United Stdtes
Environmental Protection
Agency
GRi-94 / 0257.23
EPA-600/R-96-0801
June 1996
PB97-142970
METHANE EMISSIONS FROM THE
NATURAL GAS INDUSTRY
\ ,>lume 6: Vented and Combustion Source Summary
Energy Information Administration (U. S. DOE)
National Risk Management
Research Laboratory
Research Triangle Park, fsJC 27711
REPRODUCED fiY:
U.S. Daparlmont ofCommarc
Nationni Tachnlcal {nfDimstion So
Springfiold, VH-fiinia 221^1
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TECHNICAL REPORT DATA
(Please read Insfmctiotis on *kt f*.ver*c before contpi
i. .REPORT NO.
EP.A-600/R-96-080f
Hi I
4. TITLE AND SUBTITLE
Methane Emissions from :he Natural Gas Industry,
Volumes 1-15 (Volume 6: Vented and Combustion
Source Summary)
5. REPORT DATE
June 199C
6. PERFORMING ORGANIZATION CODE
7. AUTHORIS) L> Campbell, M. Campbell, M. Cowgill, D. Ep-
person, ivl. Hall, M.Harrison, K. Hummel, D, Myers,
T. Shires, B. Stapper, C. Stapper, J. Wessels, and *
6. PERFORMING ORGANIZATION REPORT WO.
DCN 96-263-081-17
10 PROGRAM ELEMENT NO,
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian International LLC
P. O. Box 201088
Austin, Texas 78720-1088
11. CONTRACT/GRANT NO.
5091-251-2171 (GRI)
68-01=0031 (EPA)
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air Pollution Prevention and Control Division
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 3/91-4/96
14. SPONSORING AGENCY CODE
EPA/600/13
ie.SUPPLEMENTARY NOTES EPA project officer is D. A. Kirnhgessner,MD-63,919/541-4021.
Cosponsor GRI project officer is R. A. Lott, Gas Research Institute, 8600 West Bryn
Mawr Ave., Chicago, IL 60631. (*)H. Williamson (Block 7).
15-volume report summarizes the results of a comprehensive program
to quantify methane (CK4) emissions from the IJ. S. natural gas industry for the base
year. The objective was to determine CH4 emissions from the wellhead and ending
downstream at the customer's meter. The accuracy goal was to determine these
emissions within -i-/-0. 5% of natural gas production for a 90% confidence interval. For
the 1992 base year, total CB4 emissions for the U. S, natural gas industry was 314
+ /- 105 Bscf (6.04 +/- 2.01 Tg). This is equivalent to 1.4 +/- 0.5% of gross natural
gas production, and reflects neither emissions reductions (per the voluntary Ameri-
Gas Association/EPA Star Program) nor incremental increases (due to increased
gas usage) since 1992. Results from this program were used to compare greenhouse
emissions from the fuel cycle for natural gas, oil, and coal using the global war-
ming potentials (GWPs) recently published by the Intergovernmental Panel on Climate
Change (IPCC). The analysis showed that natural gas contributes less to potential
global warming than coal or oil, which supports the fuel switching strategy suggested
by the IPCC and others. In addition, study results are being used by the natural gas
industry to reduce operating costs while reducing emissions.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIFRS/OPCN ENDED TERMS
cos AT I Field/Group
Pollution
Emission
Greenhouse Effect
Natural Gas
Gas Pipelines
Methane
Pollution Prevention
Stationary Sources
Global Warming
13 B
14G
04A
21D
15E
07C
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (Tliis Report)
Unclassified
21, NO OF PAGES
20. SECURITY CLASS (1 his page)
EPA Form 222O-1 (9-?:;)
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FOREWORD
The U. S. Environmental Protection Agency is charged by Congress with pro-
tecting the Nation's land, air, and water resources. Under a mandate of national
environmental laws, the Agency strives to formulate and implement actions lead-
ing to a compatible balance between human activities and the ability of natural
systems to support and nurture life. To meet this mandate, EPA's research
program is providing data and technical support for solving environmental pro-
blems today and building a science knowledge base necessary to manage our eco-
logical resources wisely, understand how pollutants affect our health, and pre-
vent or reduce environmental risks in the future.
The National Risk Management Research Laboratory is the Agency's center for
investigation of technological and management approaches for reducing risks
from threats to human health and the environment. The focus of the Laboratory's
research program is on methods for the prevention and control of pollution to air,
land, water, and subsurface resources; protection of water quality in public water
systems; remediation of contaminated sites and groundwater; and prevention and
control of indoor air pollution. The goal of this research effort is to catalyze
development and implementation of innovative, cost-effective environmental
technologies; develop scientific and engineering information needed by EPA to
support regulatory and policy decisions; and provide technical support and infor-
mation transfer to ensure effective implementation of environmental regulations
and strategies.
This publication has been produced as part of the Laboratory's strategic long-
term research plan. It is published and made available by EPA's Office of Re-
search and Development to assist the user community and to link researchers
with their clients.
E. Timothy Oppelt, Director
National Risk Management Research Laboratory
EPA REVIEW NOTICE
This report has been peer and administratively reviewed by ihe U.S. Environmental
Protection Agency, and approved for publication. Mention of trade names or
commercial products does not constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Information
Service, Springfield, Virginia 22161.
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EPA-600/R-96-080f
June 1996
METHANE EMISSIONS FROM
THE NATURAL GAS INDUSTRY*
VOLUME 6: VENTED AND COMBUSTION SOURCE SUMMARY
FINAL REPORT
Prepared by:,
- Theresa M. Shires
Matthew R. Harrison
.Radian International LLC
8501 N. Mopac Blvd.
\ P.O. Box 201088
Austin, TX 78720-1088
DCN: 95-263-081-01
« ~ For ~ ~ _ -
GRI Project Manager:, Robert A. Lott
GAS RESEARCH INSTITUTE
Conttact No. 5091-251-2171 - .
8600 West Bryn Mawr Ave.
__ Chicago, IL 60631
- and - r
EPA Project Managers David A. Kirchgessner
U.S. ENVIRONMENTAL PROTECTION AGENCY
Contract No. jS8-Dl-003i
National Risk Management Research Laboratory
Research Triangle Park, NC 27711
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LEGAL NOTICE: This report was prepared by Radian International LLC as an account
of work sponsored by Gas Research Institute (GUI) and the U.S. Environmental Protection
Agency (EPA). Neither EPA, GRI, members of GRI, nor any person acting on behalf of
either:
a. Makes any warranty or representation, express or implied, with respect to the
accuracy, completeness, or usefulness of the information contained in this rsport. or
that the use of any apparatus, method, or process discio,=ed in this report may not
infringe privately owned rights; or
b. Assumes any liability with respect to the use of, or for damages resulting from the
use of, any information, apparatus, method, or process disclosed in this report.
NOTE: EPA's Office of Research and Development quality assurance/quality control
(QA/QC) requirements are applicable to some of the cotmt data generated by this project.
Emission data and additional count data are from industry or literature sources, and are not
subject to EPA/ORD's QA/QC policies. In all cases, data and results were reviewed by the
panel of experts listed in Appendix D of Volume 2.
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RESEARCH SUMMARY
Title
Contractor
Principal
Investigators
Report Period
Objective
Technical
Perspective
Results
Methane Emissions From Vented and Combusted
Sources
Final Report
Radian International LLC
GRI Contract Number 5091-251-2171
EPA Contract Number 68-D1-0031
Theresa M. Shires
Matthew R. Harrison
March 1991 - June 1996
Final Report
This report summarizes methane emissions from vented and combusted
sources. Significant sources of vented and combusted emissions are
discussed, as well as miscellaneous minor sources of emissions. In
addition, documentation for the methane compositions used for each
industry segment is provided. This report also discusses inconsistencies
hi reported vented and flared emissions reported by other sources.
The increased use of natural gas has been suggested as a strategy for
reducing the potential for global warming. During combustion, natural
gas generates less carbon dioxide (CO2) per unit of energy produced than
either coal or oil. On the basis of the amount of CO2 emitted, the
potential for global warming could be reduced by substituting natural gas
for coal or oil. However, since natural gas is primarily methane, a potent
greenhouse gas, losses of natural gas during production, processing,
transmission, and distribution could reduce the inherent advantage of its
lower CO2 emissions.
To investigate this, Gas Research Institute (GRI) and the U.S.
Environmental Protection Agency's Office of Research and Development
(EPA/ORD) cofunded a major study to quantify methane emissions from
U.S. natural gas operations for the 1992 base year. The results of this
study can be used to construct global methane budgets and to determine
the relative impact on global warming of natural gas versus coal and oil.
Vented emissions account for approximately 94 Bscf of methane
emissions annually. Compressor exhaust is the primary source of
111
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combustion emissions, contributing approximately 25 Bscf of methane
emissions annually.
Based on data from the entire program, methane ^missions from natural
gas operations are estimated to be 314 ± 105 Bscf for the 1992 base
year. This is about 1.4 ± 0.5% of gross natural gas prodactioii. The
overall program also showed that the percentage of methane emitted for
an incremental increase in natural gas sales would be significantly lower
than the baseline case.
The project reached its accuracy goal and provides an accurate estimate
of methane emissions that can be used to conduct methane inventories
and analyze fuel switching strategies.
Technical Vented emissions primarily result from three categories: 1) pneumatic
Approach devices, 2) blow and purge emissions, and 3) dehydrator emissions.
Combusted emissions result from the incomplete combustion of methane
in burners, flares, and engines.
Vented and combusted emissions are typically considered unsteady
emission sources, that is, sources with highly variable emissions. These
emission sources vary from company to company and site to site,
because of different maintenance practices and operating conditions.
Therefore, it is impractical to measure every source continuously for a
year. Each unsteady emission source requires a unique set of equations
and gathered data based on the equipment type, various components, and
operating modes to produce an emissions factor. Data on unsteady
emissions were gathered at multiple sites in each segment of the
industry: production, gas processing, transmission, storage, and
distribution.
This report summarizes methane emissions from significant, as well as
minor miscellaneous sources of vented and combusted emissions. In
addition, this report serves to document the data sources used to
determine methane compositions for the various industry segments.
Finally, a discussion of inconsistencies in reported vented and flared
emissions is provided to support the decision for using a bottom-up
approach in this project to more accurately account for emissions from
these sources.
Project For the 1992 base year the annual methane emissions estimate for the
Implications U.S. natural gas industry is 314 Bscf ± 105 Bscf (± 33%). This is
equivalent to 1.4% ± 0.5% of gross natural gas production. Results from
this program were used to compare greenhouse gas emissions from the
fuel cycle for natural gas. oil, and coal using the globJ warming
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potentials (GWPs) recently published by the Intergovernmental Panel on
Climate Change (IPCC). The analysis showed that natural pt-.s
contributes Jess to potential global warming than coal or oil, which
supports the fuel switching strategy suggested by IPCC and others.
10 Si.
In addition, results from this study are being used by die natural gas
industry to reduce operating costs while reducing emissions. Some .0 IN
companies are also participating in the Natural Gas- Star program, a
voluntary program sponsored by EPA's Office of Air and Radiation in 3.0 D/'
cooperation with the American Gas Association to implement cost-
effective emission reductions and to report reductions to the EPA. Since 4.0 RI
this program was begun after the 1992 baseline year, any reductions in
methane emissions from this program are not reflected in this study's 4. 1
total emissions. 4.'
Robert A. Lott
Senior Project Manager, Environment and Safety 5.0 Mi
6.0
A:
A
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TABLE OF CONTENTS
Psgi*
1.0 SUMMARY 1
2.0 INTRODUCTION 2
3.0 DATA COLLECTION , 4
4.0 RESULTS 8
4.1 Compressor Exhaust 8
4.2 Pneumatic Devices 10
4.3 Chemical Injection Pumps 12
4.4 Dehydrator Vents 13
4.5 Dehydrator Glycol Pumps 14
4.6 Blow and Purge 15
5.0 MISCELLANEOUS MINOR CATEGORIES 18
5.1 Burners 18
5.2 Flares 20
5.2.1 Combustion Efficiency 21
5.2.2 Total Natural Gas Flow to Gas Industry Flares 24
5.3 Acid Gas Recovery Vents , 27
5.4 Salt Water Tanks 28
5.5 Drilling 29
5.6 Drips 30
5.7 Sampling 31
6.0 REFERENCES 32
APPENDIX A - Methane Composition , A-l
APPENDIX B - Reported "Vented and Flared" Data B-l
VI
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LIST OF TABLES
Page
3-1 Emission Sources 6
3-2 Emission Source Groups by Type 7
4-1 Summary of Unsteady Emissions 9
4-2 Blow and Purge Emission Results 17
5-1 Burner Fuel Gas Activity Factor 19
5-2 Summary of Previous Flare Combustion Efficiency Studies 22
5-3 Non-Combusted Emissions from Production and Gas Processing
(GRI/EPA Estimate Basis) 25
5-4 Maximum Flaring Emissions 27
5-5 Salt Water Tank Emissions 2^
A-?. Methane Composition by Industry Segment A-2
A-2 Average State Methane Content and Production Rate A-4
A-3 Methane Composition of Production Gas A-5
A-4 Methane Composition hi Gas Processing A-5
B-l Comparison of 45-1 Reports B-9
B-2 1991 Flaring Permits for Oklahoma B-10
B-3 Supply and Disposition of Gas hi the United States—1989 B-l3
VII
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1.0 SUMMARY
This report is one of several volumes that provides background information
supporting the Gas Research Institute and U.S. Environmental Protection Agency, Office of
Research and Development (GRI-EPA/ORD) methane emissions project. The objective of
this comprehensive program is to quantify tne methane emissions from the gas industry for
the 1992 base year to within ± 0.5% of natural gas production starting at. the wellhead and
ending immediately downstream of the customer's meter.
This report summarizes methane emissions from vented and combustion
sources. Vented emissions primarily result from three categories: 1) pneumatic devices, 2)
blow and purge emissions, and 3) dehydrator emissions, which combined account for
approximately 94 Bscf of methane emissions annually. Combustion emissions result from
the incomplete combustion of methane in burners, flares, and engines. Compressor engine
exhaust is the only significant source of methane in this category, accounting for
approximately 25 Bscf of methane emissions annually.
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2.0 INTRODUCTION
For this project, sources of methane emissions from the natural gas industry
were classified as follows:
Vented - Vented emissions are Intentional releases from equipment
blowdown lor maintenance, releases from emergency depressuring
(from safety valves and station emergency blowdown)- direct venting
of gas used to power equipment (such as pneumatic devices), or
accidental releases due to mishaps (such as pipeline dig-ins).
Combustion - Combustion emissions refer to methane that enters the
atmosphere due to the incomplete combustion of natural gas.
Examples are methane in compressor engine exhaust and methane
from flare stacks and burners.
Fugitive - Tugitive emissions are unintentional leaks from sealed
surfaces (such as valve stem packing, flange gaskets, compressor shaft
seals, and pipelines).
This report summarizes emissions from vented and combustion sources.
Vented and combustion emissions are typically considered "unsteady." Unsteady emitters
are defined as sources with highly variable emissions, such as a pneumatic device on an
isolation valve or a maintenance activity that requires blowdown. These emission sources
vary from company to company and site to site, because of different maintenance practices
and operating conditions.
In contrast, emission sources with continuous bleed rates, or with reasonably
steady bleed rates over a typical measurement tune, are considered "steady" sources.
Fugitive emissions are generally considered steady. Extensive measurements of fugitive
emissions have been made in this and other studies in all segments of the gas industry.1'2'3
Section 3 of this report discusses daH collection techniques used to estimate
unsteady emissions. Results from vented and combustion sources considered significant are
presented in Section 4. Details on emission estimates for compressors, pneumatic devices,
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dehydrators, chemical injection pumps, mishaps, etc. are available in other volumes.'1'"'7'8-9
Section 5 discusses miscellaneous minor emission sources. Documentation supporting the
methane compositions used for each industry segment is provided in Appendix A. This
report also discussed inconsistency in vented and flared emissions in Appendix B.
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3.0 DATA COLLECTION
This GRI/EPA study calculated emission factors for unsteady emission
sources, rather than measuring them. Each unsteady source requires a unique set of
equations and gathered data based on the equipment type, various components, and
operating modes to produce the emission factor quantity. However, all sources require the
following general information:
1) A detailed technical description of the source, identifying the
important emission-affecting parameters (i.e., equipment components
and operating modes). This was generally accomplished through a
source characterization report.
2) Data to estimate the volume of natural gas released and the frequency
of releases from multiple site visits or existing reports.
3) Data on gas composition (percent methane) in various industry
segments (production, gas processing, transmission, and distribution).
Details on the methane composition results are provided in Appendix
A.
Step 1 was accomplished by researching each particular source and gathering
manufacturer, operator, and site data so that a full technical description of the important
emission characteristics of the source category could be written. Using this description,
data on the emission-affecting characteristics of each source were gathered through site
visits or existing resources.
For many emission sources, the frequency of release events was measured
(such as strokes/minute for pneumatic actuators); but for extremely infrequent releases (such
as equipment maintenance blowdowns), the frequency was estimated by gas industry field
personnel. The emission volume per event was not measured for most sources (as in the
case of compressor exhaust methane) but was often calculated using gathered site data,
existing reports, and first principles.
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During this study, data on unsteady emissions were gathered at multiple sites
in each segment of the industry: production, gas processing, transmission, storage, and
distribution. Details on the industry segments and boundaries are provided in Volume 5 on
the activity factors.10 The site visits and literature searches allowed construction of a matrix
that shows all the emission sources within the gas industry grouped by process segment and
operation mode. Table 3-1 shows this grouping. The industry characterization also allowed
a grouping of sources by emission type, as shown in Table 3-2.
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TABLE 3-1. EMISSION SOURCES
Industry Segment
Production
Gas Processing Plants
Transmission and Storage
Distribution
Operating Mode
Start Up
Normal Operations
Maintenance
Upsets/Mishaps
Start Up
Normal Operations
Maintenance
Upsets/Mishaps
Start Up
Normal Operations
Maintenance
Upsets/Mishaps
Start Up
Normal Operations
Maintenance
Upsets/Mishaps
Emission Sources
(Equipment or Activities)
Drilling (mud emissions)
Well completion testing
Fugitives
Pneumatic devices
-control valves
Chemical injection pumps
Glycoi dehydrators
Compressor exhaust
Compressor starts
Well bore maintenance
Blow and purge
Emergency blowdowns
Dig-ins
Not applicable or negligible activity
Fugitives
Pneumatic devices
- isolation valves
Glycoi dehydrators
Acid Gas Recovery vent,
Engine exhaust
Compressor starts
Blow and purge
Emergency blowdowns
NO MISHAPS
Not applicable or negligible activity
Fugitives
Pneumatic devices
- control valves
- isolation valves
Glycoi dehydrators
Engine exhaust
Compressor starts
Blow and purge
Emergency blowdown
Dig-ins
Fugitives
Pneumatic devices
- control valves
- isolation valves
Glycoi dehydrators
Engine exhaust
Compressor starts
Blow and purge
Emergency blow-down
Dig-ins
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TABLE 3-2. EMISSION SOURCE GROUPS BY TYPE
Source
Type
Emission Soi trees
Combustion Unsteady Engine exhaust (compressors and other gas-driven engines)
Sources Flares
B'irners
Vented Sources Unsteady
Pneumatic devices
Chemical injection pumps
Glycol circulation pumps
Glycol dehydrator vent
Acid Gas recovery (AGR) vent
Blow and purge
(for start up, maintenance, and
upsets/emergency conditions)
Mishaps
Fugitive
Sources
Steady Leaks from sealed surfaces
(flange gaskets, valve stem packing, valve seats
open to the atmosphere, pressure relief valve
seats, compressor seals, etc.)
Leaks from small holes in pipelines
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4.0 RESULTS
This section reviews the characterization results on the major unsteady
categories. (Major categories were defined as any source over 1 Bscf.) Minor categories
are discussed in Section 5. Table 4-1 summarizes the results determined for each category of
unsteady emissions in ec"-.h industry segment. Details on the techniques used and the data
gathered for each of the unsteady emission categories are provided in other documents of this
multi-volume set on methane emissions.4'6'8'9'11-12
4.1 Compressor Exhaust
Methane emitted to the atmosphere in compressor engine exhaust is a
significant source of unsteady emissions and accounts for approximately 25 Bscf of methane
emissions.4 Methane emissions result from the incomplete combustion of the natural gas
fuel, which allows some of the methane hi the fuel to exit in the exhaust stream. There are
two primary types of compressor drivers: 1) reciprocating gas engines, and 2) gas turbines.
A few compressors in the industry are driven by other means such as electrical motors, but
the majority are natural gas-fueled drivers. In addition to compressors, there are some
natural gas drivers that operate site electrical generators for gas plants and compressor
stations.
Reciprocating engines emit more methane per horsepower or per unit of fuel
consumed than turbine drivers: 0.24 scf/HP«hr for reciprocating versus 0.0057 scf/HP«hr for
turbines. Reciprocating engines account for over two-thirds of all installed horsepower in the
gas industry (100,500 MMhp»hr compared to 44,300 MMhp»hr for gas turbines). Therefore,
reciprocating engines account for 98% of the methane emissions for this category.
Emissions were determined by analyzing and combining several databases. A
GRI database, the GRI TPANSDAT compressor module,13 contains data from American Gas
Association (A.G.A.) on types and models of compressors in use, as well as data on
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TABLE 4-1. SUMMARY OF UNSTEADY EMISSIONS
Annual Methane :
Source ;Emissaons, Bscf 90% Confidence Interval
Oppressor Exhaust
Production 6.6 ± 200%
Gas Processing 6.9 ± 130%
Transmission 11.4 ±15%
Pneumatic Device?
Production 31.4 ±65%
Gas Processing 0.1 ± 64%
Transmission 14.1 ± 60%
Chemical Injection Pumps 1.5 ±203%
Dehydrator Vents
Production 3.4 ± 193%
Gas Processing 1.05 ± 208%
Transmission 0.10 ± 392%
Storage 0.23 ± 166%
Dehydrator Glycol Pumps
Production 11.0 ±110%
Gas Processing 0.17 ±228%
Transmission
Storage
Acid Gas Recovery Vents 0.82 ± 109%
Blow and Purge
Production
Gas Processing
Transmission
Distribution
6.6
3.0
18.5
2.2
± 329%
±262%
± 177%
± 1,783%
TOTAL 119 ± 54%
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compressor driver exhaust from the Southwest Research Institute (SwRI). A.G.A. gathers ii.s
data from government agencies, such as DOE and FERC, and from surveys of its member
companies hi transmission and distribution. SwRI data were generated through actual field
testing. The data were combined to generate emission factors for this project by correlating
compressor driver type, methane emissions, fuel use rate, and annual operating hours for 775
reciprocating engines and 86 gas turbines.
Horsepower°hour activity factors were developed for each industry segment
using TRANSDAT, FERC, A.G.A., company databases, and site-visit data. TRANSDAT
includes horsepower data for 7,489 reciprocating engines and 793 gas turbines in
transmission. Transmission operating hours were based on FERC data for 1992 and one
company's data for 524 reciprocating engines and 89 gas turbines. Storage horsepower was
based on A.G.A. data aid operating hours are based on data from 11 storage stations. Since
national totals for transmission and storage horsepower are available, no industry
extrapolation was necessary for these activity factors. Production horsepower°hours were
based on one company's data for 516 reciprocating engines. Horsepower and operating
hours for the gas processing segment were based on 10 site visits and company data for 18
gas processing plants. Horsepowereho
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There are two primary types of these devices: 1) control valves thai regulate
flow, and 2) isolation valves that block or isolate equipment and pipelines. Of the two main
types, isolation valves typically have lower annual emissions, although the emission rate per
actuation can be large. This is because isolation valves are moved infrequently, for
emergency or maintenance activities that require isolating a piece of equipment or section of
pipeline. Alternatively, control valves typically move frequently to make adjustments for
changes in process conditions, and some types of control valves bleed gas continuously.
Each segment of the industry has very different practices regarding the
pneumatic devices, as described below:
Production
The production segment accounts for the majority of pneumatic emissions:
31.4 Bscf, or 69% of all pneumatic emissions. Compressed air is rarely used as a pneumatic
operating medium in the production segment, since compressed air requires electricity at the
often remote well sites, and since gas is readily available and less expensive. A typical
production pneumatic device releases 126 Mscf methane annually and there are an estimated
249,000 pneumatic devices associated with natural gas production.
Gas Processing
Pneumatic emissions from the gas processing segment are very small: 0.12
Bscf annually, or approximately 1% of all pneumatic emissions. Only one-half (56%) of the
gas processing plants participating in this project use natural gas to operate pneumatic
controllers and isolation valv^- other sites use compressed air or electric motors. The
natural gas-powered isolacion valves in this industry segment are operated infrequently
(once/month or once/year), so the annual emissions per site are relatively small
(approximately 165 Mscf of methane per gas processing plant).
11
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Transmission/Storage
Pneumatic emissions from the transmission compression stations and storage
stations account for 14.1 Bscf annually, or 31% of pneumatic emissiors. Ir this industry
segment, most of the pneumatics are gas-actuated isolation valves. There are a few
pneumatic control valves used to reduce pressure or to control liquid flow from a separator
or scrubber. The annual methane emissions from a transmission pneumatic device are 162
Mscf, and there are apj.' xirnately 87,000 of these devices nationally.
Distribution
Pneumatic emissions for the distribution segment are included in the meter and
regulation station "fugitive" emission factor.2
4.3 Chemical Injection Pumps
Chemical injection pumps .^e a source of unsteady emissions and account for
1,5 Bscf of annual methane emissions.8 Gas-driven chemical injection pumps use gas
pressure to move a piston which pumps the chemical on the opposite end of the piston shaft;
the power gas is then vented to the atmosphere at the end of the stroke. The power gas may
be natural gas or compressed air. Two types of chemical injection pumps were observed: 1)
piston pumps, and 2) diaphragm pumps. The larger diaphragm pumps emit more gas per
stroke, and they are used to pump a higher flow rate of chemical or to pump the chemical.
into high pressure equipment.
Chemical injection pumps are used to add chemicals such as corrosion
inhibitor, scale inhibitor, biocidc, demulsifier, clarifier, and hydrate inhibitor to operating
equipment. These additives protect the equipment or help maintain the flow of gas. The
vast majority of these pumps exist hi the production segment, located at the well sites, so
that the chemical can protect all of the downstream and downhole equipment. As with
12
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pneumatic control valves, the chemical injection pumps in production are primarily powered
by natural gas.
In the production segment, significant regional differences exist. Depending
on the gas composition and conditions, some regions use very few pumps, while other
regions use the pumps frequently. Many pumps also iiave seasonal operation since they
protect against hydrate formation, which whiter temperatures exacerbate. Approximately
17,000 chemical injection pumps are associated with natural gas production. A typical
methane emission rate is 248 scfd per pump, based on site and manufacturer data.
Only a few pumps exist hi the gas processing and transmission segments. The
pumps that do exist are powered by compressed air at these stations, and as a result, have no
methane emissions.
4.4 Dehydrator Vents
Glycol dehydrator vents are a ^oant source of methane emissions and
account for 4.8 Bscf of methane emissions annually.11 The majority of the glycol
dehydrators are located in production, but dehydrators are also present in the gas processing,
transmission, and storage segments of the natural gas industry. Methane emissions are
higher in the production segment (71% of the total emissions are attributed to glycol
dehydrator vents) due to the high activity factor for this segment and the lack of flash tanks
hi most production dehydrators.
Glycol dehydrators remove water from the natural gas through continuous
glycol absorption. The water-rich glycol is then regenerated, or heated, which drives the
water back out of the glycol. The glycol also absorbs some other compounds from the gas,
including a small amount of methane. The methane is driven off with the water in the
regenerator and vented to the atmosphere.
13
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The important ^mission-affecting variables for dehydrators are: gas
throughput, use of a flash tank, use of stripping gas, and use of vent controls routed to a
burner. An emission factor was established for glycol dehydrator regenerator vents using
three sources of riata: 1) computer simulations of dehydrator operations using first
principles; 2) data from actual on-line analyzer samples taken from regenerator vents: and 3)
multiple site visits. The resulting annual methane emission factors are: 276 scf/MMscf
throughput for production, 122 scf/MMscf for gas processing, 94 scf/MMscf for
transmission, and 117 scf/MMscf for storage. For each industry segment, the emission
factor v/as combined with an activity factor to generate the national emission rats, where the
activity factors are based on the annual volume of gas dehydrated (12.4 Tscf for production,
8.6 Tscf for gas processing. 1.1 Tscf for transmission, and 2.0 Tscf for gas storage).
4.5 Dehydrator Giycol Pomps
Glycol dehydrator circulation pumps are a significant source of unsteady
emissions and account for approximately 11 Bscf of annual methane emissions.12 These
pumps use the high pressure of the rich glycol from the absorber to power pistons that pump
the low-pressure, lean glycol from the regenerator. The pump configuration pulls additional
gas from the absorber along with the rich glycol (more gas than would flow with the rich
glycol if conventional electrical pumps and level control were used). This gas is emitted
along with other absorbed methane through uie dehydrator vent stack.
Gas-powered glycol circulation pumps are common throughout the industry,
even in sites where electrical pumps are the standard for other equipment. The dehydrator
equipment is often specified as a separate bid package, and the vendors most often use the
Kimray gas pump as their standard pumping unit. The pumps are an integral part of the
glycol dehydrator unit and their emissions occur through the same point. However, the
pumps are the cause for most of the methane emissions from dehydrators, so they are
considered separately.
14
-------
Unlike chemical injection pumps which vent the driving gas directly to the
atmosphere, dehydrator pumps pass the driving gas along with the wet glycol to the reboiler.
Therefore, methane emissions from the pump depend on the design of the dehydrator, since
gas recovery on the dehydrator will also recover gas from the pump. The demographics
generated for the glycol dehydrator control system (flash drum recovery and vent vapor
recovery) were also used to determine the net emission rate for glycol pumps.
Based on a gas iliroughput basis, emission factors for glycol pumps were
estimated to be 992 scf msthane/MMscf for production and 178 scf/MMscf for gas
processing. The corresponding annual activity factors are 1.1 Tscf and 0.96 Tscf,
respectively.
4.6 Blow and Purge
Blow and purge is a large source of unsteady emissions and accounts for
approximately 30 Bscf of methane emissions annually.9 Blow (or blowdown) gas refers to
gas that is vented due to maintenance, routine operations, or emergency conditions. A piece
of process equipment or an entire site is isolated from other gas-containing equipment and
depressured to the atmosphere. The gas is discharged to the atmosphere for one of the
following reasons:
1) Maintenance Blowdown - the gas is vented from equipment to eliminate
the flammable material inside the equipment, thus providing a safer
working environment for workers that service the equipment or enter
the equipment.
2) Emergency Blowdown - the gas is vented from a site to eliminate a
potential fuel source. For example, if an equipment fire begins at a
compressor station, the station emergency shutdown and emergency
blowdown system blocks the station away from the pipelines ?nd
discharges the gas inside the station, thus reducing the fuel that could
feed the fire.
15
-------
The factors that affect the volume of methane blowdown released to the atmosphere are:
frequency, volume of gas blowdown per event, and the disposition of the blowdown gas.
Blowdown from maintenance releases was determined for each equipment
category: compressor blowdown, compressor starts, pipeline blowdown, vessel blowdown,
gas wellbore blowdown, and miscellaneous equipment blowdown. Emergency blowdown
refers to the unexpected release of gas by a safety device, such as a pressure-relief valve
(PRV) on a vessel or the automatic shutdown/emergency blowdown of a transmission
compressor station. Dig-ins, which are pipeline ruptures caused by unintentional damage,
were also classified as an emergency release of gas. Table 4-2 summarized the emission
factors and activity factors for the various blow and purge sources.
Emission estimates for each industry segment were based on data from one or
more of the following sources: 1) site-visit data; 2) company-tracked data; 3) company
studies; and 4) equipment characteristics. Data quality in the transmission segment was
considered superior since it was based upon rigorous company-tracked data. Gas-processing
data were extrapolated from transmission data based upon the similarities between gas plant
compression and transmission compressor stations. Distribution segment data were
considered good since they were based upon company studies. Production data were
considered poor (and may be underestimated) since they are based upon operator
recollections of blowdow- frequency gathered during site visits.
16
-------
TABLE 4-2. BLOW AND PURGE EMISSION RESULTS
Industry Segment
Annual Emission Factor
Activity Factor
National Annual
Methane Emission
Rate, Bscf
Production:
Gas Wells Unloading
Compressor Slowdowns
Compressor Starts
Pipeline Miles
Production Vessels
Completion Flaring
Well Workovers
PRV Releases
BSD Releases
Dig-ins
49,570 ± 344% scf/wdl
3,774 ± 147% scf/comp.
8,443 ± 157% scf/comp.
309 ± 32% scf/mile
78 ± 266% scf/vessel
733 ± 200% scf/completion
2,454 ± 459% scf/workover
34 ± 252% scfy/PRV
256,888 ± 200% scf/platform
669 ± 1,925% scf/mile
114,139 ±45% wells
17,112 ± 52% compressors
17,112 ± 52% compressors
340,000 ± 10% miles
255,996 ± 26% vessels
844 ± 10% completions
9,329 ± 258% workovers
529,440 ±53% PRVs
1,115 ± 10% platforms
340,000 ± 10% miles
5.66 ± 380%
0.065 ± 173%
0.144 ± 184%
0.105 ± 34%
0.020 ± 276%
0.0006 ± 201%
0.023 ± 1,296%
0.018 ± 289%
0.286 ± 201%
0.23 ± 1,934%
Gas Processing
4,060 ± 322% Mscf/plant
726 ±2% plants
2.95 ± 262%
Transmission and Storage:
Stations
Pipeline Miles
4,359 ± 322% Mscf/station
31.6 ± 343% Mscf/mile
2,175 ±8% stations
284,500 ±5% miles
9.48 ± 263%
9.00 ± 236%
Distribution:
PRV Releases
Dig-ins
Blowdowns
0.050 ± 3,914% Mscf/main
mile
1.59 ± 1,922% Mscf/mile
0.102 ± 2.521 Mscf/mile
836,760 ±5% miles main
1,297,569 ±5% miles
1,297,569 ±5% miles
0.04 ± 3,919%
2.06 ± 1,925%
0.13 ± 2,524%
-------
5.0 MISCELLANEOUS MINOR CATEGORIES
There were many emission categories that contributed negligible amounts of
methane (less than 1 Bscf). Although small, these categories are discussed in order to
provide a complete picture of the industry, but these emission sources are not itemized hi the
summary of annual emissions reported by this study. Emissions from a few other minor
categories are quantified in Volume 7 on blow and purge activities.9
5.1 Burners
Burner combustion refers to the controlled burning of natural gas in order to
add heat to a process stream. Burners combine ah" and gas in a controlled manner to
maximize combustion efficiency. In the natural gas industry, burners are used in all industry
segments. In the production segment, a high-pressure gas well requires a choke and an in-
line heater to avoid freezing water hi the line from the pressure drop flash. Glycol
dehydrators, which are present in all industry segments, require a reboiler burner to heat and
regenerate the glycol. Above-ground liquefied natural gas (LNG) facilities may have boilers
or hot oil furnaces for methane vaporization. Some gas plants may have additional burners
hi boilers and other sources.
Non-combusted methane may be emitted by burners hi two ways: 1) since
combustion is not 100% efficient, there is a Finall amount of methane that escapes from the
burner uncombusted, and 2) if the burner has a flameout, all of the methane sent to the
burner can be emitted uncombusted. This report has assumed that flameout emissions are
negligible, based upon interviews with gas industry personnel. Therefore only incomplete
combustion emissions are calculated hi this section.
The combustion efficiency cf natural gas hi burners was determined from
Section 1.4 of the U.S. EPA's AP-42 document.14 The burners hi the natural gas industry
fall under the industrial furnace category (between 10 and 100 MMBtu/hr of fuel fired). AP-
-------
42 shows that uncontrolled methane emissions from natural gas burners in industrial boilers
are three pounds of methane per million cubic feet of fuel. The accuracy of these numbers is
low, since AP-42 gives the data a rating of "C."
In general, annual averages of combustion emissions are generated by
estimates of the total gas flow to the burners, combustion efficiency, and flameout frequency
and duration. The activity factor for this category is the total amount of burner fuel used hi
the industry. Nationally published numbers are available that show the total annual "lease
and plant fuel use" and "pipeline fuel use," as shown in Table 5-1.1S>16 However,
compressor engine fuel must be subtracted from these totals to determine burner fuel use.
Since there are no nationally available numbers for compressor engine fuel, compressor fuel
use was estimated.
TABLE 5-1. BURNER FUEL GAS ACTIVITY FACTOR
National Fuel Use Ift6 sdt
"Lease and Plant Fuel" (Gas Facts, Table 3-3)14 1,070,452
- Production Compressor Fuel3 -219,700
- Gas Plant Compressor Fuel3 -469.500
- Estimated Burner Fuel (Production) 381,252
"Pipeline Fuel Use" (Gas Facts, Table 3-4)15 630,083
- Transmission Compressor Fuel" -400,100
- Storage Compressor Fuel3 -53.210
- Estimated Burner Fuel (T&S) 176,773
a Estimated based on HP-hr from Volume 11 on compressor driver exhaust, the AP-42 "CO2
per HP'hr" emission factor, and the combustion equation.4-14
In addition, gas lift compressors also centime natural gas as fuel. Emissions
from these compressors are considered to be attributed to the petroleum industry, based on
the industry boundaries defined by this project.10 Methane emissions from this source have
not been quantified and subtracted from the natural gas industry emissions.
19
-------
The burner combustion efficiency was determined by using the AP-42 emission
factors. The AP-42 emission factor (3 lb/106 ft3) can be converted to a combustion efficiency
as follows:
3 Ib CH4 Ibmol CH4 379 ^f scf CH4
4 x S x J/v ^ = 0.000071 (1)
106 cf fuel 16 Ib CH4 Ibmol scf fuel
Multiplying the emission factor by the activity factor yields the emission rate for burners:
scf CH- //Vv
(381,252 MMscf + 176,773 MMscf) x 0.000071 = 0.039 Bscf (2)
scf fuel
This value is insignificant, and therefore is not listed as an emission source in the total
emissions estimate for this project.
5.2 Flares
Flares are devices used to provide a safe and economical means of gas disposal
from routine operations, upsets, or emergencies via combustion of the gas. Flares prevent a
controlled release of methane from building up into a large cloud of gas that could explode.
There is a wide variety of flares used in the natural gas industry ranging from small open-
ended pipes at wellheads to iarge, horizontal, or vertical flares with pilots, such as those at
gas plants.
Methane emissions from flares result from the incomplete combustion of gas in
the flare's flame or from time periods where there is no flame at the flare tip (flame-out) due
to flare operational problems. Either of these cases results in emissions of non-combusted
methane to the atmosphere. To determine the total emissions from flares in the gas industry,
two factors must be known: 1) the average methane combustion efficiency of flares
(including flame-out periods) and 2) the total annual amount of natural gas flowing to flares
in the United States.
20
-------
5.2.1 Combustion Efficiency
The combustion efficiency of flares is primarily dependent upon the flame
stability which, in turn, depends on the gas velocity, heat content, and wind conditions.
There are many problems in testing industrial flares for combustion efficiency; some of these
include flare (and therefore flame) size, radiant heat, wind conditions, and proper probe
placement within the flare flame. Therefore, most of the studies have been conducted on
pilot flares, with the results extrapolated to the larger industrial-size flares. Table 5-2
provides a summary of flare combustion efficiency studies compiled by Pohl and Soelberg.17
Only two of these studies used natural gas as the flare gas. The study bj
Straitz has a wide-efficiency range, but instrument problems are also noted. The only oLter
study to use natural gas (Howes) shows an excellent combustion efficiency (>99%).
However, the composition of the natural gas is unknown in Howes' combustion efficiency.
Although methane is a clean-burning gas, the composition of the natural gas hi the
production segment can vary substantially. As shown in Table 5-2, gas streams with
heavier hydrocarbons or with a substantial sulfur content, such as sour gas, result in lower
combustion efficiencies.
Table 5-2 shows two studies for open-ended pipes with combustion efficiency
ranges of 90 to 99.9% and 92 to 99.7%. The lower efficiencies for these studies are due in
part to the lack of features and controls, which are used to ensure flame stability in the
larger, more efficient commercial flares. Another reason for the lower efficiency was that
these two studies were conducted on heavier gas mixtures that did not include methane or
natural gas. In the article by Straitz, "Flare Technology Safety," the author claims that
typical flare combustion efficiencies are 99+% for natural gas.18 The author also points out
that the combustion efficiency will be lower for gases with low-Btu heat content (due to
nitrogen, water vapor, or H2S). Other sources give typical flare efficiencies as 98 to 99%
as long as the flare is operated within the stability limits of the flame.19'20
21
-------
TABLE 5-2. SUMMARY OF PREVIOUS FLARE COMBUSTION EFFICIENCY STUDIES
16
Study
Palmer
Merget
Straitz
Siegel
Lee&
Whipple
Howes, et al.
McDaniel
Year
1972
1977
1978
1980
1981
1981
1982
1983
1983
Marc
Size
(in)
0.5
47
2-6
17
2
6"
Sat
4C
8
6"
Design
Steam assisted
experimental
nozzle
Full size
Steam and pilot
Commercial flare
gas
Holes in 2" cap
(1.1 in2 open
area)
Commercial air
assist. Zink
STF-LH
Commercial H.P.
Commercial Zink
STF-S-8
Commercial air
assist. Zink
STF-LH-457-5
Gas Fxft
Velocity
(f/s)
50-250
NA
0.7-16
1.8
40-60
Near Sonic
(estimate)
0.03-62
1.4-218
Gas Heating
Value
(Eta^t5)
1448
NA
1000-2350
1500
2190-2385
2385
1000
209-2183
83-2183
Gas Flared
Ethylene
Carbon black
vinyl monomer
Natural gas,
propane
Refinery gasa
Propane
Propane
Natural gas
Propylene/N2
Propylene/N2
Measured
Combustion
Eff. (%)
<97.8
2500:1
reduction
in CO
75-99
97-99
96-100
92-100
>99
67-100
55-100
Comments
Helium tracer for
full-size flare
evaluation
EPA ROSE remote
sensing system
Results of limited
validity due to
instrument range
sensitivity
Multiposition plume
extractive sampling
Both extractive and
EPA RCSE plume
sampling
Extractive and EPA
ROSE plume
sampling
to
Continued
-------
TABLE 5-2. (Continued)
Study
Pohl, et al.
Pohl and
Soe'berg
Year
1984
1985
1985
1985
1985
Flare
Size
(in)
3-12
0.042
1.5-
12
0.042
-2.5
3
Design
Open pipe and
commercial
Nozzle
Commercial
coanda steam
injection, pres-
sure assisted, air
assisted, open
pipe, pilot
assisted
Nozzle
Open pipe
Gas Exit
Velocity
(f/s)
0.2-420
31-854
0.2-591
5.6-891
0.15-139
Gas Heading
Yaiwe
(Bta/ft3)
291-2350
923-3320
122-2350
588-2350
145-877
Gas Flared
Propane/N2
25 different gas
mixtures
Propane/N2
Propane/N2
H2S/propane/N2
NHj/propane/N,
1,3 butadiene/N2
Ethylene
Oxide/N2
Measured ..
Ccmbustfofi .
Eff . (%}
90-99.9
>98
( <50-99 99
destruction
efficiency)
36-99.9
NM
92-99.7
(92-99.9
destruction
efficiency)
Comments
Multiprobe plume
extractive sampling
Comparative
screening tests
Comparative com-
mercial flare type
evaluation
Flame aerodynaiu:''
tests
Gas mixture testing
NA~= Not Available
NM = Not Measured
1 50% hydrogen plus light hydrocarbons.
b Supplied through spiders; high Btu gas through area is 5.30 in2 and low Btu gas through 11.24 in2.
0 Three spiders, each with an open area of 1.3 in2.
-------
Additional problems exist in the case of open-ended pipes used for flaring in
the production segment of the gas industry. These flares typically do not have a pilot and
must oe lit manually. Therefore, the potential exists for the gas to be vented rather than
flared when operating personnel are not available to light Che fare (i.e., gas vented through a
pressure relief valve to a flare). Much of the flaring done in the production segment occurs
at well completion. Since operating personnel are always present during this activity, the
volume of gas vented during well completion is small. In addition, most state agencies
require that any ongoing (post-completion) vent of wellhead gas be burned; the agencies have
field auditors to ensure that this requirement is followed.
On th2 basis that natural gas is predominantly methane (as presented in
Appendix A), a combustion efficiency of 98% was used for the production segment of the
natural gas industry and 99% for the other industry segments. A lower efficiency was used
for the production segment to provide a more conservative estimate of emissions due to the
variability of the composition of the natural gas as it is extracted from the well. Both
efficiencies assume the flare to be operating under optimum flame ".lability.
Flame-out in the natural gas industry was assumed to be negligible. Most gas
processing plants are manned, so that flame-out at the flare would be observed and corrected
quickly. In addition, many of these sites have pilots and/or igniters that ensure that the
flame remains lit. For transmission, flare stacks at compressor stations are uncommon,
where they do exist, they have pilots and/or igniters that ensure that the flame remains lit.
In the production segment, most flaring from natural gas industry wells is performed either
with operator supervision or occasionally with piloted flares, so that flame-out is minimal.
5.2.2 lotal Natural Gas Flow to Gas Industry Flares
There are no published sources for the total volume of gas flared in the natural
gas industry. While the American Gas Association (A.G.A.) does publish natural gas
production and distribution volumes that include a number called "Vented and Flared,"15 this
24
-------
number does not split the amount vented from the amount flared. For 1992, A.G.A. report?
167.5 Bscf of natural gas "vented and flared" from production and gas processing. The
A.G.A. number is derived by a pseudo material balance and includes all gas that is not
marketed, reinjected, or used in the production field. Therefore, the A.G.A. estimate
includes fugitive gas losses and vented losses, as well as flared volumes. If the A.G.A.
estimate were reduced by the actual amount "vented" to the atmosphere (fugitive + vented
volumes), the result would be the amount of natural gas that A.G.A. assumes is flared. This
GRI/EPA Study estimates 48.4 Bscf of methane from production and processing fugitive
emissions and 58.9 Bscf ot mciliane from production and processing vented emissions.
Converting the GRI/EPA numbers to natural gas, based on the methane composition for each
industry segment, results in 132.3 Bscf of natural gas as shown in Table 5-3.
TABLE 5-3. NON-COMBUSTED EMISSIONS FROM PRODUCTION
AND GAS PROCESSING (GRI/EPA ESTIMATE BASIS)
.- . *•
Fugitive Emissions
Production
Processing
Vented Emissions
Production
Processuig
TOTAL
Bsefy Methane
24.0
24.4
53.8
5.1
107.3
Bsefy Natural Gas
30.4
28.1
67.9
5.9
132.3
If the difference between the A.G.A. "Vented and Flared" volume (167.5
Bscf natural gas) and the non-combusted emission volume from this study (132.3 Bscf natural
gas) is assumed to result hi the flared volume, then 35.2 Bscf of natural gas would be flared.
Using a flaring efficiency of approximately 99% (as discussed in Section 5.2.1) and at
average methane composition for production and processing of 82.9%, a flared emission rate
can be estimated:
25
-------
0.829 scf CH, 0.01 scf CH. non-combusted „,,
35.2e9 scf gas x x •-= 0.29 Bscf CH, (3)
scf gas scf CH4 flared 4
There are concerns with the accuracy of this approach, in that the "Vented and
Flared" volume report by A.G.A. is fraught with inconsistencies: it includes items not truly
vented or flared, it does not include all vented and flared volumes (some sources from
production and processing are overlooked, and transmission and distribution sources are not
included), and each state may have different reporting requirements for the number.
Appendix B discusses why this number is an inaccurate representation of the total vented and
flared volume.
Selected Method
Without reasonable nationally-tracked numbers for flaring, site data were
sought. Most sites, however, did not measure nor track flared volumes. This was especially
true hi the production segment. Therefore, an alternate approach was used based on an
assumption that the total amount of gas flared would be equal to half of the total amount
directly vented to the atmosphere by the industry. Table 5-4 shows the methane volumes
vented hi each industry segment, as presented in Volume 7 (Methane Emissions from Blow
and Purge Activities).9 Using the flaring efficiencies for each industry segment discussed
earlier, a flare emission rate can be calculated by multiplying the assumed flow by the
combustion inefficiency term.
As shown hi Table 5-4, this alternate approach produces an estimatt of 15.2
Bscf of natural gas flared, which is significantly smaller than the A.G A. approach. Since
the A.G.A. approach is believed to overstate the flared amount, this alternate approach was
selected.
26
-------
TABLE 5-4. MAXIMUM FLARING EMISSIONS
Industry Segment
Production
Gas Processing
Transmission and
Storage
Distribution
TOTAL
Assumed
Mow to Flare/
Bsef FSaring Efficiency
0.5 (6.6 ± 329%)
0.5 (3.0 ± 262%)
0.5 (18.5 + 177%)
0.5 (2.2 ± 1,783%
15.2 + 185%
98%
99%
99%
99%
Maximum Annual
Methane Emissions
from Flaring,, Bscf
0.066 i 329%
0.015 ± 262%
0.093 + 177%
0.011 + 1,783%
0.185 ± 183%
The methane volume is assumed to be equivalent to half the vented quantity, where tne vented volumes are
reported in the Blow and Purge Report.9
With either calculation approach, the estimated annual emissions from flares
are negligible (less than 0.3 Bscf), and may be conservatively high, given the problems built
into the A.G.A. number and that the flow to natural gas industry flares flare may be
overestimated in the second approach. Therefore, this small category does not show up as an
itemized contribution to total emissions in this report.
5.3
Af 'd Gas Recovery Vents
Acid Gas Recovery (AGR) vents are a very minor som-ce of methane
emissions and account for only 0.82 Bscf of methane emissions. AGR systems are used to
remove acid gases (H2S and CO2) by contacting the stream with a solvent (usually amines)
and then driving the absorbed components from the solvent. Tne amines can also absorb
methane and, therefore, methane can be released to the atmosphere through the reboiler
vent.
27
-------
Methane emissions were calculated using an ASPEN PLUS™ process
simulation. The disposition of AGR vent gas and the number of AGR units were taken
from an API survey of U.S. Natural Gas Reserve Demographics.21 The following
assumptions were used in determining the emission rate: 1) AGR units do not use flash
drums or stripping gas; 2) AGRs have an absorption of methane similar to water; 3) the
total number of AGR units in the United States are in the gas processing segment; and 4)
82% of AGR emissions are controlled (18% of the emissions are vented).
5.4 Salt Water Tanks
Methane emissions from production salt water tanks were estimated using an
ASPEN PLUS* process simulation. The flash calculations were based on the following
assumptions:
1) The natural gas industry produces 497 million barrels of salt water
annually, of which approximately 100 million barrels are from coal
bed methane wells.22
2) 70% of the water from gas wells is reinjected, leaving 30% of the
water stored in atmospheric tanks.22
3) The hydrocarbon composition is 100% methane.
The flash calculation results are summarized in Table 5-5 for cases with the
salt content varied from 2 to 20%, and the pressure varied from 50 psi to 1000 psi. The
simulation results indicate that methane emissions from salt water tanks are negligible.
* ASPEN PLUS™ is a registered trademark of Aspen Technology, Inc.
28
-------
TABLE 5-5. SALT WATER TANK EMISSIONS
Salt Content, Wt %
20% Salt
10% Salt
2% Salt
Pressure, psi
50
250
1000
250
1000
250
1000
Methane Emissions,
106 Ib/yr
1.6
10.8
38.8
16.4
58.7
19.4
69.5
Methane
Emissions,
Bscf
0.0
0.0
0.0
0.0
0.0
0.0
0.0
5.5
Drilling operations typically use hydraulic pressure from the drilling mud to
keep the oil and gas in the formation while drilling. The intent is to prevent the
uncontrolled flow of oil and gas up the \vcll bore (a potential blowout) until the surface
equipment is ready to receive the material. Drilling mud does absorb some gas and releases
it in the degasser at the surface. The quantity is typically small and has been excluded for
this project.
Blowouts during drilling or completion can be a large individual source of
emissions, since the formation flows uncontrolled to the surface. The drilling industry has
developed procedures and devices throughout the evolution of oil and gas production to
prevent such an event. As a result, blowouts today are very infrequent and have not been
considered.
Once the desired formation or depth is hit, the well must be "completed"
before it can be produced. Less expensive tubing replaces the strong drill string and an
outer annular casing is cemented in place. The casing has many uses. It prevents the
formation from caving in around the tubing, allows easier well maintenance, and allows
29
offer data supporting the decision not to use the reported V&F numbers in this GRI/EPA
-------
onshore, dead (no surface pressure) oil wells to produce o^l up the tubing string "aid gas up
the outer casing. If the oil ind gas were produced in the labing, the pumps would become
vapor locked.
Once the casing is in place, it is perforated and the formation begins to flow
into the well. A clear completion fluid is used (heavy salt water) instead of mud, and the
completion fluid will flow or be pumped to surface tanks or pits. Again, some small
amount of gas may evolve from the completion fluid, but it is typically insignificant.
After the completion fluid is out of the well, oil and/or gas flow begins.
Depending on the type of we!!, the gas may be vented, flared, or immediately produced. If
the well was drilled in a known field v ith other existing wells, it is called a Developmental,
or an Infill well. In that circumstance, the reservoir pressure and size are already defined,
and the operator can have production meters and equipment sized and hi place for
completion. Very little venting and flaring would occur at completion, if any.
If the well was an exploratory "discovery" well (i.e., one drilled hi a new
area of unknown reservoir potential), facilities may not be ready for the well's production.
The well is flared for the time that it takes to measure the flow rates so that equipment can
be sized. This period is referred to as completion, completion flaring, or well testing.
Emissions from completion flaring are minimal but are included hi the blow and purge
emissions.9
5.6 Drips
Some longer sections of gas-gathering and transmission pipelines may have
small liquid collection pots L. cated along the line. These pots are periodically blown down
to clear collected hydrocarbon condensate, and the blowdown vents methane directly to the
atmosphere. An unaccounted-for (UAF) gas study by Pacific Gas and Electric (PG&E)
30
Finally, given weaker enforcement, more unrerorted quantities will exist. Some of the state-
-------
defined drip blowdown emissions under unmetered company gas usage,23 They found the
category to be insignificant, at 0.00035% of their total throughput.
5.7 Sampling
Gas is consumed in sampling and analyzing gas for composition and heating
value. Much of this gas is then emitted to the atmosphere from the on-line analyzers or
from the sample containers. Most sampling efforts begin in the gas processing areas, and
field sampling represents a small fraction of the total samples. The PG&E UAF gas project
estimated this category as insignificant, at 0.00107% of their total throughput.23
31
plant has orifice meter readings near zero, is not considered in the calculation of the reported
-------
6.0 REFERENCES
1. Hummel, K.E., L.M. Campbell, and M.R. Harrison. Methane Emissions from
the Natural Gas Industry, Volume 8: Equipment Leaks, Final Report, GRI-
94/0257.25 and EPA-600/R-96-080h, Gas Research Institute and U.S.
Environmental Protection Agency, June 1996.
2. Campbell, L.M. and B.E. Stapper. Methane Emissions from the Natural Gas
Industry, Volume 10: Metering and Pressure Regulating Stations in Natural
Gas Transmission and Distribution, Final Report, GRI-94/0257.27 and EPA-
600/R-96-080J, Gas Research Institute and U.S. Environmental Protection
Agency, June 1996.
3. Campbell, L.M., M.V. Campbell, and D.L. Epperson. Methane Emissions
from the Natural Gas Industry, Volume 9: Underground Pipelines, Final
Report, GRI-94/0257.26 and EPA-600/R-96-080i, Gas Research Institute and
U.S. Environmental Protection Agency, June 1996.
4. Stapper, C.J. Methane Emissions from the Natural Gas Industry, Volume 11:
Compressor Driver Exhaust, Final Report, GRI-94/0257.28 and EPA-600/R-
96-080k, Gas Research Institute and U.S. Environmental Protection Agency,
June 1996.
5. Picard, D.J., B.D. Ross, and D.W.H. Koon. "A Detailed Inventory of CH4 and
VOC Emissions From Upstream Oil and Gas Operations in Alberta."
Canadian Petroleum Association, Calgary, Alberta, 1992.
6. Shires, T.M. and M.R. Harrison. Methane Emissions from the Natural Gas
Industry, Volume 12: Pneumatic Devices, Final Report, GRI-94/0257.29 and
EPA-600/R-96-0801, Gas Research Institute and U.S. Environmental
Protection Agency, June 1996.
7. Radian Corporr^on. Glycol Dehydrator Emissions: Sampling and Analytical
Methods and L^.tmation Techniques. GRI-94/0324, Gas Research Institute,
Chicago, IL, March 1995.
8. Shires, T.M. Methane Emissions from the Natural Gas Industry, Volume 13:
Chemical Injection Pumps, Final Report, GRI-94/0257.30 and EPA-600/R-96-
080m, Gas Research Institute and U.S. Environmental Protection Agency,
June 1996.
32
ratio Nn actual measurements are used for P-l or P-2 reported values,
-------
9. Shires, T.M. and M.R. Harrison. Methane Emissions from the Natural Gas
Industry, Volume 7: Blow and Purge Activities, Final Report, GRI-94/0257.24
and EPA-60Q/R-96-080g, Gas Research Institute and U.S. Environmental
Protection Agency, June 1996.
10. Stapper. B.E. Methane Emissions from the Natural Gas Industry, Volume 5:
Activity. Factors, Final Report, GRI-94/0257.22 and EPA-600/R-96-080e, Gas
Research Institute and U.S. Environmental Protection Agency, June 1996.
11. Myers, D. Methane Emissions from the Natural Gas Industry, Volume 14:
Glycol Dehydrators, Final Report, GRI-94/0257.31 and EPA-600/R-96-080n,
Gas Research Institute and U.S. Environmental Protection Agency, June
1996.
12. Myers, D.B. and M.R. Harrison. Methane Emissions from the Natural Gas
Industry, Volume 15: Gas-Assisted Glycol Pumps, Final Report, GRI-
94/0257.33 and EPA-600/R-96-080o, Gas Research Institute and U.S.
Environmental Protection Agency, June 1996.
13. Biederman, N. GRI TRANSDAT Database: Compressor Module, (prepared
for Gas Research Institute), npb Associates with Tom Joyce and Associates,
Chicago, IL, August 1991.
14. U.S. Environmental Protection Agency. Compilation of Air Pollutant
Emission Factors, U.S. EPA Office of Air Quality, Planning, and Standards,
AP-42, Fifth Edition, Research Iriangle Park, NC, January 1995.
15. American Gas Association. Gas Facts: 1990 Data, (Table 3-3), Arlington,
VA, 1991.
16. American Gas Association. Gas Facts: 1993 Data, (Table 3-4), Arlington,
VA, 1994.
17. Pohl, J.H. and N.R. Soelberg. "Evaluation of the Efficiency of Industrial
Flares: H2S Gas Mixtures and Pilot Assisted Flares," EPA-600/2-86-080
(NTIS PB87-102372), September 1986.
18. Straitz, J.F., III. "Flare Technology Safety," Chemical Engineering Progress,
Volume 83, No. 7, July 1987, pp. 53-62.
19. Romano, R.R. "Control Emissions with Flare Efficiency," Hydrocarbon
Processing. Volume 62, No. 10. October 1983, pp. 78-80.
33
wells. For that reason, there is a significant quantity of casinghead gas produced. In Texas,
-------
20. Pohl, J.H., J. Lee, R. Payne, and B. Tichenor. "Combustion Efficiency of
Flares," 77th Annual Meeting and Exhibition of the Air Pollution Control
Association, San Francisco, CA, June 24-29, 1984.
21. American Petroleum Institute. Survey of U.S. Natural Gas Reserve
Demographics, Washington, DC, 1992.
22. Energy Environmental Research Center, University of North Dakota, and
ENSR Consulting and Engineering. Atlas of Gas Related Produced Water
for 1990. Gas Research Institute, 95/0016, May 1995.
23. Pacific Gas & Electric Company. "Unaccounted-For Gas Project." Volume
1, 1989.
34
-------
APPENDIX A
Methane Composition
A-l
-------
APPENDIX A
METHANE COMPOSITION
The composition of methane in natural gas is needed to calculate methane emissions
from natural gas that is emitted to the atmosphere. This section describes the characteristics
of natural gas streams in production, processing, transmission, and distribution. The
methane composition for each segment is presented in Table A-l.
TABLE A-l. METHANE COMPOSITION BY INDUSTRY SEGMENT
Segment Methane (volume %)
Production 78.8 ± 5%
Gas Processing 87.0 ± 5%
Transmission/Storage 93.4 ± 1.5%
Distribution 93.4 ± 1.5%
Production Segment - The production segment of the gas industry includes natural
gas produced from gas wells (non-associated) and oil wells (associated). Data from the
United States Bureau of Mines, Division of Helium Field Operations, and A.G.A. Gas
Facts were used to calculate the production methane composition.1>2 The Bureau of Mines
(BOM) has been collecting analytical data from oil and gas wells and natural gas pipelines
since 1917 in an effort to locate sources of helium. Under another GRI project, all
published BOM data through 1987 were obtained on magnetic tape and loaded it into an
Empress® database.3 The focus of this earlier project was to determine the major
contaminants in sour natural gas, specifically, hydrogen sulfide and carbon dioxide. Over
14,000 records were used to determine county and state averages for natural gas
composition, including methane content.
The BOM data were corrected since a few non-gas industry wells that have very
high helium or carbon dioxide content with little or no methane were included hi the data
A-2
-------
set. For the largest producing states, the Empress data files were reviewed and the entries
with less than 40% methane were removed. Table A-2 shows the average methane content
and marketed production by state. This information was regionalized to estimate the
national average methane content of 78.8 mol % ± 5% as shown in Table A-3.
Gas Processing Segment - The only source of methane data identified for the
processing segment is from the Gas Engineer's Handbook* These data are from November
1951 and consist of eight data points with only two states, California and Texas,
represented (see Table A-4). The data are reported as "after processing plant" and were
assumed to represent typical speciation data for natural gas leaving this industry segment.
Due to the limited data set, an average methane content was calculated instead of a
weighted average based on the state's fraction of U.S. production. The average methane
content for the processing segment is 87 mol ->ercent. A 90% confidence interval of 5%
was calculated based on the spread of the available data.
Transmission and Storage Segments - The methane composition for transmission
and storage was based on the GRI TRANSDAT database,5 which has analyses of fifty fuel
gas samples from various transmission compressor stations. Since the fuel gas is from the
pipeline, these should represent transmission gas quality. The resulting average methane
composition for transmission is 93.4 mol% ± 1.5% (90% confidence interval is based on
the spread of data).
Distribution Segment - The Gas Engineer's Handbook provided methane
composition data for the distribution segment.4 This data set 'acludes distribution ir: 48
cities, representing 29 states and the District of Columbia. i:;-~ the f;xT. of 1062. A weJghK ."
average was not used for this industry segment sinu; 1'rc
-------
The composition of gas leaving the processing segment should agree with the
methane composition in the transmission and distribution segments, since the gas is only
transported or stored. However, the distribution value is less than the methane composition
determined for the transmission segment. Because the transmission data are based on the
more recent and more extensive data source, the same composition is used for distribution.
Therefore, the distribution methane composition used in determining emission factors is
93.4 vol % ± 1.5%.
TABLE A-2. AVERAGE STATE METHANE CONTENT AND PRODUCTION
RATE
Region
Gulf Coast
Central Plains
Pacific and Mountain
Atlantic & Great
Lakes
States"
AL
FL
LA
MS
TX
AR
CO
KS
MO
MT
ND
NE
NM
OK
SD
WY
AK
AZ
CA
OR
UT
IL
KY
MI
NY
OH
PA
TN
VA
WV
Methane Composition,
Volnme %
86.4
60.2
87.8
79.8
75.1
87.7
65.4
69.4
69.4
69.4
62.5
53.4
64.4
79.8
—
69.9
76.5
—
75.3
._
-
86.2
76.2
74.4
90.0
82.0
91.0
85.2
88.0
86.9
1989 Marketed Gas
Production, Bscf
151
• 8
5,087
165
6,401
174
227
601
4
51
56
1
856
2,237
4
756
394
1
364
3
120
2
72
156
20
160
192
2
18
177
States not shown had insignificant 1989 marKeted gas production rates.
A-4
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TABLE A-3. METHANE COMPOSITION OF PRODUCTION GAS
Region
Volume Percent Methane (from
state vol %'s weighted by state
production)
Comments
Gulf Coast
Central Plains
Pacific and
Mountain
Atlantic and Great
Lakes
80.76
73.68
75.92
83.59
All states but GA represented
Some states with insignificant
production were excluded (IA,
MN)
Alaska and California only
Some states with insignificant
production were excluded (CT,
DE, IN, MA, MD, ME, NC, NH,
NJ, RI, SC, VT, WI)
Total U.S.
78.8
Weighted average by regional
production
TABLE A-4. METHANE COMPOSITION IN GAS PROCESSING
Location
Methane Composition, Vol %
CA, Kettleman North Dome
CA, Ventura
TX, Agua Dulce
TX, Carthage
TX, Hugoton
TX, Keystone
TX, Panhandle
TX, Wasson
Average
93.0
92.7
93.0
91.7
79.0
86.2
81.5
76.9
86.8
A-5
-------
REFERENCES:
1. U.S. Bureau of Mines. Analyses of Natural Gases, 1917-1987. 6 vols. Helium Field
Operations, Amarillo TX. February 1988 (magnetic tape and hard copy).
2. American Gas Association. Gas Facts: 1990 Data, (Table 3-3), Arlington, VA,
1991.
3. Radian Corporation. Investigation of U.S. Natural Gas Reserve Demographics and
Gas Treatment Processes, Topical Report. Gas Research Institute, January 1991.
4. "Natural Gas from Various Gas Fields (As of November 1951)," Table 2-12, Gas
Engineers Handbook, Industrial Press Inc., New York, NY, 1977.
5. Biederman, N. GRI TRANSDAT Database: Compressor Module, (prepared for
Gas Research Institute) npb Associates with Tom Joyce and Associates, Chicago, IL,
August 1991.
A-6
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APPENDIX B
Reported "Vented and Flared" Data
B-l
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APPENDIX B
REPORTED "VENTED AND FLARED" DATA
National numbers for "vented and flared" volumes are reported by production and
processing companies to state agencies, which then report to the Department of Energy
(DOE) Energy Information Administration (ElA). Gas Facts publishes this EIA national
number for "venting and flaring" (V&F) at approximately 0.71% of the total natural gas
production.1 Initially, it was assumed that the reported V&F number was valid, and the
approach for this project focused on simply splitting this number into a vented volume and a
flared volume, so that vented emissions could be accurately quantified. However, this study
discovered that the reported V&F number has many problems, and it is not a useful measure
of actual venting or flaring.
The reported numbers do not represent actual "vented and flared" quantities of gas,
since companies do not use a standard practice or protocol for determining their V&F
amount. In fact, many sites use a protocol that results in an erroneous value for V&F.
Many gas plants simply report all material balance discrepancies as "vented and flared," even
though most material balance losses are due to other factors, such as metering inaccuracies.
Other companies have operators simply guess the amount of gas vented or flared in order to
fill out a state form. Very few sites actually measure or accurately calculate V&F volumes.
Even if the reported V&F volumes were accurate, there is not a reliable method of splitting
the number into the amounts flared (burned) and the amounts vented. Furthermore, there is
no method for separating the amount of vented, unmarketed natural gas attributable to oil
production.
The GRI/EPA project abandoned use of the reported V&F number, and turned to a
technique that identified each source of vented emissions, and estimated emissions from each
source type. This technique is described in more detail hi Volume 3 on general
methodology.2 This appendix discusses the problems with the V&F numbers reported by
operators to various state and federal government agencies. This section is only intended to
B-2
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offer data supporting the decision not to use the reported V&F numbers in this GRI/EPA
project. Sources of data for the United States and for individual states, as well as the quality
of the data are covered in detail in the following subsections.
B.I Specific States
Specific state data were analyzed for Texas, Oklahoma, and Louisiana. These thres
states comprise 68% of all the gas produced in the U.S. in 1989 and are representative of gas
production facilities. States that are major producers of oil and gas generally have state
governmental agencies that regulate and maintain data on the oil and gas industry. The
regulating agencies for Texas, Louisiana, and Oklahoma are the Texas Railroad Commission
(RRC), the Louisiana Department of Natural Resources (DNR), and the Oklahoma
Corporation Commission, respectively.
The primary goal of these agencies is to control the industry (provide "fair play" for
all operators), collect fees, and protect the community and the environment. Methane
emissions have not been a concern for these agencies except where the emitted methane
represents 1) an unnecessary waste of natural resources that should come out of a company's
"allowable" production quota; 2) a toxic gas hazard (H2S); or 3) a fire or explosive hazard.
To the extent that methane emissions represent a measurable loss of natural resources, the
agencies track data on "venting and flaring." For many agencies, the V&F numbers are
grouped together. No differentiation is made between amounts actually burned versus
amounts vented; however, there is one exception. Permits filed under Rule 32 in the Texas
RRC code do differentiate between venting and flaring.
The accuracy and extent of the reported V&F numbers are a iqunction of the V&F
definition the state uses in the reporting regulations, the state's enforcement of report' g
regulation, and the exclusions that the state allows. Given a broader definition, more
emissions are included; however, given more exclusions, fewer events will be reported.
B-3
-------
Finally, given weaker enforcement, more unrepor~d quantities will exist. Some of the state-
specific data are discussed below.
B.I.I Texas
For Texas, most of the V&F numbers are reported as one number to the RRC on a
monthly basis. Gas plant operators send in R-3 forms, and oil and gas producers send in P-l
and P-2 forms, respectively. Oil wells are tracked by the lease, and gas wells are tracked by
the individual well. The data from these forms are summed into tables in the RRC's
published Oil and Gas Annual Report.3 The RRC also requires a permit for flares or vents
lasting more than 24 hours in the R-32 form. The specific forms are discussed in more
detail below.
Among the states, Texas probably has the strongest regulations, the strongest enfor-
cement, and the most comprehensive published data. Nevertheless, the reported vented and
flared numbers in Texas are difficult to assess; there are areas over-reported and under-
reported due to definition. Amounts vented from compressor engine exhausts, pneumatic
actuators, glycol vents, and acid gas recovery vents have never been considered as part of
the V&F definition for reporting. In addition, the definition of V&F is different even among
the various RRC forms.
R-3 Gas Plants - For gas plants, the V&F number on the R-3 is simply the result of
a material balance closure around the gas plant. The rule is:
GAS IN - PRODUCTS OUT - CONSUMPTION = V&F
Measured outlet dispositions (pipeline gas, fuel, extraction loss, etc.) are subtracted from the
inlet, plant meter, and the difference is reported as V&F. The difference is really just an
"unaccounted-for" (UAF) number arrived at by an accounting procedure; it is usually
positive and hi the range of 0.3% of the total gas processeu. The flare, which in the gas
B-4
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plant has orifice meter readings near zero, is not considered in the calculation of the reported
V&F number.
If the gas plant material balances are absolutely accurate (all quantities included are
on the same basis) and have a zero meter bias (doubtful, but possible), then the reported
V&F number, even though a calculated value, is a true "emitted, vented, or flared" amount.
From the V&F number, the flare meter reading could be subtracted, the fugitive emissions
subtracted, and the remarking value would be material actually vented. This is the "top-
down" yardstick that the "bottom-up" emissions rates for gas plants can be compared to.
R-3 Cycling Plants (Pressure Maintenance) - Cycling plants process gas to reduce
the dew point of condensibles in the formation and thus extend the life of a field. In most
cases, not all of the gas is returned to the formation in a cycling plant. Again, data from the
Texas Railroad Commission indicate that for the 15 pressure maintenance facilities in Texas,
51.6% of the residue gas is used for repressurizing or cycling, while 26.6% is sent to
transmission pipelines.3 It should be noted also that the V&F estimate for cycling plants is
0.3% of the total gas processed, which is the same as for gas plants.
P-l, P-2 Production - A P-l report is generated for each oil lease and a P-2 report
for each gas well. For production facilities, V&F on the P-l and P-2 reports is meant to
represent a real vented and flared quantity at the wellhead. Nevertheless, many releases are
exceptions to the reporting requirements, including: well completion flaring for up to 10
days, events less than 24 hours in duration, well cleanups, and venting and flaring from
certain field equipment (glycol separators and pneumatic devices). This excludes many of
the true release events from the numbers recorded by the RRC.
Even the accuracy of the categories that are included in reporting is questionable.
Production flares have no pilot and no meter, so reported values are operator estimates. The
operators generally base their estimates upon the most recent well test data or upon the
B-5
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field's gas-to-oil ratio. No actual measurements are used for P-l or P-2 reported values, and
the RRC admittedly has no way to verify the reported values.
There are so many exceptions and estimations in the reported production numbers that
it is impossible to intuitively tell whether the number is over- or under-reported. As with
gas plants, a method that does not use the reported V&F numbers must be used to estimate
real production emissions. The reported numbers can then be adjusted to use only as a check
value for the bottom-up calculations.
Rule R-32 - The Texas RRC Rule 32 does have some impact on the V&F amounts.
The rule allows 10 days of venting following completion of a well, and then requires all gas
to be flared. In addition, permits are required for flares or vents beyond initial completion
(exceptions are well cleanups or repairing/modifying a gas-gathering system). The permit
fcrm has one very useful piece of data: a designation of venting that is different from
flaring. The form is the only place hi the reported V&F category where the operator must
designate whether he intends to vent or to flare for the specific release permit.
The RRC tracks Rule 32 permits to make sure that sour gas is burned and that large
vented releases are not near major roadways nor populated areas. Releases of unburned sour
gas can be toxic, and large vented releases can be explosion or fire hazards. The R-32 d'tfa
were used for this project to establish a percentage split between vented versus flared for all
the production V&F totals that are reported. The data were reviewed for 1991 permits and
showed that the amount vented was 7.7% and the amount flared was 92.3% of the total
V&F. However, the assumption that the non-permitted quantities have the same split may be
incorrect, since events less than 24 hours and well cleanups are exceptions. Therefore, many
venting events may not be part of these data.
Oil and Gas Annual Report - With all of the above limitations in mind, the data
from annual reported values were analyzed. Most of the reported venting and flaring
volumes were for casinghead gas (oil well gas). There are many more oil wells than gas
B-6
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wells. For that reason, there is a significant quantity of casinghead gas produced. In Texas,
23% of all gas produced is casinghead gas.
Of the total reported V&F amounts, V&F from casinghead gas at the well accounts
for 47.5%, while V&F from gas at the well accounts for only 5%. Gas well gas V&F is
likely under-reported, since well cleanups are not reported. The data show that a dispro-
portionate amount of the reported V&F is due to casinghead gas. The remainder of the
reported V&F amounts is due to V&F reported at gas plants. This accounts for 47.5% of
the reported total V&F amount.
These data show that gas wells typically vent or flare infrequently. This makes sense
from an economic point of view, since vented gas represents a direct loss of the well's only
revenue. Casinghead gas (oil well gas) is vented or flared more frequently. Gas lost
through V&F at oil wells is also a loss of revenue but on a much less significant scale. The
oil revenue is typically much larger than the gas revenue.
Casinghead gas that is V&F may be from wells that never produce gas to a pipeline
and, therefore, should not be considered part of the gas industry emissions. Those wells
would either consume all of the produced gas as lease fuel, reinject all of the gas, or
vent/flare all of the gas. Summing those three disposition categories for the RRC's
casinghead gas annual table shows that 4.3% of the total casinghead gas is used for those
purposes. If all oil wells had identical gas production, this would mean that the maximum
amount of oil wells that should be excluded is 4.3%. For a more exact answer, the number
of oil wells that do not market gas must be known.
The reported V&F numbers for Texas imply that 0.53% of all gas produced is vented
or flared. However, the following problems are associated with the Texas statistics [pluses
(+) are shown for comments that would raise the reported numbers when corrected, and
minus (-) symbols are shown for items that would reduce the reported numbers]:
B-7
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(-) Approximately one-half of the V&F amount is due to gas plant V&F, which is
an accounting closure number and not really venting and flaring. Even if a
gas plant material balance is assumed to have a zero bias, fugitives should be
subtracted from the V&F numbers reported.
(-) Nearly half of the reported venting and flaring gas is from casinghead gas.
Some of this casinghead gas is associated with oil wells that do not produce to
a gas pipeline, and that fraction is, therefore, not part of the natural gas
industry as defined by this project. This amount could be excluded if a
defensible basis were derived to separate those wells.
(-) Venting and flaring permit rates are usually overestimated (in the RRC's
opinion) because many of the producers do not want to apply for permit
exceptions if the rate increases.
(+) Many events are exempted from the reporting rules (such as well cleanup, well
completion, and events less than 24 hours).
(+) Some oil wells that produce associated or dissolved gases do not report V&F.
(+) Emissions from tank batteries, glycol dehydrators, AGRs, and other
miscellaneous sources are not reported.
Therefore, even though Texas' reported V&F numbers appear to give an overall emission
estimate for V&F emissions, they cannot be used as a quantitative measurement.
B.1.2 Louisiana
The Louisiana Department of Natural Resources (DNR) tracks V&F in a mariner
similar to the Texas RRC. Operators report the monthly production (wellhead) disposition
data on the R-5D form and the gas plant data on the R-6 form. The DNR, like the Texas
RRC, compiles all of the monthly data on computer files. The DNR, however, only makes
the data available through specific, standardized computer runs which must be pre-paid by
the requestor.
B-8
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Radian has not requested Louisiana runs; however, Louisiana provided the 1988
Parish Report during a visit to the DNR. The report showed a total onshore V&F number
similar to Texas, at 0.47% of total gas production (Texas was 0.51%).
Louisiana's definitions of venting and flaring for reported numbers appear to be
similar to Texas; and, therefore, Louisiana data will have the same problems that were
described for the Texas data. Louisiana also has no method of separating the split between
vented and flared quantities from the single V&.F numbers reported on the R-5D and R-6
forms. In fact, the term "venting," such as the "vented" column on the R-6 form, refers to
venting or flaring.
Although Louisiana does not have a Rule 32 flare permit requirement as Texas does,
it has a Statewide Order 45-1 that require? a semiannual status report, which lists casinghead
and natural gas "vented" by lease and explains why the gas is not being recovered.
Unfortunately, the DNR does not aggregate these data; the data are received in nonstandard
letter format and stored as received. It would be very difficult and time-consuming to
assemble all of "hese data into a meaningful form. For example, Radian's examination of
three 45-1 status reports indicated very different results as shown in Table B-l.
TABLE B-l. COMPARISON OF 45-1 REPORTS
Company
Type of Gas
Reason for Venting
Mid-size company Casinghead gas
Uneconomical to recover. Most vent points were low-
pressure heater treaters. Some fields used intermittent
gas lift, thus, consuming all of the produced gas
intermittently.
Large company
Small company
Unknown
Unknown
Majority of emissions were from compressor
downtimes.
Compressor downtimes.
B-9
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B.I.3 Oklahoma
The Oklahoma Corporation Commission's Oil and Gas Conservation Division issues
venting and flaring permits. However, only rates above 50 Mcfd require a permit, and few
wells fall into that category. The permit file for 1991 had only nine permits issued as shown
in Table B-2.
TABLE B-2. 1991 FLARING PERMITS FOR OKLAHOMA
Number of
Permits
6
1
2
Percent of Total
Permits
67
11
22
Season for Request
Recover load water from gas well (well
clean-up).
H2S found, pulled from gathering system and flared.
Other (unknown)
Oklahoma appears to have significantly fewer reporting requirements than Texas or
Louisiana and had no other data on V&F available. Interestingly, Oklahoma does not appear
to exclude well cleanups from the permit requirements as Texas does. As shown above, well
cleanups constitute a large percentage of the permits issued in Oklahoma.
B.2 United States
There are several sources of information gathered on the natural gas industry for the
entire United States. These sources include federal agencies, such as the Federal Energy
Regulatory Commission (FERC) and the Department of Energy (DOE), and gas industry
representatives, such as the American Gas Association (A.G.A.). Numerous publications are
compiled by these agencies and include information on gas industry financials, gas
production and disposition, and gas storage and reserves. Data are also collected from
regulatory agencies and other private agencies, such as the American Petroleum Institute
(API).
B-10
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There are five FERC forms that deal specifically with the natural gas industry. The
main form completed by gas companies regulated by FERC is the FERC Form No. 2,
"Annual Report for Major Natural Gas Companies." This form is an annual requirement for
major gas companies, which are defined by the FERC as "having combined gas sold for
resale and gas transported or stored for a fee exceeding 50 Bcf (at 14.73 psia 60°F) in each
01 the three previous calendar years." Most of the information collected on this form is
financial and, therefore, does not contribute to the data gathering effort for V&F. The other
FERC forms collect information on underground storage (FERC-8), gas pipelines (FERC-
11,-15), and gas supply (FERC-16),
The Energy Information Administration (EIA) of the DOE, publishes many reports on
the natural gas industry. One of the most useful publications is the Natural Gas Annual*
Two EIA forms provide most of the information used in this report; EIA-176, "Annual
Report of Natural and Supplemental Gas Supply and Disposition," and EIA-627, "Annual
Quantity and Value of Natural Gas Report." The EIA-176 is a mandatory form to be
completed by all companies that deliver natural gas to consumers or transport interstate gas.
The EIA-627 is a voluntary form completed by energy or conservation agencies in gas-
producing states. Other sources of information used by EIA for the Natural Gas Annual
include the FERC, the United States Geological Survey (USGS), and the Interstate Oil
Compact Commission (IOCC). Information directly from the USGS and the IOCC has not
been gathered for this venting and flaring task.
The Natural Gas Annual provides information on gas production, transmission, and
consumption for the United States as a whole and for each gas-producing state individually.
Included in this report are numbers for gas V&F. Both the EIA-176 and the EIA-627 collect
gas V&F information. Since these data are taken directly from the responsible state
agencies, any differences in reporting requirements and/or the definition of vented and flared
are not accounted for in this publication. Some of these differences were identified in the
previous sections on individual state reporting. The EIA is aware of this inherent problem,
but it is not known if the agency adjusts the data to reflect these differences.
B-ll
-------
The A.G.A.'s Gas Facts is an annual publication containing data on the gas utility
industry. The data concentrate on gas distribution and transmission but also include some
information from the gas-producing segment of the industry. Most of the information is
gathered by the A.G.A. in its survey entitled "Uniform Statistical Report. The only
information on venting and flaring provided in the Gas Facts was taken from the EIA
Natural Gas Annual. Again, this information is just a reiteration of the numbers reported by
the responsible state agencies with the inherent problems already discussed. A summary of
the national statistics in Gas Facts is shown in Table B-3.1
It appears that any data which are derived from an overall United States approach are
just a summation of the data reported by the individual gas-producing stales. Due to the
variability in these data, the task of characterizing V&F in the natural gas industry should
follow a bottom-up approach and begin with the identification of the individual sources.
Then, respective methane emission estimates could be calculated and added to determine the
overall emission number for the entire United States.
REFERENCES
1. American Gas Association: Gas Facts: 1990 Data, (Table 3-3), Arlington, VA,
1991.
2. Harrison, M.R.. H.J. Williamson, and L.M. Campbell. Methane Emissions from the
Natural Gas Industry, Volume 3: General Methodology, Final Report, GRI-
94/0257.20 and EPA-600/R-96-080c, Gas Research Institute and U.S. Environmental
Protection Agency, June 1996.
3. Texas Railroad Commission. Oil and Gas Annual Report, Volume 1 "Cycling Plant
Operations hi Texas," Data Source: RRC Form R-3, 1991.
4. U.S. Department of Energy. "Quantity of Natural Gas Used as Lease Plant Fuel by
State," Natural Gas Annual 1992, Volume 1. Energy Information Administration,
Office of Oil and Gas, U.S. Dept. of Energy, Washington, DC, November 1993, p.
240.
B-12
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TABLE B-3. SUPPLY AND DISPOSITION OF GAS IN
THE UNITED STATES - 1989"
Production
Gas Wells
Oil Wells
Total
Disposition
Extraction Loss
Fuel and Lease Use
Pipeline Fuel
Gas Lift
Repressure and Pressure Maintenance
Cycled
Underground Storage (Net Charge)
To Transmission Lines
To Carbon Black Plants
Vented or Flared
Acid Gas (H2S, CO2, H2O)
Plant Meter Difference (UAF)
MMcf
15,735,849
5,262,981
20,998,030
784,502
1,070,452
630,083
Unreporied
2,451,342
Unreported
(310,802)
15,688,047
Unreported
140,532
362,457
182,217
Percent of Total
74.9
25.1
100.0
3.7
5.1
3.0
11.7
-
(1.5)
73.3
-
0.7
1.7
0.9
a Data reported includes gas processing.
B-13
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c
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