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.
Fugitive emissions from a compressor 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 then fugitive emissions result from closed blowdown valves and
reciprocating compressor rod packing leaks. When the compressor is offline and
depressurized, then fugitive emissions result from releasing the natural gas to the atmosphere
and from isolation valve leakage. When operating, compressor fugitive emissions result from
compressor seals or rod packing and other components in the compressor system. In each of
the compressor modes the resultant fugitive emissions are significantly different. One
potential approach to address this issue is that operators measure emissions for each mode the
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compressor is operated in and the period of time during the reporting period at which the
compressor is in the different modes to account for the varying levels of fugitive emissions.
However, this will increase the reporting burden, since measurements will have to be taken at
each mode of compressor operation. The time that the equipment is in various operational
modes would also have to be tracked.
(e) Natural Gas Composition
When measuring fugitive emissions using the various measurement instruments (high
volume sampler, calibrated bags, and meters measure natural gas emissions), only flow rate
is measured and the individual CH4 and CO2 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
(flare stack and storage tank fugitive emissions are an exception to this general rule). These
gas composition estimates are assumed to be available with facilities. But this may or may
not be a practical assumption. In the absence of gas composition, periodic measurement of
the required gas composition for speciation of the natural gas mass emissions into CH4 and
CO2 mass emissions could be a potential option.
(f) 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. The class of
unintentional leaking components, e.g. flanges, valve stems, equipment covers, is generally
smaller than the class of fugitives from vent stacks, whether designed, intentional emissions
or through-leaking valves intended to isolate the process from a vent stack. The former class
of component leaks is expensive to measure where they are not accessible within arms reach
from the ground or a fixed platform. Vent stacks are often located out of access by operators
for safety purposes, but may represent large emission sources. Where emissions are detected
by remote sensing devices such as IR cameras, 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.
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(D) 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 to use a previous years' data point to
replace missing data in the current reporting year, this is not ideal due to the impact that
various operating conditions can have on fugitive emissions. Where using previous years'
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.
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 fugitive
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 should be repeated within the reporting period. If this proves to be
impossible, then the previous reporting period's data could be used to estimate fugitive
emissions from the current reporting period.
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 fugitive emissions. Again,
using previous years' data are not as desirable as there could be significant
differences from year to year based on operating conditions.
• Process conditions data. Estimating fugitive emissions from acid gas removal vent
stacks, blowdown vent stacks, dehydrator vent stacks, 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,
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.
Emissions Estimation Data for Storage Tanks and Flares
Fugitive emissions from storage tanks and flares might require a combination of both direct
measurement and engineering estimation to quantify emissions. Storage tank emissions
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calculation requires the measurement of "fugitive emissions per throughput" data. If this data
is missing then the previous year's estimate of "fugitive 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.
(E) QA/QC Requirements
Equipment Maintenance
Equipment used for monitoring, both leak 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.
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.?
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,
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¦ Changes concerning the emitting process (e.g. energy efficiency
improvements).5
• 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.6
• Maintain data documentation, including comprehensive documentation of data
received through personal communication:
o Check that changes in data or methodology are documented
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)
o Check the aggregation of data across source categories, business units, etc.
5 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.
6 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 When methods or data have changed, check consistency of time series inputs
and calculations.7
(F) Reporting Procedure
The following reporting requirements could be considered for a mandatory reporting rule;
a) Where emissions are reported on an annual basis it is not practically possible, in most
cases, to determine when the fugitive emissions began. Therefore, under these circumstances,
annual emissions would be determined assuming that the fugitive emissions were continuous
from the beginning of the reporting period or last recorded zero detection in the current
reporting period and until the fugitive emissions is repaired or the end of the reporting period.
(b) There are potentially hundreds (and in some cases) thousands of fugitive emissions
sources in a facility. Typically, from practical experience in the Natural Gas STAR Program
10 percent of the potential emissions sources have been found to be emitting. Reporting of
such large numbers of emissions estimates may not be practical. One way to minimize the
reporting burden would be to have facilities report emissions at the individual source type
level, i.e. fugitive emissions from each source type can be reported in the aggregate. For
example, a facility with multiple reciprocating compressors may report emissions from all
reciprocating compressors as an aggregate number. The disadvantage to this approach would
be that there would not be a distinction in the reported data between intentional (e.g., vents)
and unintentional (e.g., leaks) releases. Although such distinctions may be of interest to the
reporter, as different mitigation opportunities may exist for intentional and unintentional
releases, it may not be necessary for the integrity of a reporting program, and therefore
aggregate reporting may be sufficient.
(c) Due to the point-in-time nature of direct measurements, reports of annual fugitive
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.
(d) 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.
7 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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(G) 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 fugitive
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).
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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 can be included in the proposed rule.
Inventory of Methane Emissions from Natural Gas Systems (Year 2006)
Note: Cells Highlighted in "yellow" represent sources that fall over the threshold for either 1% of total emissions (3597 MMcf/year) or emissions factor (100 Mcf/year)
Cells highlighted in "pink" represent sources that were included over riding the decision tree process
Emissions per unit
Decision Process
(Mcf/year)
Preferred Estimation Methodoloqy
Outcome
l-include;
Measurement Continuous
Pl-probably include;
Measurement Periodic
Cl-consider includinq;
Total Emissions
Production EFs are for
Enqineerinq (Calculation)
ET-excluded with tech;
Reduction Technoloqy
PRODUCTION
Nationally (MMcf/year)
Rocky Mountain Reqion
Emission Factors (Calculation)
EX-excluded
Available (Y/N)
\Normal Fugitives
Gas Wells
Non-associated Gas Wells (less Unconventional)
2,682
13
Measurement Periodic
ET
Y
Unconventional Gas Wells
69
3
Measurement Periodic
ET
Y
Field Separation Equipment
Heaters
1.463
21
Measurement Periodic
ET
Y
Separators
4,718
45
Measurement Periodic
PI
Y
Dehydrators
1,297
33
Measurement Periodic
ET
Y
Meters/Pipinq
4,556
19
Measurement Periodic
PI
Y
Gatherinq Compressors
Small Reciprocatinq Comp.
2.926
98
Measurement Periodic
ET
Y
Larqe Reciprocatinq Comp.
664
5,550
Measurement Periodic
PI
Y
Larqe Reciprocatinq Stations
45
3,010
Measurement Periodic
PI
Y
Pipeline Leaks
8,087
19
Measurement Periodic
PI
Y
I Vented and Combusted
Drillinq and Well Completion
Completion Flarinq
0
0.73
Enqineerinq
ET
Y
Well Drillinq
96
3
Measurement Continuous/Enqineerinq
EX
N
Coal Bed Methane
Powder River (Gq/qallon water drainaqe)
2.924
1.9831 E-09
Measurement Continuous/Enqineerinq
ET
Maybe
Black Warrior (Gq/well)
543
0.0023
Measurement Continuous/Enqineerinq
ET
Maybe
Normal Operations
Pneumatic Device Vents
52,421
126
Measurement Periodic/Emission Factors
PI
Y
Chemical Injection Pumps
2.814
91
Enqineerinq
ET
Y
Kim ray Pumps (Mcf/MMscf)
11,572
1
Enqineerinq
PI
Y
Dehydrator Vents (Mcf/MMscf)
3,608
0
Enqineerinq
PI
Y
Condensate Tank Vents
Condensate Tanks without Control Devices (Mcf/bbl)
1,225
0.02
Enqineerinq
I
Y
Condensate Tanks with Control Devices (Mcf/bbl)
245
0.00
Enqineerinq
I
N
Compressor Exhaust Vented
Gas Enqines (scf/HPhr)
11,680
0.24
Measurement Continuous/Emission Factors
I
Maybe
Well Workovers
Gas Wells
47
2
Enqineerinq
I
Y
Well Clean Ups (LP Gas Wells)
9,008
50
Enqineerinq
I
Y
Blowdowns
Vessel BD
31
0.08
Enqineerinq
EX
N
Pipeline BD
129
0.31
Enqineerinq
ET
Y
Compressor BD
113
4
Enqineerinq
ET
Y
Compressor Starts
253
8
Enqineerinq
ET
Y
Upsets
Pressure Relief Valves
29
0
Not Practical
EX
N
Mishaps
70
1
Not Practical
EX
N
I Offshore
0
Shallow water Gas Platforms (GoM and Pacific)
12,621
7,000
Measurement Periodic
PI
Y
Deepwater Gas Platforms (GoM and Pacific)
630
29,000
Measurement Periodic
PI
Y
Background Technical Support Document - Petroleum and Natural Gas Industry
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Inventory of Methane Emissions from Natural Gas Systems (Year 2006)
Note: Cells Highlighted in "yellow" represent sources that fall over the threshold for either 1% of total emissions (3597 MMcf/year) or emissions factor (100 Mcf/year)
Cells highlighted in "pink" represent sources that were included over riding the decision tree process
Preferred Estimation Methodology
Decision Process
Outcome
GAS PROCESSING PLANTS
Total Emissions
Nationally (MMcf/year)
Emissions per unit
(Mcf/year)
Measurement Continuous
Measurement Periodic
Engineering (Calculation)
Emission Factors (Calculation)
l-include;
Pl-probably include;
Cl-consider including;
ET-excluded with tech;
EX-excluded
Reduction Technology
Available (Y/N)
\ Normal Fuqitives
Plants
1,634
2,886
Measurement Periodic
PI
Y
Recip. Compressors
17,351
4,087
Measurement Periodic
PI
Y
Centrifugal Compressors
5,837
7,749
Measurement Periodic
PI
Y
I Vented and Combusted
Normal Operations
Compressor Exhaust
Gas Engines
(scf/HPhr)
6,913
0.24
Measurement Continuous/Emission Factors
I
Maybe
Gas T urbines
(scf/HPhr)
195
0.01
Measurement Continuous/Emission Factors
I
Maybe
AGR Vents
643
2,220
Engineering
PI
Y
Kimray Pumps
(Mcf/MMscf)
177
0.18
Engineering
ET
Y
Dehydrator Vents
(Mcf/MMscf)
1,088
0.12
Engineering
ET
Y
Pneumatic Devices
(Mcf/plant)
93
165
Engineering
PI
Y
I Routine Maintenance
IB lo wdo wn s/V e nti n g
(Mcf/ plant)
2,299
4,060
Engineering
PI
Y
TRANSMISSION AND STORAGE
\Fuqitives
Pipeline Leaks
166
0.57
Measurement Periodic/ Engineering
ET
Y
Compressor Stations (Transmission)
Station
5,619
3,204
Measurement Periodic
PI
Y
Recip Compressor
38,918
5,550
Measurement Periodic
PI
Y
Centrifugal Compressor
7,769
11,061
Measurement Periodic
PI
Y
Compressor Stations (Storage)
Station
2,801
7,850
Measurement Periodic
PI
Y
Recip Compressor
8,093
7,707
Measurement Periodic
PI
Y
Centrifugal Compressor
1,149
11,159
Measurement Periodic
PI
Y
Wells (Storage)
695
42
Measurement Periodic
ET
Y
M&R (Trans. Co. Interconnect)
3,798
1,454
Measurement Periodic
PI
Y
M&R (Farm Taps + Direct Sales)
853
11
Measurement Periodic
ET
Y
I Vented and Combusted
Normal Operation
Dehydrator vents (Transmission)
(scf/MMscf)
105
94
Engineering
ET
Y
Dehydrator vents (Storage)
(scf/MMscf)
217
117
Engineering
PI
Y
Compressor Exhaust
Engines (Transmission)
(scf/HPhr)
10,820
0.24
Measurement Continuous/Emission Factors
I
Maybe
Turbines (Transmission)
(scf/HPhr)
61
0.01
Measurement Continuous/Emission Factors
I
Maybe
Engines (Storage)
(scf/HPhr)
1,092
0.24
Measurement Continuous/Emission Factors
I
Maybe
Turbines (Storage)
(scf/HPhr)
9
0.01
Measurement Continuous/Emission Factors
I
Maybe
Generators (Engines)
(scf/HPhr)
529
0.24
Measurement Continuous/Emission Factors
I
Maybe
Generators (Turbines)
(scf/HPhr)
0
0.01
Measurement Continuous/Emission Factors
I
Maybe
Pneumatic Devices Trans + Stor
Pneumatic Devices Trans
11,393
162
Engineering/Emission Factors
PI
Y
Pneumatic Devices Storage
2,318
162
Engineering/Emission Factors
PI
Y
Routine Maintenance/Upsets
Pipeline venting
9,287
32
Engineering
ET
Y
Station venting Trans + Storage
Station Venting Transmission
7,645
4,359
Engineering
PI
Y
Station Venting Storage
1,555
4,359
Engineering
PI
Y
Background Technical Support Document - Petroleum and Natural Gas Industry
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Inventory of Methane Emissions from Natural Gas Systems (Year 2006)
Note: Cells Highlighted in "yellow" represent sources that fall over the threshold for either 1% of total emissions (3597 MMcf/year) or emissions factor (100 Mcf/year)
Cells highlighted in "pink" represent sources that were included over riding the decision tree process
Decision Process
Preferred Estimation Methodology
Outcome
l-include;
Measurement Continuous
Pl-probably include;
Measurement Periodic
Cl-consider including;
Total Emissions
Emissions per unit
Engineering (Calculation)
ET-excluded with tech;
Reduction Technology
LNG STORATE AND TERMINALS
Nationally (MMcf/year)
(Mcf/year)
Emission Factors (Calculation)
EX-excluded
Available (Y/N)
\LNG Storage
LNG Stations
552
7,850
Measurement Periodic
PI
Y
LNG Reciprocalnq Compressors
2.084
7,707
Measurement Periodic
PI
Y
LNG Centrifugal Compressors
715
11,159
Measurement Periodic
PI
Y
LNG Compressor Exhaust
LNG Enqines (scf/HPhr)
172
0.24
Measurement Continuous/Emission Factors
I
Mavbe
LNG Turbines (scf/HPhr)
1
0.01
Measurement Continuous/Emission Factors
I
Mavbe
LNG Station ventinq
306
4,359
Engineering
PI
N
\LNG Import Terminals
LNG Stations
22
7,850
Measurement Periodic
PI
Y
LNG Reciprocatinq Compressors
105
7,707
Measurement Periodic
PI
Y
LNG Centrifuqal Compressors
27
11,159
Measurement Periodic
PI
Y
LNG Compressor Exhaust
LNG Enqines (scf/HPhr)
586
0.24
Measurement Continuous/Emission Factors
I
Mavbe
LNG Turbines (scf/HPhr)
3
0.01
Measurement Continuous/Emission Factors
I
Mavbe
LNG Station ventinq
12
4,359
Engineering
PI
N
DISTRIBUTION
Mains - Unprotected steel
6,515
110
Emission Factors
CI
Y
Mains - Protected steel
1.422
3
Emission Factors
ET
Y
Mains - Plastic
6,871
10
Emission Factors
CI
Y
Total Pipeline Miles
Services - Unprotected steel
7,322
2
Emission Factors
CI
Y
Services Protected steel
2.863
0.18
Emission Factors
ET
Y
Services - Plastic
315
0.01
Emission Factors
ET
Y
Services - Copper
47
0.25
Emission Factors
ET
Y
Total Services
Meter/Requlator (Citv Gates)
M&R >300
5,037
1,575
Measurement Periodic
PI
Y
M&R 100-300
10,322
837
Measurement Periodic
PI
Y
M&R <100
249
38
Measurement Periodic
ET
Y
Req >300
5,237
1,383
Measurement Periodic
PI
Y
R-Vault >300
25
11
Measurement Periodic
ET
Y
Reo 100-300
4,025
355
Measurement Periodic
PI
Y
R-Vault 100-300
8
2
Measurement Periodic
ET
Y
Req 40-100
306
9
Measurement Periodic
ET
Y
R-Vault 40-100
23
0.76
Measurement Periodic
ET
Y
Req <40
17
1
Measurement Periodic
ET
Y
Customer Meters
Residential
5,304
0.14
Measurement Periodic
PI
Y
Commercial/lndustrv
203
0.05
Measurement Periodic
ET
Y
I Vented
Rountine Maintenance
Pressure Relief Valve Releases (Mcf/mile)
63
0.05
Not Practical
EX
N
Pipeline Blowdown (Mcf/mile)
122
0.10
Engineering
ET
Y
Upsets
Mishaps (Dig-ins)
1,907
2
Not Practical
EX
N
Background Technical Support Document - Petroleum and Natural Gas Industry
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Inventory of Methane Emissions from Petroleum Systems (Year 2006]
Note: Cells Highlighted in "yellow" represent sources that fall over the threshold for either 1% of total emissions (704 MMcf/year) or emissions factor (100 Mcf/year)
Cells highlighted in "pink" represent sources that were included over riding the decision tree process
Preferred Estimation Methodology
Decision Tree
l-include;
Measurement Continuous
Pl-probably include;
Total Emissions
Measurement Periodic
Cl-consider including;
Nationally
Emissions per unit
Engineering (Calculation)
ET-excluded with tech;
Reduction Technology
Emission Source
(MMcf/year)
(Mcf/year)
Emission Factors (Calculation)
EX-excluded
Available (Y/N)
Production
Vented Emissions:
Oil Tanks (scf/bbl of crude)
7,171
5
Measurement Periodic
PI
Y
Pneumatic Devices, Hiqh Bleed
16,067
121
Enaineerina
PI
Y
Pneumatic Devices, Low Bleed
4,696
19
Enaineerina
PI
Y
Chemical Injection Pumps
2,429
91
Enaineerina
PI
Y
Vessel Biowdowns
14
0.08
Enaineerina
EX
N
Compressor Biowdowns
9
4
Enaineerina
ET
Y
Compressor Starts
20
8
Enaineerina
ET
Y
Stripper wells
752
2
Measurement Periodic
PI
Y
Well Completion Venting
9
1
EX
N
Weil Workovers
4
0.10
EX
N
Pipeline Piqqinq
0.00
1
Enaineerina
ET
Y
OCS Offshore Platforms, Shallow water oil
29,275
20,000
Measurement Periodic
PI
Y
OCS Offshore Platforms, Deep water oil
2,202
95,000
Measurement Periodic
PI
Y
Fugitive Emissions:
Oil Wellheads (heavy crude)
1
0.05
Measurement Periodic
ET
Y
Oil Wellheads (liqht crude)
1,016
6
Measurement Periodic
PI
Y
Separators (heavy crude)
1
0.06
Measurement Periodic
ET
Y
Separators (light crude)
471
5
Measurement Periodic
ET
Y
Heater/Treaters (light crude)
494
7
Measurement Periodic
ET
Y
Headers (heavy crude)
0.37
0.03
Measurement Periodic
ET
Y
Headers (light crude)
161
4
Measurement Periodic
ET
Y
Floating Roof Tanks
8
338
Measurement Periodic
PI
Y
Compressors
86
37
Measurement Periodic
ET
Y
Larqe Compressors
0.00
5,971
Measurement Periodic
PI
Y
Sales Areas (Mcf/loading)
63
0.04
Measurement Periodic
ET
Y
Pipelines
0.00
0.00
Measurement Periodic
ET
Y
Well Drillinq
0.00
0.00
EX
N
Battery Pumps
13
0.09
ET
Y
Combustion Emissions:
Gas Engines (scf CH4/HP-hr)
3,564
0.24
Monitorina (Measurement Continuous)
I
Y
Heaters (scf CH4/bbl)
1
1
EX
N
Well Drilling
34
2
EX
N
Flares (scf/ Mcf flared
3
20
I
Y
Process Upset Emissions:
Pressure Relief Valves
5
0.03
EX
N
Well Blowouts Onshore
116
2,500
Enaineerina
PI
N
Background Technical Support Document - Petroleum and Natural Gas Industry
53
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Inventory of Methane Emissions from Petroleum Systems (Year 2006)
Note: Cells Highlighted in "yellow" represent sources that fall over the threshold for either 1% of total emissions (704 MMcf/year) or emissions factor (100 Mcf/year)
Cells highlighted in "pink" represent sources that were included over riding the decision tree process
Preferred Estimation Methodology
Decision Tree
Emission Source
Total Emissions
Nationally
(MMcf/year)
Emissions per unit
(Mcf/year)
Measurement Continuous
Measurement Periodic
Engineering (Calculation)
Emission Factors (Calculation)
l-include;
Pl-probably include;
Cl-consider including;
ET-excluded with tech;
EX-excluded
Reduction Technology
Available (Y/N)
Transportation
Vented Emissions:
Tanks (scf CH4/vr/bbl of crude delivered to refineries)
115
0.02
EX
Y
Truck Loadina
(scf CH4/vr/bbl of crude transported bv truck)
30
1
EX
Marine Loadina
(scf CH4/1000 aal.crude marine loadinas)
57
3
EX
Rail Loadina
(scf CH4/vr/bbl of crude transported bv rail)
2
1
EX
Pump Station Maintenance
0.02
0.04
EX
Pipeline Piaaina
14
0.04
EX
Y
Fugitive Emissions:
Pump Stations
1
0.03
EX
N
Pipelines
0.00
0.00
EX
N
Fioatina Roof Tanks
49
59
EX
N
Combustion Emissions:
Pump Enaine Drivers
(scf CH4/hp-hr)
NA
0.24
EX
Y
Heaters
(scf CH4/bbl. burned)
NA
1
EX
Y
Refineries
Vented Emissions:
Tanks
15
21
Enaineerina
I
Y
System Blowdowns
761
137
PI
Y
Asphalt Blowing
472
2,555
PI
Fugitive Emissions:
Fuel Gas System
(Mcf/refinery)
64
439
PI
N
Floating Roof Tanks
(Mcf CH4/floating roof tank/)
0.45
1
Enaineerina
I
N
Wastewater T reating
10
2
EX
N
Cooling Towers
13
2
EX
N
Combustion Emissions:
Atmospheric Distillation
21
4
EX
Y
Vacuum Distillation
9
4
EX
Y
Thermal Operations
5
6
EX
Y
Catalytic Cracking
10
5
EX
Y
Cataiiytic Reforming
8
7
EX
Y
Catalytic Hydrocracking
4
7
EX
Y
Hydro refining
2
2
EX
Y
Hydrotreating
24
6
EX
Y
Alkylation/Polymerization
5
13
EX
Y
Aromatics/lsomeration
1
2
EX
Y
Lube Oil Processing
0.00
0.00
EX
Y
Engines
(scfCH4/hp-hr)
7
0.01
Enaineerina
I
Y
Flares
1
0.19
Enaineerina
I
Y
Background Technical Support Document - Petroleum and Natural Gas Industry
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APPENDIX B: Glossary
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 process.
Acid gas removal unit (AGIO means a process unit that separates hydrogen sulfide
and/or carbon dioxide from sour natural gas using liquid or solid absorbents, such as liquid
absorbents, solid adsorbents, or membrane separators.
Acid gas removal vent stack fugitive emissions mean the acid gas (typically CO2
and/or H2S) separated from the acid gas absorbing medium (most commonly an amine
solution) and released with methane and other light hydrocarbons to the atmosphere or a
flare.
Actual conditions mean temperature, pressure and volume at measurement conditions
of natural gas.
Actuation means, for the purposes of this rule, an event in which a natural gas
pneumatically driven valve is opened and/or closed by release of natural gas pressure to the
atmosphere.
Air injected flare means a flare in which air is blown into the base of a flare stack to
induce complete combustion of low Btu natural gas (i.e. high non-combustible component
content).
Ambient temperature means the surrounding temperature to a process or stream; often
times the atmospheric temperature.
Anti-static wrap means wrap used to assist the process of ensuring that all fugitive
emissions from a single source are captured and directed to a measurement instrument.
Backpressure means impeding the natural atmospheric release of fugitive emissions
by enclosing the release with a lower capacity sampling device and altering natural flow.
Barometric pressure means the pressure of the atmosphere at the given altitude and
time, as measured by a barometer.
Bleed rate means the rate at which natural gas flows continuously or intermittently
from a process measurement instrument to a valve actuator controller where it is vented
(bleeds) to the atmosphere.
Blowdown means manual or automatic opening of valves to relieve pressure and or
release natural gas from but not limited to process vessels, compressors, storage vessels or
pipelines by venting natural gas to the atmosphere or a flare. This practice is often
implemented prior to shutdown or maintenance.
Blowdown vent stack fugitive emissions mean natural gas released due to
maintenance and/or blowdown operations including but not limited to compressor blowdown
and Emergency Shut-Down system testing.
Boil-off gas means natural gas that vaporizes off of liquefied natural gas in storage
tanks.
Background Technical Support Document - Petroleum and Natural Gas Industry
55
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Calibrated bag means a flexible, non-elastic bag of a calibrated volume that can be
quickly affixed to a fugitive emitting source such that the fugitive emissions inflate the bag to
its calibrated volume.
Centrifugal compressor means any equipment that increases the pressure of a process
natural gas 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 operate mechanically under the opposing forces to
prevent natural gas from escaping to the atmosphere.
Centrifugal compressor dry seals fugitive emissions mean natural gas 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 seals mean a series of rings around the compressor shaft
where it exits the compressor case, that use oil circulated under high pressure between the
rings to prevent natural gas from escaping to the atmosphere.
Centrifugal compressor wet seals fugitive emissions mean natural gas released from
the seal face around the rotating shaft where it exits one or both ends of the compressor case
PLUS the natural gas absorbed in the circulating seal oil and vented to the atmosphere from a
seal oil degassing vessel or sump before the oil is re-circulated, or from a seal oil
containment vessel vent.
Close-range means, for the purposes of this rule, safely accessible within the
operator's arm's reach from the ground or stationary platforms.
Cold fugitive emissions mean an emissions stream that is low enough in temperature
(i.e. less than 140 degrees Fahrenheit) to be safely directly measured by a person.
Component means but is not limited to 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.
Comprehensive emissions detection survey means effort made with rule specified and
calibrated instruments, to inspect all potential fugitive emission sources required under this
rule, and detect actual emissions, including direct measurement of fugitive emissions found
or acquisition of operating and facility date necessary for engineering estimates including
process simulation modeling of emissions.
Compressor means any machine for raising the pressure of a natural gas by drawing
in low pressure natural gas and discharging significantly higher pressure natural gas (i.e.
compression ratio higher than 1.5).
Compressor fugitive emissions mean natural gas emissions from all components in
close physical proximity to compressors where mechanical and thermal cycles may cause
elevated emission rates, including but not limited to open-ended blowdown vent stacks,
piping and tubing connectors and flanges, pressure relief valves, pneumatic starter open-
ended lines, instrument connections, cylinder valve covers, and fuel valves.
Condensate means hydrocarbon and other liquid separated from natural gas that
condenses due to changes in the temperature, pressure, or both, and remains liquid at storage
conditions, includes both water and hydrocarbon liquids.
Background Technical Support Document - Petroleum and Natural Gas Industry
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Connector means but is not limited to flanged, screwed, or other joined fittings used
to connect pipe line segments, tubing, pipe components (such as elbows, reducers, "T's" or
valves) or a pipe line and a piece of equipment or an instrument to a pipe, tube or piece of
equipment. A common connector is a flange. Joined fittings welded completely around the
circumference of the interface are not considered connectors for the purpose of this
regulation.
Control method means any equipment used for recovering and/or oxidizing air
emissions of methane. Such equipment includes, but is not limited to, vapor recovery
systems, absorbers, carbon dioxide adsorbers, condensers, incinerators, flares, catalytic
oxidizers, boilers, and process heaters.
Correction factor for flow meters means a calibration factor that is applied to the
direct instrument reading to convert the value to a more correct value.
Crude oil means any of the naturally occurring liquids and semi-solids found in rock
formations composed of complex mixtures of hydrocarbons ranging from one to hundreds of
carbon atoms in straight and branched chains and rings.
Dehvdrator means, for the purposes of this rule, a device in which a liquid absorbent
(including but not limited to desiccant, ethylene glycol, diethylene glycol, or triethylene
glycol) directly contacts a natural gas stream to absorb water vapor.
Dehvdrator vent stack fugitive emissions mean natural gas released from natural gas
dehydrator system absorbent (typically glycol) reboiler or regenerator, 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 (ethane, propane, butane, pentane-plus) in feed
natural gas stream.
Downstream of de-methanizer means any process stream or equipment containing a
process stream that has passed through a de-methanizer at natural gas processing facilities.
Engineering estimation means an estimate of fugitive emissions based on engineering
principles applied to measured and/or approximated physical parameters such as dimensions
of containment, actual pressures, actual temperatures, and compositions.
Equipment means but is not limited to each pump, compressor, pipe, pressure relief
device, sampling connection system, open-ended valve or line, valve, connector, surge
control vessel, tank, vessel, and instrumentation system in natural gas or liquid service; and
any control devices or systems referenced by this subpart.
Emissions Source see component, qualified to be those components that contain and
potentially can release methane to the atmosphere.
Equipment chambers mean the total natural gas-containing volume within an
equipment between the equipment isolation valves.
Flare stack means a device used to provide a safe means of combustible natural gas
disposal from routine operations, upsets, or emergencies via combustion of the natural gas in
an open, normally elevated flame.
Flare combustion efficiency means the fraction of natural gas, on a volume or mole
basis, that is combusted at the flare burner tip, assumed 95% for non-aspirated field flares
and 98% for steam or air asperated flares.
Background Technical Support Document - Petroleum and Natural Gas Industry
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Flare stack fugitive emissions means the CH4 and CO2 content of that portion of
natural gas (typically 5% in non-aspirated field flares and 2% in steam or air asperated flares)
that passes through flares un-combusted and the total CO2 emissions of that portion of the
natural gas that is combusted.
Fractionation of natural gas liquids means the process by which saturated
hydrocarbons are removed from natural gas and separated by boiling point into distinct
products, or "fractions," such as propane, butane, and ethane.
Fugitive emissions means unintentional equipment emissions, and in context of this
rule intentional or designed releases, of methane and/or carbon dioxide containing natural gas
or hydrocarbon gas(not including combustion flue gas) from emissions sources including, but
not limited to, open ended lines, equipment connections or seals to the atmosphere. In the
context of this rule, fugitive emissions also mean CO2 emissions resulting from combustion
of natural gas in flares.
Fugitive emissions detection means the process of identifying natural gas emitting
equipment, components, and other point sources, either intentional or unintentional.
Fugitive emissions detection instruments mean any device or instrument that has been
approved for fugitive emissions detection in this rule, namely infrared fugitive emissions
detection instruments, OVAs, and TVAs.
Fugitive emissions measurement means the process of using measuring instruments in
direct contact with the natural gas fugitive emissions to quantify the mass or volumes emitted
from detected point sources.
Gas conditions mean the actual temperature, volume, and pressure of a gas sample.
Gathering and boosting station means a station used to gather natural gas from well or
field pipelines for delivery to a natural gas processing facilities or central point. Stations may
also provide compression, dehydration, and/or treating services.
High volume sampler means an atmospheric emissions measurement device that
captures emissions from a source in a calibrated air intake and uses dual hydrocarbon sensors
and other devices to measure the flow rate and combustible hydrocarbon concentrations of
the fugitive emission such that the quantity of emissions is determined.
Hot wire anemometer means a meter that measures gas velocity by measuring the
heat convected by the gas from a hot wire core of the meter. The hot wire is either heated
using a constant source of current or kept at a constant temperature. The measurements are
made by traversing the meter across the cross section of the conduit carrying the gas and
profiling the flow across the cross section. The gas velocity is estimated using a standard
correlation of gas velocities to wire temperatures or current consumption.
Infrared remote fugitive emissions detection instrument means an instrument that
detects infrared light in the narrow wavelength range absorbed by light hydrocarbons
including methane, and presents a signal (sound, digital or visual image) indicating the
presence of methane and other light hydrocarbon vapor emissions in the atmosphere; for the
purpose of this rule, it must detect the presence of methane.
Liquefied natural gas fLNG) means natural gas (primarily methane) that has been
liquefied by reducing its temperature to -260 degrees Fahrenheit at atmospheric pressure.
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Liquefied natural gas import and export facilities mean onshore and/or offshore
facilities that send out exported or receive imported liquefied natural gas, store it in storage
tanks, re-gasify it, and deliver re-gasified natural gas to natural gas transmission or
distribution systems. The facilities include tanker unloading equipment, liquefied natural gas
transportation pipelines, pumps, compressors to liquefy boil-off-gas, re-condensers, and
vaporization units for re-gasification of the liquefied natural gas.
LNG import and export facility fugitive emissions mean natural gas releases from
valves, connectors, storage tanks, flanges, open-ended lines, pressure relief valves, boil-off-
gas recovery, send outs (pumps and vaporizers), packing and gaskets. This does not include
fugitive emissions from equipment and equipment components reported elsewhere for this
rule.
Liquefied natural gas storage facilities means an onshore facility_that stores liquefied
natural gas in above ground storage vessels. The facility may include equipment for
liquefying natural gas, compressors to liquefy boil-off-gas, re-condensers, and vaporization
units for re-gasification of the liquefied natural gas.
LNG storage station fugitive emissions mean natural gas releases from valves,
connectors, flanges, open-ended lines, storage tanks, pressure relief valves, liquefaction
process units, packing and gaskets. This does not include fugitive emissions from equipment
and equipment components reported elsewhere for this rule.
Mass emissions mean fugitive emissions reported in mass units such as kilograms or
tonnes.
Meter means a device that measures gas flow rate from a fugitive emissions source or
through a conduit by detecting a condition (pressure drop, spin induction, temperature loss,
electronic signal) that varies in proportion to flow rate or measures gas velocity in a manner
that can calculate flow rate.
Mole percent means the proportion of a chemical species in a mixture that represents
the ratio of the number of molecules of that species per total number of all molecules of all
chemical species in the mixture.
Natural gas means a naturally occurring mixture of hydrocarbon and non-
hydrocarbon gases found in geologic formations beneath the earth's surface, of which its
constituents include, but are not limited to, methane, heavier hydrocarbons and carbon
dioxide. Natural gas may be field quality (which varies widely) or pipeline quality. For the
purposes of this subpart, the definition of natural gas includes similarly constituted fuels such
as field production gas, process gas, and fuel gas.
Natural gas driven pneumatic manual valve actuator device means valve control
devices that use pressurized natural gas to provide the energy required for an operator to
manually open, close, or throttle a liquid or gas stream. Typical manual control applications
include, but are not limited to, equipment isolation valves, tank drain valves, pipeline valves.
Natural gas driven pneumatic manual valve actuator device fugitive emissions means
natural gas released due to manual actuation of natural gas pneumatic valve actuation
devices, including, but not limited to, natural gas diaphragm and pneumatic-hydraulic valve
actuators.
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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.
Natural gas driven pneumatic pump fugitive emissions means natural gas released
from pumps that are powered or assisted by pressurized natural gas.
Natural gas driven pneumatic valve bleed device means valve control devices that use
pressurized natural gas to transmit a process measurement signal to a valve actuator to
automatically control the valve opening. Typical bleeding process control applications
include, but are not limited to, pressure, temperature, liquid level, and flow rate regulation.
Natural gas driven pneumatic valve bleed devices fugitive emissions means natural
gas continuous or intermittent release from automatic process control loops including the
natural gas pressure signal flowing from a process measurement instrument (e.g. liquid level,
pressure, temperature) to a process control instrument which activates a process control valve
actuator.
Natural gas liquids means the liquid hydrocarbons, such as ethane, propane, butane,
pentane, and natural gasoline that are extracted from natural gas produced from crude oil and
natural gas wells.
Natural gas processing facilities means any processing site engaged in the extraction
of natural gas liquids from produced natural gas, which may also include fractionation of
mixed Natural Gas Liquids (NGL) to natural gas products, removal of contaminants such as
but not limited to carbon dioxide, sulfur compounds, nitrogen, helium, and water. In addition,
processing facilities encompass gathering and boosting stations that include equipments that
phase-separate natural gas liquids from natural gas, dehydrate the natural gas, and transport
the natural gas to transmission pipelines or to a processing facility with fractionation
equipment.
Natural gas products means products produced for consumers from natural gas
processing facilities including, but not limited to, ethane, propane, butane, iso-butane, and
pentanes-plus.
Natural gas transmission compression facility means any permanent combination of
compressors that move natural gas at increased pressure from production fields or natural gas
processing facilities, in transmission pipelines, to natural gas distribution pipelines, or into
storage facilities. In addition, transmission compressor stations may include equipment for
liquids separation, natural gas dehydration, and storage of water and hydrocarbon liquids.
Non-pneumatic pump means any pump that is not pneumatically powered with
pressurized gas of any type, such as natural gas, air, or nitrogen.
Non-pneumatic pump fugitive emissions means natural gas released through
connectors and flanges of electric motor or engine driven pumps.
Non-steam aspirated flare means a flare where natural gas burns at the tip with natural
induction of air (and relatively lower combustion efficiency as may be evidenced by smoke
formation).
Offshore means tidal-affected borders of the U.S. lands, both state and Federal,
adjacent to oceans, bays, lakes or other normally standing water.
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Offshore petroleum and natural gas production facilities means any platform
structure, floating in the ocean or lake, fixed on ocean or lake bed, or located on artificial
islands in the ocean or lake, that houses equipment to extract hydrocarbons from ocean floor
and transports it to storage or transport vessels or onshore. In addition, offshore production
facilities may include equipments for separation of liquids from natural gas components,
dehydration of natural gas, extraction of H2S and CO2 from natural gas, crude oil and
condensate storage tanks, both on the platform structure and floating storage tanks connected
to the platform structure by a pipeline, and compression or pumping of hydrocarbons to
vessels or onshore. The facilities under consideration are located in both State administered
waters and Mineral Management Services administered Federal waters.
Offshore platform pipeline fugitive emissions means natural gas above the water line
released from piping connectors, pipe wall ruptures and holes in natural gas and crude oil
pipeline surfaces on offshore production facilities.
Open-ended line fugitive emissions means natural gas released from pipes or valves
open on one end to the atmosphere that are intended to periodically vent or drain natural gas
to the atmosphere but may also leak process gas or liquid through incomplete valve closure
including valve seat obstructions or damage.
Open-ended valve or Lines fOELs) means any valve, except pressure relief valves,
having one side of the valve seat in contact with process fluid and one side open to
atmosphere, either directly or through open piping.
Operating characteristics means normal flow rates, temperatures, pressures, stream
compositions typical of steady state or majority of operating time conditions.
Operating hours means the duration of time in which a process or process unit is
utilized; this excludes shutdown, maintenance, and standby.
Operating pressure means the containment pressure that characterizes the normal state
of gas and/or liquid inside a particular process, pipeline, vessel or tank.
Optimal operating conditions of fugitive emissions detection instruments means 1) for
IR emission detection intruments, weather, ambient light and reflective background
conditions that produce a strong signal in response to the presence of methane; and 2) for
OVA and TVA instruments, non-interference with air intake probe by atmospheric fluids or
materials such as rain, snow or dust.
Organic monitoring device means an instrument used to indicate the concentration
level of organic compounds exiting a control device based on a detection principle such as
IR, photoionization, or thermal conductivity.
Organic vapor analyzer (OVA') means an organic monitoring device (as defined
previously) that uses a flame ionization detector to measure the concentrations in air of
combustible organic vapors from 9 to 10,000 parts per million sucked into the probe.
Petroleum and natural gas industry means all companies, endeavors and facilities
involved in finding, accessing, producing, transporting, and processing fossil crude oil and
natural gas to produce and deliver products suitable for distribution to consuming customers.
Pitot tube means a right angled tube that measures the pressure differential between
the interior of the pitot tube and the surrounding air to measure velocity of gas. The
measurements are made by traversing the meter across the cross section of the conduit
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carrying the gas and profiling the flow across the cross section. The gas velocity is estimated
using a standard correlation of gas velocities to pressure differentials.
Platform fugitive emissions means natural gas released from equipment and
equipment components including valves, pressure relief valves, connectors, tube fittings,
open-ended lines, ports, and hatches. This does not include fugitive emissions from
equipment and components reported elsewhere for this rule.
Pressure relief device or pressure relief valve or pressure safety valve means a safety
device used to prevent operating pressures from exceeding the maximum allowable working
pressure of the process equipment. A common pressure relief device is but not limited to a
spring-loaded pressure relief valve. Devices that are actuated either by a pressure of less than
or equal to 2.5 psig or by a vacuum are not pressure relief devices.
Processing facility fugitive emissions means natural gas released from all components
including valves, flanges, connectors, open-ended lines, pump seals, ESD (emergency shut-
down) system fugitive emissions, packing and gaskets in natural gas processing facilities.
This does not include fugitive emissions from equipment and components reported elsewhere
for this rule, such as compressor fugitive emissions; acid gas removal, blowdown, wet seal
oil degassing, and dehydrator vents; and flare stacks.
Pump means a device used to raise, drive, or increase pressure and flow of liquid
streams.
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 fugitive emissions means natural 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 by positive displacement, employing linear movement of a shaft driving a
piston in a cylinder.
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 that escapes to the atmosphere.
Reciprocating compressor rod packing fugitive emissions means natural gas released
from a connected tubing vent and/or around a piston rod where it passes through the rod
packing case. It also includes emissions from uncovered distance piece, rod packing flange
(on each cylinder), any packing vents, cover plates (on each cylinder), and the crankcase
breather cap.
Re-condenser means heat exchangers that cool compressed boil-off gas to a
temperature that will condense natural gas to a liquid.
Re-gasification means the process of vaporizing liquefied natural gas to gaseous
phase natural gas.
Representative gas for flare stacks means a sample natural gas stream that is closest in
composition to the expected average composition of flared natural gas streams.
Residue gas means natural gas from which natural gas processing facilities liquid
products and, in some cases, nonhydrocarbon components have been extracted.
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Rotameter means a flow meter in which gas flow rate upward through a tapered tube
lifts a "float bob" to an elevation related to the gas flow rate indicated by etched calibrations
on the wall of the tapered tube.
Sensor means a device that measures a physical quantity/quality or the change in a
physical quantity/quality, such as temperature, pressure, flow rate, pH, or liquid level.
Shutdown means the cessation of operation of an affected source under this subpart,
or equipment required or used solely to comply with this subpart, for purposes including, but
not limited to, standby for future operation (either pressurized or depressureized), periodic
maintenance, replacement of equipment, or repair.
Simulation software means a calibrated, empirical computer program that uses
physical parameters and scientific laws to numerically simulate the performance variables of
a physical process, outputting such parameters as emission rates from which methane
emissions can be estimated.
Site means any combination of one or more graded pad sites, gravel pad sites,
foundations, platforms, or the immediate physical location upon which equipment is
physically located.
Sour natural gas means natural gas that contains significant concentrations of
hydrogen sulfide and/or carbon dioxide that exceed the concentrations specified for
commercially saleable natural gas delivered from transmission and distribution pipelines.
Source see "Emissions Source".
Standard conditions or standard temperature and pressure fSTP) means 60 degrees
Fahrenheit and 14.7 pounds per square inch absolute.
Standby means for an equipment to be in a state ready for operation, but not
operating.
Steady fugitive emissions means fugitive emission characterized by a nearly constant
and steady release rate.
Steam aspirated flare means steam injected into the flare burner tip to induce air
mixing with the hydrocarbon fuel to promote more complete combustion as indicated by lack
of smoke formation.
Storage station fugitive emissions means natural gas released from all components
including valves, flanges, connectors, open-ended lines, pump seals, ESD (emergency shut-
down) system emissions, packing and gaskets in natural gas storage station. This does not
include fugitive emissions from equipment and equipment components reported elsewhere
for this rule.
Storage tank means other vessel that is designed to contain an accumulation of crude
oil, condensate, intermediate hydrocarbon liquids, or produced water and that is constructed
entirely of non-earthen materials (e.g., wood, concrete, steel, plastic) that provide structural
support.
Storage tank fugitive emissions means natural gas vented when it flashes out of
liquids; this occurs when liquids are transferred from higher pressure and temperature
conditions upstream, plus working losses from liquid level increases and decreases during
filling and draining and standing losses (breathing losses) from diurnal temperature changes
and barometric pressure changes expanding and contracting the vapor volume of a tank.
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Storage wellhead fugitive emissions means natural gas released from storage station
wellhead components including but not limited to valves, OELs, connectors, flanges, and
tube fittings.
Stripping gas for glycol dehvdrator means natural gas injected into wet glycol in the
reboiler to cause absorbed water to vaporize at lower temperatures.
Sub-surface or subsurface facility means for the purposes of this rule, a natural gas
facility, such as a pipeline and metering and regulation station in a closed vault below the
land surface of the Earth.
Tanker means ocean-going vessel that transports crude oil, liquefied natural gas, or
petroleum products.
Tanker unloading means pumping of liquid hydrocarbon (e.g. crude oil, LNG) from
an ocean-going tanker or barge to shore storage tanks.
Toxic vapor analyzer (TVA) means an organic monitoring device that uses a flame
ionization detector and photoionization detector to measure the concentrations in air of
combustible organic vapors from 9 parts per million and exceeding 10,000 parts per million
sucked into the probe.
Trained technician means a person who has completed a vendor provided or
equivalent training program and demonstrated proficiency to use specific equipment for its
intended purpose, such as high volume sampler for the purposes of this rule.
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.
Transmission compressor station fugitive emissions means natural gas released from
all components including but not limited to valves, flanges, connectors, open-ended lines,
pump seals, ESD (emergency shut-down) system emissions, packing and gaskets in natural
gas transmission compressor stations. This does not include fugitive emissions from
equipment and equipment components reported elsewhere for this rule, such as compressor
fugitive emissions.
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.
Underground natural gas storage facility means a subsurface facility, including but
not limited to depleted gas or oil reservoirs and salt dome caverns, utilized for storing natural
gas that has been transferred from its original location for the primary purpose of load
balancing, which is the process of equalizing the receipt and delivery of natural gas.
Processes and operations that may be located at an natural gas underground storage facility
include, but are not limited to, compression, dehydration and flow measurement. The storage
facility also includes all the wellheads connected to the compression units located at the
facility.
Upstream of de-methanizer means any process stream or equipment containing a
process stream that has not passed through a de-methanizer at natural gas processing
facilities (i.e. natural gas rich in non-methane hydrocarbons).
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Valve means any device for halting or regulating the flow of a liquid or gas through a
passage, pipeline, inlet, outlet, or orifice; including, but not limited to, gate, globe, plug, ball,
butterfly and needle valves.
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
liquefied natural gas to supply transmission and distribution pipelines, or consumers with
natural gas.
Very high degree of accuracy means three significant digits of numerical
determination (e.g. 0.034 or 56.3).
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.
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 C: References
AGA (2008) Greenhouse Gas Emissions Estimation Methodologies, Procedures, and
Guidelines for the Natural Gas Distribution Sector.
API (2004) Compendium of Greenhouse Gas Emissions Estimation Methodologies for the
Oil and Gas Industry.
.
Bacharach, Inc. (2005) HiFlow® Sampler Natural Gas Leak Rate Measurement: Instruction
55-9017, Operation & Maintenance. < http://www.bacharach-inc.com/PDF/Instructions/55-
9017.pdf>.
Bureau of Economic Analysis (2007) Table 1.1.9. Implicit Price Deflators for Gross
Domestic Product. .
California Environmental Protection Agency (2007) Rulemaking to Consider Adoption of a
Regulation for the Mandatory Reporting of Greenhouse Gas Emissions.
.
CC AR (2007) General Reporting Protocol. .
The Climate Registry (2007) General Reporting Protocol for the Voluntary Reporting
Program. < http://www.theclimateregistrv.org/>.
EI A (2006) Underground Storage Field Level Data From EIA-191A.
.
EIA (2008) Official Energy Statistics from the U.S. Government Glossary.
.
EU ETS (2004) Establishing Guidelines for the Monitoring and Reporting of Greenhouse
Gas Emissions. < http://eur-
lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2004:059:0001:0074:EN:PDF>.
FERC (2008) Existing LNG Terminals. .
FLIR (2006) ThermaCAM® GasFindIR™ Brochure.
.
GRI (1992) GRI Report, Methane Emissions from the Natural Gas Industry, Volumes 1- 15.
Energy Information Agency (U.S. DOE)
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GRI (2008) GRI-GLYCalc™ Software Program.
.
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.
.
IPIECA (2003) Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions.
.
MMS (2000) Goads Summary Access File "Final GOADS Emissions Summaries".
.
NESHAP (accessed 2008) 40 CRF Part 63.
.
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. .
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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U.S. EPA (2008) Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006. U.S.
Environmental Protection Agency, Washington D.C. USEPA #430-R-08-005.c
U.S. EPA (2008) Natural Gas Methane Units Converter.
.
WCI (2008) WCI Meetings and Events.
.
World Resources Institute and World Business Council for Sustainable Development (2008)
Corporate Accounting and Reporting Standard, .
WRAP (2005) Oil and Gas Emissions Inventories for the Western States.
.
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