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United Slates
Environmental Protection
Agency
GR1-94/0257.24
EPA-600/R-96-080y
June 1996
PB97-142988
METHANE EMISSIONS FROM THE
NATURAL GAS INDUSTRY
Volume 7: Blow and Purge Activities
Energy Information Administration (U. S. DOE)
National Risk Management
ResearcSi Laboratory
Research Triangle Park, ls!C 27711
REPRO, JCE.J8Y:
U.S. Department o* Commerce
National Technical Information Servl'
Springfield, Virginia 2Z161
-------
TECHNICAL REPORT DATA
(Please read iHOruftions on the reverse before comj
I. REPORT NO.
EPA-6QQ/R-96-080g
PB97-142988
S. TITLE AND SUBTITLE
Methane Emissions from the Natural Gas Industry,
Volumes 1-15 (Volume 7: Blow and Purge Activities)
. REPORT DATE
June 1996
6. PERFORMING ORGANIZATION CODE
7. AUTHORS L> Camnbell, M. Campbell, M. Cowgill, D. Ep-
Derson, M. Hall, M. Harrison, K. Hummel, D. Myers,
T. Shires, B. Stapper, C. Stapper, J. Weasels, and *
8. PERFORMING ORGANIZATION REPORT NO.
DCN 96-263-081-17
D. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian International L/LC
P.O. Box 201088
Austin, Texas 78720-1088
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
5091-251-2171 (GRI)
68-D1-0031 (EPA)
12. SPONSORING AGENCY K AME AND ADDRESS
EPA, Office of Besearch and Development
Air Pollution Prevention and Control Division
Research Triangle Park, NC 27711
13. TYPE OF R
Final;
: REPORT AND PERIOD COVERED
3/91-
-4/96
14. SPONSORING AGENCY CODE
EPA/600/13
IB.SUPPLEMENTARY NOTES EPA project officer is D. A. Kirchgessner, MD-63,919/ 541-4021.
osponsor GRI project officer is R. A. Lott, Gas Research Institute, 8600 West Bryn
Mawr Ave.. Chicago. IL 60631. (*)H. Williamson (Block 7). '
is. ABSTRACT-Jhe 15-volume report summarizes the results of E comprehensive program
to quantify methane (CH4) emissions from the U. S. natural gas industry for the base
year. The objective was to determine CH4 emissions from the wellhead and ending
downstream at !±ie customer's meter. The accuracy goal was to determine these
emissions within +/-0. 5% of natural gas production for a 90% confidence interval. For
the 1992 base yeur, total CH4 emissions for the U. S. natural gas industry was 314
+/- 105 Bscf (6.04 +/- 2.01 Tg). This is equivalent co 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
s emissions frnm 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.
17.
KEY WORDS AND DOCUMENT ANAL 'SIS
DESCRIPTORS
b.lDENTIFIf.s/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Emission
Greenhouse Effect
Natural Gas
Gas Pipelines
Methane
Pollution Prevention
Stationary Sources
Global Warming
13B
14G
04A
21D
15E
07C
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (Tills Report)
Unclassified
21. NO. OF PAGES
83
2O. SECURITY CLASS (This page)
Unclassified
EPA Form 2220-1 (9-73)
-------
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'a 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 the U.S. Environmental
Protection Agency, and approved for publication. Mention of trade names or
commercial products does not constitute endorsement cr recommendation for use.
This document is available to the public through the National Technical Information
Service, Springfield, Virginia 22161.
-------
EPA-600/R-96-080g
June 1996
METHANE EMISSIONS FROM
THE NATURAL GAS INDUSTRY,
VOLUME 7: BLOW AND PURGE ACTIVITIES
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: 95-263-081-10
For
GRI Project Manager: Robert A. Lott
GAS RESEARCH INSTITUTE
Contract No. 5091-251-2171
8600 West Bryn Mawr Ave.
Chicago, IL 60631
and
EPA Project Manager: David A. Kirchgessner
U.S. ENVIRONMENTAL PROTECTION AGENCY
Contract No. 68-D1-0031
National Risk Management Research Laboratory
Research Triangle Park, NC 27711
PROTECTED UNDER INTERNATIONAL COPYRIGHT
NATIONALTECHNICAUNFORMATION SERVICE
U.S. DEPARTMENT OF COMMERCE
-------
DISCLAIMER
LEGAL NOTICE: This report was prepared by Radian International LLC as an account
of work sponsored by Gas Research Institute (GRI) 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 tb^
accuracy, completeness, or usefulness of the information contained in this report, or
that the use of any apparatus, method, or process disclosed 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 count 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.
-------
RESEARCH SUMMARY
Title
Contracted
Principal
Investigators
Report Period
Objective
Technical
Perspective
Results
Methane Emissions from the Natural Gas Industry,
Volume 7: Blow and Purge Activities
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 describes a study to quantify the annual methane emissions
from blow and purge activities, which are a significant source of
methane emissions within the gas industry.
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 (COj) 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. Environ-
mental 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 g?s versus coal and oil.
The national annual emissions for blow and purge activities for each
industry segment are as follows: production, 6.5 + 340% Bscf; gas
processing, 3.0 ± 260% Bscf; transmission, 18.5 + 180% Bscf; and
distribution, 2.2 ± 1,800% Bscf.
in
-------
Based on data from the program, methane emissions 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 production. 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 program reached its accuracy goal and provides an accurate estimate
of methane emissions that can be used to construct U.S. methane inven-
tories and analyze fuel switching strategies.
Technical Blow or blowdown emissions refer to the venting of natural gas
Approach contained Inside a pressure vessel, pipeline, or other equipment to the
atmosphere. Purge is the process of clearing air from equipment by
displacing it with natural gas; in the process, some purge gas is emitted
as the air is evacuated from the equipment.
The techniques used to determine methane emissions were developed to
be representative of annual emissions from the natural gas industry.
However, it is impr ctical to measure every source continuously for a
year. Therefore, emission rates for blow and purge activities were
determined by developing annual emission factors for typical practices in
each industry segment and extrapolat'^g these data based on activity
factors to develop a national estimate, where the national emission rate is
the product of the emission factor and activity factor.
Maintenance activities and emergency upsets are the two major causes of
blow and purge emissions. Natural gas is released (blown) as a safety
precaution during maintenance activities conducted on or near the
equipment, or to restore an oxygen-free natural gas environment after
maintenance are finished (purged). The second source of blowdowns
results from emergency or upset conditions that require gas depressuring.
Emission factor data for the various device types were collected from
several sources: site visits, company-tracked data, and company studies.
The blow and purge emissions for the major production emission
categories were calculated from estimates of volume and frequency of
releases based on data collected from site visits. Transmission blow and
purge emissions were calculated from company totals. Transmission
segment emission factors were also applied to gas processing, due to the
similarities between the two industry segments and the lack of gas
processing plant data. Distribution company unaccounted-for gas studies
were used to quantify blow and purge emission factors from the
distribution segment.
IV
-------
The development of activity factors for each industry segment are
presented in a separate report. In general though, activity factors were
based on equipment counts for the production segment, the number of
gas plants for the gas processing segment, station counts or pipeline
miles for the transmission segment, and pipeline miles for the
distribution segment. The national emission factor for each industry
segment was then based on the product of the emission factor for a
generic pneumatic device and activity factor.
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 global warming
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 IPCC and others.
In addition, results from this study are being used by the natural gas
industry to reduce operating costs while reducing emissions, Some
companies are also participating in the Natural Gas-Star program, a
voluntary program sponsored by EPA's Office of Air and Radiation in
cooperation with the American Gas Association to implement cost-
effective emission reductions and to report reductions to the EPA. Since
this program was begun after the 1992 baseline year, uny reductions in
methane emissions from this program are not reflected in this study's
total emissions.
Robert A. Lott
Senior Project Manager, Environment and Safety
-------
TABLE OF CONTENTS
Page
1.0 SUMMARY 1
2.0 INTRODUCTION 2
3.0 OVERVIEW OF BLOW AND PURGE EMISSIONS 3
3.1 Intentional Maintenance Releases 3
3.2 Slowdown from Emergency and Upset Conditions 9
3.3 Results 14
4.0 EXISTING STUDIES AND DATA SOURCES 15
4.1 Site Visit Data , 16
4.2 Company-Tracked Data 17
4.3 Company Studies 18
4.4 Other Studies 19
5.0 EMISSION FACTOR CALCULATIONS 20
5.1 Field Gas Production 20
5.2 Gas Transmission , 30
5.3 Gas Processing Planvs 33
5.4 Distribution 35
6.0 NATIONAL ANNUAL EMISSIONS 38
6.1 Field Gas Production 38
6.2 Gas Transmission 40
6.3 Gas Processing 40
6.4 Distribution 40
7.0 REFERENCES 42
APPENDIX A - Unaccounted-For Gas Studies A-l
A.I PG&E UAF Study A-2
A.2 SoCal UAF Study A-8
APPENDIX B - Source Sheets B-l
B.I Production B-2
B.2 Gas Processing B-12
B.3 Transmission and Storage B-14
B.4 Distribution B-17
VI
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LIST OF FIGURES
Page
3-i Example Compressor Gas Starter 6
3-2 Gas Starter Schematic 7
3-3 Pressure Relief Valve Schematic 11
3-4 Transmission Station ESD/EBD System 13
vn
<-
3 .0
-------
LIST OF TABLES
Page
3-1 Emission Summary 14
5-1 Production Maintenance P.eleases - Gas Well Unloading 23
5-2 Production Maintenance Releases - Compressor Slowdown 24
5-3 Production Maintenance Releases - Compressor Starts 25
5-4 Production Maintenance Releases - Pipeline Slowdowns 26
5-5 Production Maintenance Releases - Vessel Blowdo vns 27
5-6 Production Emergency Releases - PRV Releases 28
5-7 Production Emergency Releases - ESD Releases 29
5-8 Production Gathering Pipeline Dig-In Emissions 31
5-9 Summary of Production Emission Factors 31
5-10 Transmission Company Data 33
5-11 Gas Processing and Transmission Compressor Slowdown Operating
Practices 35
5-12 Distribution PRV Emissions 36
5-13 Distribution Pipeline Slowdown Emissions 37
6-1 Blow and Purge Emission Results 39
A-l PG&E Slowdown Sources A-3
A-2 Sources Not Included in UAF A-6
A-3 PG&E UAF Estimate Methods A-7
A-4 SoCal UAF Sun-nary A-8
A-5 SoCal UAF Estimate Methods A-ll
vin
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1.0 SUMMARY
This report is one of several volumes that provide 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 the 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 quantifies the amount of methane released nationally during blow
and purge operations in natural gas production, gas processing, transmission, and
distribution. Emission estimates for each industry segment were based on data from one or
more of the following source: 1) site-visit data; 2) company-tracked data; 3) company
studies; and 4) equipment calculations. The factors that affect the volume of methane
released are: frequency, the volume of natural gas emitted per event, and the disposition of
the released gas.
Blow and purge activities are a significant source of unsteady emissions (32%
of vented emissions). This accounts for 30.2 Bscf of methane emissions which is about
10% of methane emissions from the natural gas industry.
A n uYivTfwn STTTTvnye awn F»ATA
-------
2.0 INTRODUCTION
"Blow" and "purge" are terms that have different definitions in various
segments of the natural gas industry. In this report, blow (also called "blowdown")
emissions refer to the venting of natural gas contained inside a pressure vessel, pipeline, or
other equipment to the atmosphere. Purge is the process of clearing air from equipment by
displacing it with natural gas; in the process, some purge gas is emitted as the air is
evacuated from the equipment.
The remainder of this report describes the findings of this study. Section 3
summarizes the activities that lead to blow and purge emissions; Section 4 presents the data
sources. The calculation methodology is provided in Section 5. and die national estimates
for blow and purge emissions from the gas industry are provided in Section 6.
-------
3.0 OVERVIEW OF BLOW AND PURGE EMISSIONS
Maintenance activities and emergency upsets are two major causes of blow and
purge emissions in the natural gas industry. Natural gas is released intentionally (blown) as
a safety precaution during maintenance activities conducted on or near the equipment, or to
restore an oxygen-free natural gas environment after maintenance activities are finished
(purged). The second source of blowdown results from emergency or upset conditions that
require gas depressuring.
Some additional sources of blow and purge methane emissions are gas required
to start a compressor, gas emitted during sampling, and gas released while removing liquid
from a drip pot. Compressor start gas is the only significant category; the other categories
are negligible. These sources of natural gas are vented to the atmosphere as part of the
normal operation of a gas facility. The company may or may not include these in its
definition of blow and purge gas.
3.1 Intentional Maintenance Releases
Maintenance activities requiring blowdown provide a safer working environ-
ment when it is necessary to enter a vessel, in which case, all flammable gas must be
removed. Likewise, a reduction in the internal flammable gas inventory may be required for
external equipment maintenance. Conversely, when equipment previously open to the
atmosphere is placed back in service, air must be removed (or purged) to prevent a flam-
mable mixture of gas and oxygen. An operator may displace the air directly with natural gas
or with an inert gas, such as nitrogen, and then displace the nitrogen with natural gas.
Depending on the specific company equipment and practices, an operator may also vent some
of the nitrogen and natural gas mixture to the atmosphere to reduce the inert gas con-
centration before the equipment is placed back in service.
-------
On any maintenance operation that requires blowdown, the equipment may vent
from its operating pressure directly to the atmosphere, or partial recovery may be ac-
complished by moving some gas into a lower-pressure gas system (if available), and then
venting the remaining gas. Lower-pressure recovery systems include recovery gas systems,
fuel systems, downstream distribution systems, and control systems, such as flares.
Equipment configurations and company practices vary widely on the use of recovery steps.
Blowdown from intentional maintenance releases can be put into the following
equipment categories:
• Compressor blowdown;
e Compressor starts;
6 Pipeline blowdown;
• Vessel blowdown;
• Gas wellbore blowdown;
• Miscellaneous blowdown of small volume sources (meter and pressure
regulator blowdown, drip pot blowdown, odorizer blowdown, etc.); and
• Miscellaneous well activities.
Compressor Blowdown
Many facilities have multiple compressors, some of which are idle at any given
tune. These idle compressors, or "hot spares," are service-ready machines that can be put
on line when a compressor is shut down. In general, spare compressors are used when
mechanical operating problems develop on the primary machine, to distribute the operating
hours equally among several machines, or to perform preventive maintenance. Depending on
the reason for the compressor shutdown and on the company's standard practices, the
operator may or may not depressure compressors each time they are shut down. Companies
may do one of the following:
-------
1. Leave the compressor under full suction pressure (no blowdown);
2. Depressure the compressor to a lower-pressure recovery system, and
either leave the compressor at that lower-pressure (no blowdown) or
uepressure to the atmosphere (partial blowdown); or
3. Depressure the compressor from full operating pressure to the at-
mosphere (full blowdown).
Naturally, each of these practices results in a different emission rate per event.
Compressor Starts
Most gas compressors in the natural gas industry are started with a gas starter
(as opposed to an electric starter, such as used for a car engine). The gas starter uses a
small turbine whose blades spin when high-pressure supply gas is introduced to the starter.
The supply gas is usually vented to the atmosphere after exiting the starter. Figures 3-1 and
3-2 show typical gas starters for compressors.
Compressed air may power the starters, but natural gas is used more often than
air in many facilities. The starter vent gas can also be directed to a control system rather
than to the atmosphere, but that practice is not common. Both the gas type (air or natural
gas) and the disposition are accounted for in the emission calculations.
Pipeline Blowdown
Pipeline blowdowns may occur when repairs are required, when old pipelines
are permanently removed from service, or when new pipelines are placed in service. Large
segments of pipeline (on the order of many miles) can be pulled down usiug a recovery
system before atmospheric blowdown occurs.
-------
STARTER MOTORS
OUTLET HOSES
PILOT-OPERATiO
SHUT-OFF VALVE
STRAINER
SOLfNOID-OPEHATED
Figure 3-1. Example Compressor Gas Starter
-------
"OUT"
PORT
TO STARTER
CONTROL
VALVI
LUBRICATOR
£
RELAY
V&LVi
LUBE
SUPPLY
LINE
STARTER
CONTROL
VALVE
VENT
EXHAUST
AIR
PRESSURE
GAUGE
SHUT-OFF
VALVI
SUPPLY
Figure 3-2. Gas Starter Schematic2
aatViprprt at earh site from interviews with nnerators. The annual emission far.tor
-------
Vessel Blowdown
Vessels ar*> blown down more frequently than gas pipelines, since vessels
usually have more working parts and thus more opportunities for failure. A separator may
require blowdown to replace the level control float, service internal elements such as
demisters, or clean accumulated solids out of the vessel. Gas may vent directly to the
atmosphere or to a flare if available (as in some gas processing plants). In some instances,
the gas is partially recovered by moving some gas into a lower-pressure gas system (such as
a fuel system, if available) and then venting the remaining gas.
Gas Wellbore Blowdown
Operators may routinely open some low flow rate gas wells to the atmosphere
to remove salt water accumulation in the wellbore. Low-pressure natural gas wells can
accumulate salt water and other fluids in the wellbore if the gas flow rate is not sufficient to
lift out the free liquid. To keep the gas flow from declining, this type of low-pressure gas
well is sometimes isolated from the gathering pipeline and opened to a surface tank or pit.
The surface tank has no backpressure (as opposed to the pipeline), so the gay flows at a
higher rate and lifts out the water. The gas is released directly to the atmosphere during this
practice.
Miscellaneous Equipment Blowdown
Operators may also blow down miscellaneous equipment to remove
accumulated material. Many small pieces of pipeline equipment are routinely blown down:
drip pots that collect liquids, meter runs for orifice plate changeout, and odorizers. Most of
the emissions from these miscellaneous categories are insignificant when considered on a
national basis.
starters nmi/prpd hv natural oas and fhp frarrirm nf starters
-------
The factors that affect the volume of irvXnane emissions from maintenance
blowdown include:
6 Frequency of blowdown (times/yr/equiprnent);
• Volume (Scf) of methane released per blo\vdown event (a function of
pressure, volume withia the equipment, and gas composition); ar,d
e Disposition of the blowdown gas (atmosphere or control system).
Miscellaneous Well Activities
Completion flaring and well workovers are additional maiucnance activities
associated with gas well production. Drilling operations typically use the hydraulic pressure
of drilling mud to overbalance the formation pressure and keep the oil and gas in the
formation while drilling. The amount of gas released during drilling is minimal. However,
before producing gas from a new well, the facility must either know the reservoir pressure
and size or measure the gas flow rate so that the equipment can be sized. To measure the
gas flow rate, the gas from the well is routed through a meter and then flared.
Well workovers pull the tubing from the well to repair tubing corrosion or
other downhole equipment problems. If the well has positive pressure at the surface, the
well is "killed" first by replacing the gas and oil in the column with (heavier) water or mud,
thus over-balancing the formation and stopping all oil and gas flow. A small amount of gas
is released as the tubing is removed from the open surface casing.
3.2 Blowdown from Emergency aitd Upset Conditions
For the emergency release of gas, uic iv ie&se is usually caused by a safety
device, such as a spring-loaded pressure relief valve (PRV» on a vessel or an automatic
blowoff valve on a transmission pipeline station. An exampe or ail emergency blovvdown is
the shutdown and depressuring of a transmission station that automatically results from the
TART.F. 5-1. PRODUCTION MAINTF.NANrF. RFJLF.ASF.K
-------
detection of flammable gas in a compressor building. The emergency blowdown category
relates to the maintenance blowdown category, in that emergency blowdowns are usually
followed by some equipment maintenance to correct or eliminate the emergency situation.
PRV lifting is not usually considered a blowdown, since PRV lifts do not depressure an
entire vessel or station, but merely relieve pressure above a certain set point. However,
since PRV lifts result from unusual, upset, or emergency conditions, they are included in the
emergency blowdown category of this report.
Another emergency condition that can result in the release of gas from a
pipeline is a "dig-in." Dig-ins are ruptures of gathering pipelines caused by unintentional
(often third-party) damage. These raptures are isolated and repaired by the pipeline
operator.
Unlike some maintenance releases, emergency blowdowns by their nature are
not recovered, but are typically vented directly to the atmosphere. Blowdown from
emergency conditions can be classified as PRV lifts, station automatic blowdown, or pipeline
dig-ins.
PRV Lifts
PRVs, which are also called safety valves 01 pop-off valves, protect a vessel
from rupturing due to high pressure. Figure 3-3 shows a sketch of a PRV. If emergency
conditions occur, where internal pressures exceed the vessel's design pressure, the valve lifts
and allows gas to flow out of the vessel. The pressure at which the valve lifts is set by the
size and tension of the spring that holds down the PRV seat. The size of the PRV is set by
the flow contingency (emergency scenario) for which the valve is designed.
3orne vessels may also use rupture disks (RDs) which are similar to PRVs and
perform the same funct'on. These devices act as a secondary protection mechanism for a
vessel with a higher release pressure setpoint than the PRV. Should the PRV fail to relieve
10
TABLE 5-2. PRODUCTION MAINTENANCE RELEASES
-------
Figure 3-3. Pressure Relief Valve Schematic3
11
TAUT-IT
-------
PRVs can be routed to control systems such as flares, but they are often vented
directly to the atmosphere. The annual methane release rate for » PRV is set by:
• Frequency of lifts (times/yr/PRV);
e Volume (scf) or methane released per event, which is a function of
duration, PRV size, lift set pressure, and gas composition; and
Q Disposition of the discharge (atmosphere 01 control system).
Station Automatic Slowdown
Some facilities have manual or automatic safety systems that shut down all
rotating equipment when emergency conditions (suj.h rs fire or natural gas in the atmosphere)
are detected. A few of these systems also depressure the facility by venting gas to the
atmosphere, so that natural gas will not feed a fire. An example of such a system is a
transTiission compressor station emergency shutdown (ESD) and emergency blowdown
(EBD) system (see Figure 3-4), where an automatic shutdown and blowdown can be
triggered by gas detectors in uie compressor building, or it can be triggered manually if a
fire starts. The ESD system shuts down the compressors and blocks in the pipelines leading
to the facility. The EBD system then may open blowoff valves that depressure the facility to
the atmosphere.
Annual methane releases from station blowdowns can be quantified on the basis
of the following data:
e Average frequency of station blowdowns (times/yr/station);
e Volume (scf) of methane released per event, which is a function of
normal operating pressure, volume within the station, and gas com-
position; and
e Disposition of the discharge (atmosphere or control system).
12
TATW.F. $-d PROniir.TION MATNTF.NAWF. TiF.T.F.ASFS
-------
Gas Ir.t.o
Station
Remotely
Operated
Pipe Open to Atmosphere
Pain Cap
Remotely
Operated
Quarter-turn Remotely
Operated Valve
Gas Out
of Station
BSD Valve
'C Valve
Figure 3-4.
System
-------
Pipeline Dig-ins
Dig-ins are unintentional damage to a buried gas pipeline. Gas is released
when a pipeline is punctured or ruptured during excavation or construction work, usually by
earth-moving construction equipment excavating near the burie.i gas pipeline. Gas emissions
from pipeline dig-ins can be estimated by quantifying the flow rate and duration of the
release before the pipeline segment was isolated for repair.
3.3 Results
This report quantifies methane blowdown emissions for each natural gas
industry segment by estimating releases from the various types of blowdowns. The estimates
are based on data provided by natural gas companies or on data collected during site visits
conducted for this project. The resulting estimates of national emissions from blow and
purge activities are shown in Table 3-1.
TABLE 3-1. EMISSION SUMMARY
Annual Methane Emissions, 90% Confidence
Industry Segment Bscf Upper Bound
Production 6.5 340%
Transmission and Storage 18.5 180%
Gas Processing 3.0 260%
Distribution 2.2 1,800 %
The basis for these numbers is explained in Sections 4 through 6.
14
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4.0 EXISTING STUDIES AND DATA SOURCES
The data used for this project came from one cf three sources:
1. Site visit data — During site visits, data were collected on the
frequency of release events, internal volumes, and pressures through
observation and interviews. Data on well workovers were collected
during site visits by Pipeline Systems Incorporated (PSI>.4
2. Company-tracked data — This includes data already internally tracked
by a company on a regular basis. The data apply to all of the
company's facilities.
3. Company studies — Some companies, although they might not
regularly track all vented volumes cf gas, may perform one-time studies
to estimate such volumes for their system. Two examples of such
studies were conducted by Pacific Gas and Electric (PG&E)5 and
Southern California Gas Company6 (SoCal) on unaccounted-for (UAF)
gss.
The quality of company-tracked data is believed to be the best ot the three
sources since it entails a regular accounting of the frequency of release events and uses
detailed company data for the gas volumes. Company studies have a slightly lower quality
since the results are calculated only once, but they do use detailed compare data to produce
the estimate. Site visit data are acceptable, but the quality of the data is the lowest of the
three blowdown estimation techniques because it relies on operators' recollections of the
frequency of release events.
In the production segment, none of the companies had company-tracked data or
company reports. Therefore, all the blowdown calculations for that segment are based on
site visit data. In the transmission, storage, and distribution segments, many companies did
have company-tracked data or company studies, so company data were used for these
segments. Site vis»i data were collected for the transmission and storage segments, but those
data were not used as the basis for the methane emission estimates because of the lower
quality of the data (operator recollection). In the gas processing segment, no companies had
15
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similar to the compressor sections of gas plants, data from the transmission and storage
segment were used as the basis for gas plant emission estimates. Site visit data were
available for the gas processing segment, but were not used.
The techniques used to calculate methane emission volumes for each of the
three data sources are described in Sections 4.1 through 4.4. The characteristics of the
emissions for each release type we-.s discussed in Section 3. In general, annual emission
averages are generated by estimating the frequency of the releases, the volume per event, and
the disposition of the gas.
4.1 Site Visit Data
Slowdown practices vary from company to company and even from site to site
within a company. The hardware installed at a facility has a large effect on blowdown
emissions, and local regulations may also affect practices. Because of variability in company
practices within the industry, averages were established by visiting a number of facilities.
The site data were collected as follows:
1. From interviews during site visits, the freq \' of maintenance and
emergency blowdowns was determined.
2. For maintenance blowdowns, the major types (compressor blowdown,
compressor start, pipeline, vessel, gas wellbore, or other) were deter-
mined from interviews and observation during a site visit. The volume
of gas released per event and the disposition of the released gas (i.e.,
the amount vented to the atmosphere) were established from interviews
or company records.
3. For emergency blowdowns, the following information was gathered:
® For emergency ESD shutdowns, the existence and design
operation of any ESD system (activity factor data);
e Total count of PRVs to the atmosphere at a facility (activity
factor data);
16
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8 From operator recollection or records, the average frequency of
PRV lifts and station depressuring that occurs at the facility, and
the disposition and duration of the events (emission factor data);
• PRV lift data from company records: size, lift set pressure,
disposition (for mass emission factor data);
• Station blowdown volume from company records or from the
actual station volume and operating pressure; and
e Emissions due to dig-ins from company records.
4.2 Company-Tracked Data
Company-tracked data consist of the annual gas volumes tracked by a com-
pany's accounting department. These volumes are made up of some combination of the
following categories:
• Compressor station venting — compressor blowdown, compressor
starts, and emergency station blowdown (ESD/EBD);
• Pipeline venting;
9 Other maintenance activities — completion flaring, well workovers,
etc.; and
• Miscellaneous equipment — sampling, drip blowdown, odorizer blow-
down, orifice plate blowdown, etc.
Companies that tracked vented gas volumes did so by one of two methods:
1) calculations were performed monthly at each compressor station, and total monthly
volumes were reported to the company's main accounting department, or 2) the frequency of
events (compressor blowdowns) was reported monthly to the accounting department, which
used a pred'^ermined volume per event to determine total volumes. Both methods may use a
volume per event calculated from the exact internal dimensions of the equipment and the
particular station's operating pressure.
17
-------
Company-tracked data were provided by six transmission companies that
operated pipelines, transmission compressor stations, and storage stations. Only one of the
six companies tracked miscellaneous volumes, but the miscellaneous volumes are considered
to be insignificant. A company might only track pipeline blowdown volumes or compressor
station blowdown volumes; only four of the six companies tracked both.
4.3 Company Studies
Two companies, PG&E and SoCal, performed unaccounted-for (UAF) gas
studies that quantified the blowdown volumes for the same categories listed previously:5i6
• Compressor station venting;
• Pipeline venting; and
8 Miscellaneous equipment.
The miscellaneous equipment category was found to be insignificant (< 0.66%
of total company blow and purge). However, both companies found the first two categories
to be significant.
The studies actually sought to quantify the amount of blowdown not currently
being accounted for by the company's system. At PG&E, this was all of the blowdown gas,
since PG&E did not previously account for vented losses: At SoCal, some of the blowdown
events were accounted for, and some were not. The SoCal accounted-for and unaccounted-
for blowdown volumes were combined to obtain the total vented quantity for SoCal.
Summaries of the PG&E and SoCal studies appear in Appendix A. The results of these UAF
studies were used along with tracked data from other companies to develop several blow and
purge emission factors.
18
-------
4.4 Other Studies
This study of the blow and purge emissions focused on the major contributors
to these emissions (e.g., station blowdown, pipeline blowdown, compressor/vessel
blowdown, ESD/PRV releases). However, for completeness, minor emission sources were
also considered using data from studies:6-7-8
Well workover emissions were estimated by Pipeline Systems
Incorporated (PSI) on the basis of information from two gas production
facilities.
The Energy Information Agency and a gas production company
provided information on the gas production of exploratory wells and
drilling practices, respectively, which was used to estimate completion
flaring emissions.
Six distribution companies participating in a cooperative underground
leak measurement program provided data on the volume of blowdown
gas in the routine company reports on unaccounted-for gas.
19
TABLE 5-10. TRANSMISSION COMPANY DATA
-------
5.0 EMISSION FACTOR CALCULATIONS
This section describes the emission calculations for the maintenance and
emergency blowdowns in each industry segment. Slowdown volumes vary widely from site
to site. The exact state of equipment repair, available control and recovery equipment
resources, and company procedures cause the emissions for a similar blowdown to vary from
one company to another and from one site to another.
5.1 Field Gas Production
The production segment contains wells, separation stations, gathering lines, and
gathering compressor stations. Blowdown emissions result from the maintenance of these
units. Maintenance blowdowns of low-pressure gas wells, gathering pipelines, compressors,
and vessels are usually vented to the atmosphere. Piloted flares are rare. Many well sites
have a vent line that the company may call a "flare" in the production field, but this is a
misnomer, since it is most often a simple open-ended pipe with no pilot or igniter and does
not burn gas.
Emergency or upset condition releases result primarily from ESD system
blowdowns for offshore production platforms and from PRV or RD discharges for the
onshore field production segment. Most ESD, PRV, and RD blowdowns are vented directly
to the atmosphere. Field automatic station blowdown devices are rare, and manual
emergency shutdowns of gathering lines are extremely infrequent. Dig-ins of production
gathering lines, though minor, are a source of emissions due to mishaps.
The blowdown emissions for the major production emission categories were
calculated from estimates of the volume and frequency of releases based on data collected
from 25 site visits. The volume of gas released times the frequency of events resulting hi
released gas equals the annual emissions. Volumes were calculated for each site using
equations of state, observed vessel dimensions, and pre-blowdown pressures. Frequencies
20
-------
were gathered at each site from interviews with operators. The annual emission factor
(scf/blowdown) for each site was calculated as follows:
EF - Volume x Frequency x % Methane (1)
where:
Volume = Gas released to the atmosphere during a release event
(scf/event).
Frequency = Number of events annually.
% Methane = 78.8 mol % + 5% for the production segment.
The volume of gas released was calculated differently for each type of
blowdown event. The volume calculation methods are described below.
Low-Pressure Gas Well Unloading — The volume of gas released due
to unloading was based on a scaled gas flow rate and the time required
to unload the well. To account for the changing gas flow rate as water
accumulates in these wells, the average gas flow rate was scaled as-
suming that 25% of the time the well operated at 25% of the average
gas flow rate, 50% of the time the well operated at 50% of the average
gas flow rate, and 25% of the time the well operated at the average gas
flow rate. This results in a scaling factor of 0.5625 which was mul-
tiplied by the gas well flow rate to estimate the volume of gas released
per unloading event.
Compressor Blowdown — The volume of gas inside the block valves
(scf) is a function of pressure and volume. Compressor blowdown
volumes were also corrected for the fraction of compressors that release
gas to the atmosphere. (Some compressors vent gas to control systems.)
Compressor Starts — Some general company data were available on
compressor starter gas consumption rates. Several sites provided
estimates for reciprocating engines of 200 scf/minute for all starters.
The total volume of gas per start was calculated using this emission
rate, the tune required to start the compressor, the fraction of
21
-------
compressor starters powered by natural gas, and the fraction of starters
that vent gas to the atmosphere.
Pipeline Slowdown — The volume of gas released due to blowdown
per mile, corrected for the pipeline pressure, was based on the diameter
and length of various pipe segments.
Vessel Blowdown — Vessel blowdown emissions were estimated from
the internal dimensions of the vessel and corrected for the vessel pres-
sure. This value includes blowdowns from separators, dehydrators, and
in-line heaters. (Compressor blowdowns and starts are considered
separately.)
PRV Discharge — The average volume released at the lift pressure was
calculated for an average-size PRV and an average duration, and cor-
rected for the fraction of PRVs that release gas to the atmosphere.
ESD Blowdown — This category was only observed for off-shore
platforms. The emission volume was based on the platform volume and
corrected for the fraction of platforms with ESDs and the fraction that
vent gas to the atmosphere.
Tables 5-1 through 5-7 show the site values used in the calculations. The
volume of gas released per year weighted by the count of each equipment category became
the emission factor for each source. The emission factors were then multiplied by the
volume percent of methane in natural gas (78.8% for production).9
Determination of the emission factor for well workovers was based on data
from two gas production fields collected by Pipeline Systems Incorporated (PSI).4 PSI
estimated that the methane emissions due to workovers at the first site were 670 scf/well, on
the basis of 1 of 21 gas wells being worked over annually. For the second site, 8 of the
approximately 400 wells are worked over each year. PSI assumed that four of the wells
were high-pressure wells, at depths of 12,000 ft and that four wells were low-pressure wells
at depths of 5000 ft. For a well tubing size of 2-3/8 inches, the annual methane emissions
due to well workovers were estimated to be 4,238 scf/workover. Averaging these two
estimates, results in the workover methane emission factor of 2,454 + 459% scf/well
workover.
22
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TABLE 5-1. PRODUCTION
GAS WELL
MAINTENANCE RELEASES
UNLOADING
Site
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Number of
Wells Number of
Number of Requiring Events/Year/
Gas Wells Unloading Site
0
80
0
13
12
6
130
26
138
321
500
500
600
53
800
1,000
520
1,439
100
15
2
12
80
40
TOTALS 6,387
% WELLS
REQUIRING UNLOADING
0
?0 12
0
13 1
0
0
43 103.2
5 2.5
55 193.2
25 72
0
0
0
53 1
600 3600
1,000 2600
520 6240
245 89,425
0
0
2 24
0
0
0
2,641
AVERAGE ANNUAL UNLOADING
EMISSIONS, scf natural gas/unloading well
4jiiHial
Scf/Event Natni -al Gas
based on Emission!)
Sealed Flow Set/Site
52,500 630,000
37,969 37,969
0
0
28,125 2,902,500
2,524 6,310
938 181,125
703 50,625
10,631 10,631
3,516 12,656,250
39,375 102,375,000
675 4,212,000
471 42,102,408
41,006 984,150
166,148,968
41.4% ± 45%
62,907 ± 343%
23
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TABLE 5-2. PRODUCTION MAINTENANCE RELEASES
COMPRESSOR FLOWDOWN
Site
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
M
18
19
20
21
22
23
24
25
TOTALS
ANNUAL
Company
Compressor
Count
56
4
11
12
1
1
37
0
31
50
5
3
2
17
1
2
4
4
241
Blowdown/Year/
Compressor
(All Compres- Percent to
sors) Atmosphere
4
23
19
4
36
12
8
24
2.5
1.7
13.3
13.3
12
13.3
0
0
100
93.8
0
0
100
lOO
100
100
100
100
100
100
0
30
0
AVERAGE, scf natural gas/compressor
Annual
Natural Gas
ScPEveist Emissions
Basis Scf/Event Scf/Site
0
0
Site data 612 154,836
Average 421.3 90,101
0
0
Site data 40 17,760
Average 421.3 104,482
Average 421.3 505,560
Site data 9,200 115,000
Site data 9,200 46,000
Average 421.3 11,207
Average 421.3 95,256
Site data 612 7,344
0 0
Average 421.3 6,739
0 0
1,154,285
4,790 ± 147%
24
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TABLE 5-3. PRODUCTION MAINTENANCE RELEASES
COMPRESSOR STARTS
Site
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
TOTALS
ANNUAL
Annual
Company Starts/ Natural Gas
Compressor Percent Compressor/ Percent To Duration,- Starters/ Emissions
Count On Gas Year . Atmosphere minute Compressor Scf/Site
56 0
4 100 26
11 0 26
12 92 56
1 0 12
1 100 36
37 95 12
0
31 100 8
50 100 24
5
3
2
17 100 7.3
1 100 U
?,
4
4
241
AVERAGE, scf natural gas/compressor
100 1 0
100 0.5 1 10,400
100 1 0
I'lO 0.17 1 20,608
0 1 0
0 1 0
100 10 1 840,000
100 10 1 496,000
100 3 1 1,200,000
100 0.17 0.647 2,730
100 5.13 1 12,320
2,582,058
10,714 + 156%
25
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TABLE 5-4. PRODUCTION MAINTENANCE RELEASES
PIPELINE SLOWDOWNS
Site
1
2
3
4
5
6
7
g
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
TOTALS
ANNUAL
Total Company
Miles
150
50
50
50
15.4
11
40
8
5
9
5
20
25
10
449
AVERAGE, scf natural
Natural Gas
Blowdown/ Percent to Emissions
Yr/Mile Atmosphere ScPEvent
0
0
0
0.120 100 20,000
0.0,6 100 17,817
0 iOO 25,514
0.025 100 50,000
0
0.026 100 1,3 18
0
0.067 100 400
0.017 100 400
0.080 100 400
0.030 100 400
gas/mile
Annual
Natural Gas
Emissions
Sc#Site
0
0
0
120,000
4,454
0
50,000
0
176
0
133
133
800
120
175,817
392 ± 32%
26
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TABLE 5-5. PRODUCTION MAINTENANCE RELEASES
VESSEL SLOWDOWNS
Site
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
TOTALS
ANNUAL
Vessu Slowdown/
Count/Site Yr/Vessel
973 0.01
136 2.50
90 0.58
120 0.10
39 0.21
20 0.20
107 0.5
78 0.06
296 0.5
86^ 0.0 1
502 0.02
125 0.5
3,351
AVERAGE, scf natural gas/vessel
Annual
Natural Gas Natural Gas
Percent to Emissions Emissions
Atmosphere Set/Event Scf/Site
100 13 157
100 221 75,140
100 618 32,260
87.f 379 3,980
0 956 0
0 956 0
100 365 19,528
100 1,896 8,532
100 715 105,820
100 2,047 20,470
100 905.9 9,059
100 905.9 56,618
331,562
99 ± 265%
27
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TABLE 5-6. PRODUCTION EMERGENCY RELEASES
PRV RELEASES
Pressure Relief Valve (PRV} Releases
No. Lffl/Yr/ Percent To mnJ Avg. Avg. Set Scf NG/
Site PRV PRV Atmosphere Lift Size Press hr
On-Shore
1 1,694 !00 0
2 80 2 100 llxl 250 38,674
3 80 0,5 100 1 3x3 100 15,223
4 101 0.0099 100 60 1.5 x 2 100 15,223
5 30 0.0030 50 2 1.5 x 2 1,440 247,408
6 20 0.05 50 2 1.5 x 2 1,440 247,408
7 84 0 100 llxl 1,000 162,103
8 52 0.0577 100 1 1x1 1,500 247,408
9 156 0 100 1 1 x 1 1,000 162,103
10 541 0 100 Olxl 1,500 147,408
11
12
13
14 500 0.0004 100 1 38,674
15
16
17
18
19
20
Off-shore
21
22
23
24
25
ON-SHORE 3,338
TOTALS
ANNUAL ON-SHORE AVERAGE, scf natural gas/PRV
Annual
Scf
NG/Site
0
103,131
10,149
15,223
375
4,123
0
12,370
0
0
129
145,500
44 ±252
28
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TABLE 5-7. PRODUCTION EMERGENCY RELEASES
ESD .RELEASES
Emergency Shutdown (ESI)} Releases
Site
On-Shore
1
2
3
-------
Completion flaring is necessary to measure the flow rate of an exploratory
well to size the production equipment. The length of time required to complete the flow
measurement is approximately one day, according to an industry contact experienced in
drilling practices. The flow rate of gas at completion is the highest that the well will
produce. For the purposes of estimating emissions, maximum gas flow rates were not
available. Instead, an average natural gas production per gas well of 16.97 MMcfy was
used.10 Assuming a flaring efficiency of 98% and adjusting for the methane composition of
production gas (78.8 mol%), the annual completion flaring emission factor is 733 + 200%
scf/completion well. (The confidence interval was based on engineering judgement of the
data quality.)
No production records were available on gathering pipeline dig-ins. However,
several transmission and distribution companies track this emission source. Table 5-8
summarizes the distribution segment dig-in emissions. Assuming that production dig-ins
occur less frequently than distribution dig-ins, the distribution emission factor per mile was
reduced by one-half. This is a reasonable assumption, given that the human activity level
(and the resulting likelihood of a dig-in) near most production facilities is low, while human
activity near most distribution networks is high. The resulting annual methane emission
factor for production dig-ins is 669 ± 1,92.5% scf/mile (adjusted for the methane com-
position in production of 78.8 mol%).
The production emission factors, adjusted for the production methane com-
position of 78.8 mol%, are summarized in Table 5-9. In addition, the number of sites used
to develop the emission factors is provided for each category.
5.2 Gas Transmission
Gas transmission systems are mostly pipelines and therefore have fewer
"facilities" than the production and gas processing segments of the natural gas industry.
30
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TABLE 5-8. PRODUCTION GATHERING PIPELINE DIG-IN EMISSIONS
TOTALS
ANNUAL
ANNUAL
Company
1
2
3
4
EF FOR DISTRIBUTION
EF FOR PRODUCTION,
Annual
Dig-in Emissions,
Mscf
91,178
170,457
19,581
10,543
291,669
, Mscf methane/mile
Mscf methane/mile
Pipeline
Miles
58,024
82,337
24,916
18,713
183,990
Annual
Uig-in Methane
Emission Factor,
scf/mile
1.57
2.07
0.79
0.56
1.59+ 1,900%
0.67 ± 1,900%
TABLE 5-9. SUMMARY OF PRODUCTION EMISSION FACTORS
Category
Gas Well Unloading
Compressor Slowdown
Compressor Starts
Vessel Slowdown
Pipeline Slowdown
Completion Flaring
Well Workovers
PRV Slowdown
ESD Slowdown
Dig-ins
Annual
Methane Emission Factor
49,570 scf/LP well ± 344%
3,774 scf/compressor ± 147%
8,443 sctfcompressor ± 157%
78 scf/vessel ± 266%
309 scf/mile + 32%
733 scf/completion well ± 200%
2,454 scf/workover ± 459%
34 scf/PRV ± 252%
256,888 scf/platform ± 200%
669 scf/mile ± 1,925%
Number of Sites
12 sites
17 sites
12 sites
12 sites
18 sites
1 site
2 sites
13 sites
6 platforms
4 sites
31
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There are two common types of above-ground pipeline transmission facilities: meter and
pressure regulation (M&PR) stations and compressor stations. The compressor stations
usually have PRVs vented to the atmosphere and ESD/EBD systems that isolate the site and
depressure it to the atmosphere. Flare systems are rare, but some compressor station sites
do have lower-pressure gas recovery systems (such as fuel saver systems) that can be used
to recover some of the blowdown gas. In the United States, M&PR stations typically do
not have ESD/EBD systems, flare systems, nor gas recovery.
Gas storage facilities that are considered part of the gas transmission segment
can be located below or above ground. The below-ground facilities are similar to transmis-
sion compressor stations and production fields and therefore can be characterized in the
same way. The above-ground, liquefied natural gas (LNG) facilities are similar to gas
plants in their general maintenance venting practices.
Compressor stations (for storage or transmission) typically have BSD and
EBD systems. These systems are tested at least annually, but practices and regulations
concerning full EBD testing (which vents gas) vary. Therefore, some stations do not emit
any gas during this practice.
Blowd, vn volumes and frequencies were calculated from company totals for
multiple stations from tracked or studied totals. The company-tracked data were available
from either company gas use estimates reported to accounting dep- -nents from each site
(accounted-for gas), or from special UAF gas studies that searched for unmetered company
gas use. Most of the company data could be separated into two event types: station
blowdowns (includes compressor blowdowns, compressor starts, PRV lifts, ESD activation,
and other venting sources) and pipeline blowdowns. These data are summarized in Table
5-10.
32
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T4BLE 5-10. TRANSMISSION COMPANY DATA
Annual Station
Slowdown Emissions,
Company Mscf
1
2
3
4
5
6
7
8
TOTALS
ANNUAL
ANNUAL
120,757
272,589
33,731
-
325,418
Unknown
60,956
194,541
1,007,992
AVERAGE, Mscf natural
AVERAGE, Mscf natural
Annual Pipeline Total Annual Total
Blowdowns, Slowdowns, Number of
Mscf Mscf Stations
189,044
11,358
138,988
--
Unknown
161,628
750,000
315,058
1,566,076
gas/station
gas/mile
309,801
283,947
172,719
172,776
Unknown
Unknown
810,956
509,599
11
15
27
(19)'
47
(48)
69
47
216
Total Number
of Pipeline
Miles
3,857
4,000
5,886
(5,450)
(4,725)
7,896
14,666
9,915
46,220
4,667 ± 262%
33,9 ± 236%
'Parentheses indicate that the value is not included in the total count because a station or pipeline emission
rate was not available.
The transmission segment emission factors are calculated from the average of
the site values for blowdown emissions per station and blowdown emissions per pipeline
mile. Correcting the values shown in Table 5-10 for the methane composition of gas in the
transmission and storage segment (93.4% ± 1.5%)9 results in annual emission factors of
4,359 ± 262% Mscf/station and 31.6 ± 236% Mscf/mile.
5.3
Gas Processing Plants
Gas plants recover hydrocarbon liquids (such as propane, butane, and NGLs)
from "wet" natural gas and send the "dry" residue gas to sales. The liquid portion of the gas
plant handles very little methane; therefore, blowdowns from the liquid-side of the plant are
not considered in this report. The major areas of interest for methane emissions are limited
to the front end operation of the plant: dehydration, liquids recovery, gas compression and
residue gas handling. Most of the gas blowdown from a gas plant comes from the natural
gas compressors, which are nearly identical to those of transmission compressor stations.
33
-------
Plant blowdown practices in gas processing vary considerably. Many gas
plants have piloted flare systems. However, very few plants route all PRVs and maintenance
blowdown lines to the flare. Some gas plants have gas recovery systems (such as the fuel
saver system) that allow for some maintenance blowdown to be partially recovered, but most
gas compressor blowdown vents are routed to the atmosphere.
Many gas plants have emergency shutdown (BSD) systems that can isolate the
plant and stop the gas compressors; however, most of these systems do not depressure the
plant.
Similar to the transmission segments, maintenance blowdowns at gas plants
consist primarily of the following events: compressor blowdown, compressor starts, and
miscellaneous vessel blowdown. Table 5-11 compares the blowdown practices of the two
industry segments. The practices were determined from company data and site visits. The
gas plant and transmission practices are comparable.
Because of the similarities in station blowdown practices between the gas
processing and transmission segments, company-tracked data for transmission stations were
applied to the gas plants. It is believed mat the quality of the transmission company data is
superior to that of the individual site blowdown data gathered for 11 gas plants. Therefore,
the emission factor for gas processing plants was based on the annual transmission compres-
sor station emission factor (4,667 scf natural gas/plant) but corrected for the methane
composition in gas processing of 87% ± 5%, rather than the transmission methane com-
position of 93.4% ± 1.5%.9 The resulting methane emission factor for gas processing is
4,060 ± 262% Mscf/plant for 1992.
34
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TABLE 5-11. GAS PROCESSING AND TRANSMISSION COMPRESSOR
SLOWDOWN OPERATING PRACTICES
Gas Processing Transmission
Slowdown Operating Practice (Based on 11 (Based on 8
Sites) Companies)
Reciprocating Engines:
% with blowdown 'ines to the atmosphere 62.5% 100%
% that are depressured to the atmosphere when idle 25% 29%
% that are held at operating pressure when idle 75% 65%
% that are partially depressured to a lower pressure system when 0% 6%
idle
% with gas starters that vent to the atmosphere 25% 0%
Turbine Engines:
% with blowdown lines to the atmosphere 100% 100%
% that are depressured to the atmosphere when idle 100% 92%
% that are held at operating pressure when idle 0% 8%
% that are partially depressured to a lower pressure system when 0% 0%
idle
% with gas starters that vent to the atmosphere 67% 100%
5.4
Distribution
The distribution segment consists primarily of pipeline networks. Blow and
purge emissions in distribution pipelines are mainly due to PRV releases, dig-ins, or pipeline
blowdowns. PRVs are used in the distribution network to prevent the over-pressure of
pipelines. Typically, PRVs are used in conjunction with pressure regulators as a secondary
protection mechanism hi the event of regulator failure. Gas is released during any
emergency actuation of the PRVs.
Two distribution companies quantified losses from PRVs as part of UAF gas
studies.5-6 The results are shown in Table 5-12. The emission factor was determined based
on the ratio of natural gas released per mile of distribution main from the two companies.
Correcting for the methane composition in distribution (93.4 mol % ± 1.5%),9 the annual
emissions due to PRV releases are 0.050 ± 3,900% Mscf/mile of main.
35
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TABLE 5-12. DISTRIBUTION PRV EMISSIONS
TOTALS
ANNUAL
Company
1
2
PRV EF FOR
Annual
PRV Emissions,
Mscf
2,262
141
2,403
DISTRIBUTION, Mscf methane/mile
Main
Miles
31,730
13,248
44,978
main
Annual
PRV Natural Gas
Emission Factor,
Mscf/mile
0.071
0.011
0.050 ± 3,900%
As discussed in Section 3.2, dig-ins are pipeline ruptures caused by uninten-
tional third-party damage. Some distribution companies estimate and record the quantity of
gas lost during a dig-in event. From the annual records of four companies (Table 5-8), the
average methane emissions due to dig-ins is 1.59 ± 1,900% Mscf/mile of distribution
pipeline.
The high uncertainties of the distribution blowdown emission factors are the
result of the limited database (two to four sets of company data).
Pipeline blowdowns are a maintenance activity and may release methane to the
atmosphere as a result of pipeline abandonment, installation, or repair. The emission factor
for pipeline blcwdowns is based on data from four companies, shown in Table 5-13. The
emission factor was calculated from the ratio of the blowdown methane losses per mile of
distribution mains and services for the four sites. The estimated gas loss was adjusted for
93.4% methane, resulting in an annual emission factor of 0.102 ± 2,500% Mscf methane
per mile of distribution pipeline.
36
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TABLE 5-13. DISTRIBUTION PIPELINE SLOWDOWN EMISSIONS
Company
1
2
3
4
TOTALS
Annual Slowdown
Methane
Emissions, Mscf
8,972
5,688
2,360
1,695
18,715
Pipeline
Miles
58,024
82,337
24,916
18,713
183,990
Annual
Slowdown Methane
Emission Factor,
scf/milc
0.155
0.069
0.095
0.091
ANNUAL SLOWDOWN EF, Mscf methane/mile 0.102 ± 2,500%
37
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6.0 NATIONAL ANNUAL EMISSIONS
National annual emissions for each industry segment were calculated by
combining the emission factor and activity factor:
National Annual Emissions = Emission Factor x Activity Factor (2)
These results are summarized in Table 6-1 and presented in the following sections. The
activity factors for the production, transmission, gas processing, and distribution segments
are discussed biiefiy. (Details are provided in Volume 5 on activity factors.9)
6.1 Field Gas Production
The activity factors for equipment in the production segment were compiled
from site visit averages.9 The number of production vessels was assumed to be the sum of
separators, heaters, and dehydrators within the gas industry boundaries. The count of gas
wells requiring unloading was based on the number of all active gas wells observed at 22
sites corrected for the fraction of wells requiring unloading from these site (41.4% ± 45%,
from Table 5-1). Tbe count of PRVs hi production is based on an average number of
PRVs determined for each type of equipment: 2 PRVs/separator, 1 PRV/heater, 2 PRVs/d-
ehydrator, and 4 PRVs/compressoj. 9~" The count of platforms is from Offshore Data
Services and the Minerals Management System Outer Continental Databases.9-12
The final production blowdown emissions were determined by multiplying
cht omission factor (rate per average unit) for each category by the activity factor
(population) of the category. Emission factors for production were previously discussed in
S action 5.1. Table 6-1 and source sheets P-8, P-9, and P-10 in Appendix B summarize
these calculations. The results were added to give the annual national production emission
rates of 6.0 Bscf ± 359% for maintenance blowdowns and 0.53 Bscf ± 840% for emergency
releases.
38
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TABLE 6-1. BLOW AND PURGE EMISSION RESULTS
Iradtastry Segmeat
National Ateisal
Methane
Emission Rate,
Emission Factor
Activity Factor
Production:
Gas Wells Unloading
Compressor Slowdowns
Compressor Starts
Pipeline Miles
Production Vessels
Completion Flaring
Well Workovers
PRY Releases
BSD Releases
Dig-ins
Gas Processing
Transmission and Storage:
Stations
Pipeline Miles
Distribution:
PRV Releases
Dig-ins
Slowdowns
49,570 ± 344% scf/well
3,774 ± 147% scf/comp.
8,443 ± 157% scf/comp.
309 ± 32% scf/mile
78 ± 266% scf/vessel
733 ± 200% scf/cornpletion
2,454 ± 459% scf/workover
34 ± 252% scfy/PRV
256,888 ± 200% scf/platform
669 ± 1,925% scf/mile
4,060 ± 322% M&cf/plant
4,359 ± 322% Mscf/station
31.6 ±343% Mscf/mile
0.050 ± 3,914% Mscf/main mile
1.59 ± 1,922% Mscf/mile
0.102 ± 2.521 Mscf/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
726 ± 2% plants
2,175 ± 8% stations
284,500 + 5% miles
836,760 ± 5% miles main
1,297,569 ± 5% miles
1,297,569 ±5% 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%
2.95 ± 262%
9.48 ± 263%
9.00 ± 236%
0.04 ± 3,919%
2.06 ± 1,925%
0.13 ±2,524%
-------
6.2 Gas Transmission
The activity factors for the transmission segment • /ere compiled from
company data, site visit averages, and published statistics on the gas industry.9 The total
count for transmission compressor stations is 1,700; the total storage station count is 475.n
This results in 2,175 ± 8% compression facilities. The number of transmission pipeline
miles is reported in A.G.A. Gas Facts, Table 5-1, which shows 284,500 ± 5% miles of
pipeline in the United States for 1992.14 Multiplying the respective activity factors by the
station methane emission factor of 4,359 ± 262% Mscf/station and the pipeline emission
factor of 31.6 ± 236% Mscf/mile, results in the annual station emissions of 9.5 ± 263%
Bscf and the pipeline blowdov/n emissions of 9.0 ± 236% Bscf. Combining these produces
the national annual transmission emissions of 18.5 ± 177% Bscf.
6.3 Gas Processing
The number of gas processing plants, as reported in a 1992 edition of Oil and
Gas Journal, '5 is 726 ± 2%. (The confidence bound is assigned by engineering
judgement.9) The annual emissions were determined by multiplying the transmission station
blowdown emission factor by the number of gas plants. The resulting national annual
emissions for gas processing are 3.0 + 262% Bscf for 1992.
6.4 Distribution
The activity factor for distribution PRV releases is based on the total miles of
distribution main pipeline in the United States (836,760 ± 5%). Combining the activity
factor with the annual emission factor (0.050 ± 3,914% Mscf/main miles from Section 5.4)
yields the national annual methane emissions of 0.042 ± 3,919% Bscf.
The activity factor for distribution pipeline dig-ins and blowdowns is based
on the total miles . distribution pipeline in the United States (1,297,569 ± 5%).9 For
40
-------
pipeline dig-ins, multiplying the annual emission factor (1 59 ± 1,922% Mscf/mile from
Section 5.4) and activity factor results in the national annual methane emissions of 2.06 ±
1,925% Bscf for dig-ins. Likewise for pipeline blowdowns, the national annual methane
emissions of 0.13 ± 2,524% Bscf result from the product of the activity factor and annual
emission factor (0.102 ± 2,521% Mscf/mile from Section 5.4). The annual national
methane emissions for the distribution segment are then 2.2 ± 1,783% Bscf.
41
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7.0 REFERENCES
1. Ingersoll-Rand. Compressor Gas Starter Schematic, 1992.
2. Ingersoll-Rand. Starting System Schematic, 1992.
3. BS&B Safety Systems. "Union, Bolted, Quik-sert Safety Heads." Catalog
77-7001, Section E-5, Tulsa, OK, 1989.
4. Pipeline Systems Incorporated. Annual Methane Emission Estimate of the
Natural Gas Systems in the United States, Phase 2. For Radian Corporation,
September 1990.
5. Pacific Gas & Electric Company and Gas Research Institute. Unacrnunted-
For Gas Project. Volume 1, Final Report, San lamon, CA, June ', 1990.
6. Southern California Gas Company and Gas Research Institute. A Study of the
1991 Unaccounted-For Gas Volume at the Southern California Gas
Company, Final Report, Los Angeles, CA, April 1993.
7. Energy Information Administration. Annual Energy Review 1994, Table 4.5
"Oil and Gas Exploratory Wells, 1949-1994." EIA, Office of Oil and Gas,
U.S. Department of Energy, DOE/EIA-0384(94), Washington, DC, July 1995.
8. 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.
9. 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.
10. American Gas Association. Gas Facts, 1992 Data (Table 3-3), Arlington,
VA, 1993.
11. 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.
12. Offshore Data Services. David Sutherland. Phone contact with Radian
Corporation, Lafayette, LA, April 27, 1994.
13. Department of Energy. FERC Form No. 2: Annual Report of Major Natural
Gas Companies. OMB No. 1902-0028, Department of Energy, Federal
Energy Regulatory Commission, Washington DC, December 1994.
14. American Gas Association. Gas Facts, 1992 Data (Table 5-1), Arlington,
VA, 1993.
15. Bell, L. "Worldwide Gas Processing," Oil and Gas Journal, July 12, 1993,
p. 55.
42
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APPENDIX A
Unaccounted-For Gas Studies
A-l
-------
A.I PG&E UAF Study
The Pacific Gas & Electric (PG&E) unaccounted-for (UAF) gas study1
estimated blow and purge gas for the entire PG&E transmission and distribution system. The
study estimated the 1987 blow and purge (blowdown) gas for PG&E's system to be 310
MMcf. This accounts for 2.3% of the 13,259 MMcf of UAF gas estimated in the PG&E
report for 1987 and 0.04% of the total 857,346,771 Mcf PG&E gas receipts for 1987.
In the PG&E study, UAF is defined as the difference between total gas
receipts (input) and total gas deliveries (output). Because of PG&E's accounting procedures,
even though a quantity of purge gas may be well documented and reported, it may still be
classified as "unaccounted-for" because it was not reported to accounting as having been
"delivered" to anyone. Therefore all of PG&E's blow and purge quantities were classified as
UAF, and were estimated by the UAF study. PG&E attempted to systematically account for
blowdown gas emitted from their system using pipeline records, documentation of blow and
purge occurrences (for instance with their standard form "Report of Gas Blown to At-
mosphere"), and from interviews with engineers and operators. Blowdown sources of UAF
gas included in the report are listed in Table A-l. These sources are discussed briefly
below.
Boiler Purge
Boiler purge UAF gas was estimated using the dimensions of the purged
piping and the frequency of purges. Pipe dimensions were measured manually and the
frequency of purges was obtained from accounting records.
Pipeline Blow and Purge
Purge gas for pipelines taken out of service was estimated by calculating the
internal volume of ;he pipeline, estimating a working pressure, and using the Ideal Gas
A-2
-------
TABLE A-l. PG&E SLOWDOWN SOURCES
Type Blow/Purge
Boiler purge
Pipeline blow and purge
Drip Operations
Compressor blow and purge (including
start-ups)
Dehydrator blow and purge
Meter and regulator replacement and insp-
ection
Odorizer blow and purge
TOTAL
1987 Amount
(Met)
57
198,000
2,600
107,000
544
1,300
196
310,000
% of 1987
Blow/Purge
0.0
63.9
0.9
34.5
0.2
0.4
0.1
100
% of 1987
Receipts
0.0000
0.0231
0.0003
0.0125
0.0001
0.0002
0.0000
0.0362
Law. Volume measurements were obtained from 1987 pipeline statistics. Transmission
and gathering pipe are not mentioned in this section of the report.
Estimates for purge gas from new pipelines put into service were broken into
two categories by pipe diameter and therefore, purge method. When purging small
diameter pipes, PG&E used a method which allows more natural gas to escape than the
purge method for larger diameter pipes. However, interviews with pipeline engineers/
operators indicated that UAF resulting from either purge method was very small. UAF gas
from pipes with small diameters was estimated by assuming an orifice size for the purge
valve, assuming a pressure in the pipeline, and assuming the valve was left open for 20
seconds with 100% natural gas being purged. UAF gas emissions from the newly installed
pipelines with larger diameters were not calculated.
Estimates of purge gas resulting from pireline repair were also broken into
two categories. If the repair was done on a distribution and service pipe, a worst case
length was assumed. If the repair was done on transmission and gathering pipelines, the
amount of purge gas was estimated and reported at the time of repair. Other types of blow
A-3
-------
and purge due to pipeline repair were not included in the report because interviews with
engineers/operators indicated the amount to be insignificant.
For transmission and gathering pipe, estimates of blow and purge due to
emergency shutdowns were reported at the time of shutdown and were included in the
estimate for pipeline repair. For distribution and service pipe, emergency shutdowns were
too infrequent and the volumes too small to warrant UAF gas estimation.
Drip Operations
Drip points along the pipeline are periodically opened to clear the line of
condensation. PG&E operators were interviewed to determine a typical blow operation and
its frequency. UAF gas due to drip operations was then estimated.
Compressor Blow and Purge (including start-ups)
Compressor blow and purge occurs when a compressor is brought down for
emergency or maintenance reasons. In addition, most compressors require compressed gas
to bring them up to starting speed. For compressor purge and blow estimations, piping
sizes were obtained from engineering drawings and blow and purge frequencies were
obtained from records. Purge volumes were estimated by compressor engineers to be about
2% of the associated pipe volume at operating pressure. The volume of gas needed to start
a turbine compressor was measured, prior to 1980, to be about 35 Mcf per start-up attempt
and each turbine requires about 4 attempts to start. Assuming the turbines required the
same amount of gas to start in 1987 as prior to 1980, PG&E estimated a final blow volume
from this source. Reciprocating compressors were not mentioned in the PG&E report.1
A-4
-------
Dchydrator Blow and Purge
In estimating blowdown gas from dehydrators, PG&E obtained dehydrator
volumes, operating pressures, and the frequency of gas vents to the atmosphere. No
estimate was made of purge gas because of the infrequency of shutdowns (about once every
two years) and the low volume of purge needed. Additionally, seven of PG&E's 37
dehydrators were not included in the estimate because they service underground storage,
which was beyond the scope of their report.
Meter and Regulator Replacement and Inspection
To arrive at an estimate for blow and purge from gas meters, PG&E
interviewed operators for estimates of the lengths of purge and the flow rates used during
installations and maintenance. They then obtained the total number of operations from
company records, and calculated a final estimate. Many of the steps involved in installing a
gas meter or connecting a new customer require releasing gas to the atmosphere while
metering the flow. These volumes are typically charged to the customer and, therefore, are
not considered UAF gas.
Odorizer Blow and Purge
PG&E obtained estimates from operators of how much gas is purged from
odorizers each year. The estimated volumes were so low that they decided not to inves-
tigate this source of UAF gas any further.
Sources Not Included In Study
Several L)AF gas sources were not included in the study because they were
beyond the scope of work or deemed insignificant. These sources and the reasons for not
including them in the study are listed in Table A-2,
A-5
-------
TABLE A~2, SOURCES NOT INCLUDED IN UAF
UAF Source Reason for Non-inclusion
Start-up purge of pipes over 8 inches in diameter The method of purge yields little UAF gas
Blow and purge due to maintenance, repair, and Operator estimate determined amount to be insig-
hydrostatic testing of pipelines nificant
Emergency shutdown blow of distribution and ser- Volume of pipe was small and frequency of emer-
vice pipe gency shutdown was low
All purge gas from all dehydrators Volume was small and shutdown infrequent (blow
gas was included)
All blow gas from three compressor stations and Beyond the scope of the report
seven dehydrators at underground storage fields
All blow gas from orifice meters with senior fittings Volume was insignificant (orifice meters with junior
fittings were included)
All blow and purge from meters and regulators on Outside of PO&E system, except downstream of
California producer wells and PG&E purchase me- PO&E purchase meters, which was a small volume
ters
Conclusions
There are some differences in definitions, comprehensiveness, and accuracy
between the results of the PG&E study and the needs of the GRI/EPA methane emissions
project. PG&E includes turbine compressor starts in the blow and purge category, while the
GRI/EPA study separates starts from blowdowns. PG&E's report seems to be comprehen-
sive with one notable exception. They fail to account for blowdowns from reciprocating
compressors, which could be a significant source of UAF gas. Other omissions are
relatively low-volume sources. The accuracy of the estimates hi the study can be broken into
two qualitative categories, those which were done using anecdotal evidence (such as operator
guesses) and those which were done using measurements or easily estimated volumes,
pressures, and times. Table A-3 breaks the estimates into these categories.
A-6
-------
TABLE A-3. PG&E UAF ESTIMATE METHODS
Type Blow/Purge
Estimate
Boiler
Retired Pipeline
New Pipeline
Repaired Pipe
Drip Operations
Comp. B&P
Comp. Starts
Dehydrator
Meter and
Regulator
Odorizer
Accounted- Non-rigorous
for Gas UAF Gas
Measured Estimate
X
X
X
X X
X
Rigorous
UAF Gas
Estimate
X
X
X
X
X
Volume
Estimates
214 Mcf
9392 Mcf
20 Mcf
73,797 Mcf
32,890 Mcf
UAF volume
not reported
A-7
-------
A.2
SoCal UAF Study
The SoCal UAF gas study2 was modeled after the 1987 PG&E UAF study,
but it was conducted on 1991 inventories. This study estimated total UAF gas for the
SoCal system of 9,516 MMcf in 1991, with 12,514 Mcf, or 0.13%, coming from blowdown
operations. The blowdown UAF gas estimate accounts for 0.0012% of the 1,052 Bcf total
1991 receipts to the SoCal System. Specific operations included in the SoCal study are
listed in Table A-4. Each type of blow and purge emission source is discussed briefly.
TABLE A-4. SoCal UAF SUMMARY
Type Blow/Purge
Blow & purge of abandoned pipe
Purge from newly installed pipe
Turbine meter spin test blow
Calibration purge of meters > size 4
Hydrostatic test blowdown
Drip operations
TOTAL
1987 Amount
(Mcf)
827
5,180
100
2,669
2,498
1,0
12,514
% of Total
Blow/Purge
6.6
41.4
0.8
21.3
20.0
9.9
100
% of 1991
Receipts
0.000079
0.000492
0.000010
0.000254
0.000237
0.000118
0.001190
Blow and Purge of Abandoned Pipe
To estimate the UAF gas volume due to old pipe abandonment, SoCal obtained
pipe dimensions from records, assumed a pressure inside the pipe, and applied the Ideal Gas
Law.
Purge From Newly Installed Pipe
In estimating the UAF gas due to installation of new pipe, SoCal used the pipe
radial dimensions and length, the pressure inside the pipe, the duration that air/gas was
A-8
-------
purged, and the size of the purge orifice. The pipe radial dimensions were obtained from
company records and the pipe length and the duration of purge were obtained from Industrial
Engineering standards. Both the pressure in the pipe and the purge orifice were assumed.
With these assumptions and data, SoCal estimated the volume of gas purged to the at-
mosphere starting with a pipe full of air at atmospheric pressure, and ending with a pipe full
of natural gas at 40 psig.
Turbine Meter Spin Test Blow
For turbine meter test purges, SoCal identified 323 turbine meters and
segregated them into five pressure groups. They then assumed a turbine meter run from a
standard drawing and assumed each meter was inspected thiee times per year. The Ideal Gas
Law was used to calculate the final estimate of UAF gas due to turbine meter inspection.
Calibration Purge of Large Meters
In estimating the amount of purge gas due to calibrating diaphragm and rotary
meters, SoCal limited their investigations to size 4 meters and larger. The diaphragm and
rotary meter purges were calculated separately due to differing field test procedures.
Observations were made in the field to determine the length of purge per meter test. The
flow rates used during testing were taken from published company procedures. Often meters
require multiple tests to achieve calibration, so to calculate a purge estimate, SoCal assumed
four tests per calibration for diaphragm meters and three tests per calibration for rotary
meters.
Hydrostatic Test Slowdown
When SoCal performs hydrostatic pipe strength tests, they sometimes record
the amount of gas purged to the atmosphere in accounting records. In these cases, the purge
is not considered "unaccounted-for" and is not included in their UAF gas total (presumably it
A-9
-------
is accounted-for as delivered to themselves). To calculate the UAF gas for their report, they
obtained the lengths and diameters of all pipe tested from company records, assumed a
pressure, applied Boyle's Law to obtain a total volume, and subtracted the "accounted-for"
volume (284 Mcf in 1991) to obtain a final UAF volume.
Drip Operations
To estimate UAF purge from drip operations, several field operators were
interviewed to establish a typical drip procedure. Further, they estimated the number of drip
points, a drip point distribution according to pipeline pressure, and a drip point purge
frequency. Using these assumptions and the Pacific Coast Gas Association orifice equation,
they calculated a final UAF purge volume.
Sources Not Included
The SoCal report2 does not mention several sources of UAF gas which are
included in the PG&E report.1 Most of these were very small: boiler purge, dehydrator blow
and purge, and odorizer blow and purge. However, compressor blow and purge contributed
over one-third of the blowdown UAF reported in the PG&E study, but was not mentioned in
the SoCal study.
Conclusions
SoCal's UAF volume does not represent all of the blowdown gas that reached
the atmosphere. Due to accounting procedures, SoCal does not include gas blown to the
atmosphere from some hydrostatic strength hi their UAF estimates. The 284 Mcf of natural
gas from this source should be included in the present study to get a better picture of the
amount of methane lost from their system to the atmosphere.
A-10
-------
The SoCal report2 apparently does not take into account compressor start-up
gas or compressor shut-down blow and purge gas, as the PG&E study did. These were
substantial sources in the PG&E report1 and should be accounted for.
Most of SoCal's estimates were done in a reasonably rigorous manner, but for
comparison to the PG&E report, their estimates are broken-down by qualitative accuracy in
Table A-5.
TABLE A-5. SoCal UAF ESTIMATE METHODS
Type Blow/Purge AF Gas
Estimate Measured
Abandoned Pipe
New Pipeline
Turb. Meter Test
Large Meter Calib.
Hydostat. Tests X
Drip Operations
REFERENCES
1. Pacific Gas & Electric Cc
Non-rjgorousr Rigorous
UAF Gas UAF €as
Estimate Estimate
X
X
X
X
X
X
impany and Gas Research Institute.
Wnme
Estimates
UAF = 284 Mcf
, Unaccounted-
2.
For Gas Project. Volume 1, Final Report, San Ramon, CA, June 7, 1990.
Southern California Gas Company and Gas Research Institute. A Study of the
1991 Unaccounted-For Gas Volume at the Southern California Gas Company,
Final Report, Los Angeles, CA, April 1993.
A-ll
r A ¥ »*E"ru A Mir RIVAfCCiriMG- 1 at
-------
APPENDIX B
Source Sheets
B-l
-------
B.I Production
P-8
PRODUCTION SOURCE SHEET
SOURCES: Various Production Equipment
(wells, vessels, compressors, pipelines)
OPERATING MODE: Maintenance
EMISSION TYPE: Unsteady, Vented
ANNUAL EMISSIONS: 6.0 Bscf ± 359%
BACKGROUND:
Maintenance activities can emit gas to the atmosphere through blowdown or through purge. Slowdown is the
direct, intentional venting to the atmosphere of gas contained inside operating equipment. The gas is released
to provide a safer working snvironment for maintenance activities around or inside the equipment. After the
equipment is serviced, the oxygen inside the equipment is often cleared to the atmosphere by purging natural
gas through the equipment.
Another type of maintenance venting is associated with low pressure gas wells that sometimes accumulate
water in the wellbore due to their low flow rate. This water chokes the flow of the well, reducing gas
production. To clear the water, the well is blown to a tank at atmospheric pressure where the gas is vented.
EMISSION FACTORS: Gas Well Unloading 49,570 ± 344% scl/unloading gas well
Compressor Blowdown 3,774 ± 147% scl/eompressor
Compressor Stcrts 8,443 ± 157% scf/compressor
Pipeline Blowdown 309 ± 32% scf/inile
Vessel Blowdown 78 ± 266% scfi'vessel
(Emission factors were adjusted for the production methane fraction of
natural gas of 78.8 moi%)
Blowdown volumes and frequencies were averaged from calculations for each QRI/EPA site visit. The
volume times the frequency results in the annual emissions. The volumes were calculated at each site using
equations of state, observed vessel dimensions, and pre-blowdown pressures. Frequencies were gathered at
each site from operator interview. The annual emission factor (scfAinit) for each category was calculated as
follows:
EF = Volume x Frequency x % Me mane
where:
Volume = Gas released to the atmosphere during an event (scffevent/unit);
Frequency = Number of events annually;
% Methane = 78.8 mo! % ± 5% for the production segment.
More details are available in the Methane Emissions from the Natural Gas Industry, Volvme 7: Blow and
Purge Activities (1).
EF DATA SOURCES:
1. The blow and purge report establishes emission affecting characteristics of blow-
down practices.
2. Volume and frequency data were available from the following number of sites:
L. Gas Well Unloading (12 sites)
B-2
-------
Compressor Starts (12 sites)
Vessel BD (12 sites)
Pipeline BD (18 sites)
3. The; count of equipment at each site was gathered during the site visits by obser-
vation, record search, or interview.
EF PRECISION: ± 32% to 344%
Basis:
The accuracy was calculated from the variance of the site dat,. A 90% confidence interval
is calculated for the sites using the method outlined in the Methane Emissions from the
Natural las '- \istry, Volume 4: Statistical Methodology (2).
ACTIVITY FACTORS:
114,139 ± 45% gas wells requiring unloading
17,112 ± 52% compressors
340,000 ± 10% miles of pipeline
255,996 ± 26% produc»-ou vessels
The activity factors for equipment in the production segment were compiled from GRI/EPA site visit averages
as well as published statistics on the gas industry (see activity factor sections in previous sheets). The
number of production vessels was assumed to be the sum of separators, heaters, and dehydrators.
AF DATA SOURCES:
1. The well, compressor, and vessel counts came from the activity factor extrapolation
based on GRI/EPA site visits or surveys (previously discussed in the production
fugitives sheet). The count of "vessels" is from the addition of dehydrator, separat-
or, and in-line heater counts.
2. The miles of production gathering pipelines were determined fro- a site extrapolati-
on of seven sites and data from Gas Facts Table 5-3 (3). This e apolation was
previously discussed in the production gathering pipeline fugitive leaks sheet,
P-3.
3. The number of gas wells requiring unloading is based on the ratio of gas wells
requiring unloading to all active gas wells from 25 GRI/EPA sites (41.4% ± 162%).
AF PRECISION: Range ± 10% to 52%
Bask:
The accuracy for all equipment types is based on error propagation from the spread of
available production site data.
ANNUAL METHANE EMISSIONS: 6.0 Bscf ± 359%
The annual methane emissions were determined by multiplying an emission factor (rate per average unit) for
each category by the activity factor (population) of the category.
REFERENCES
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-60U/R-96-080g, Gas
Research Institute and U.S. Environmental Protection Agency, June 1996.
B-3
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Williamson, H.J., M.B. Hall, and MR. Harrison. Methane Emissions from the Natural Gas
Industry, Volume 4: Statistical Methodology, Final Report, GRI-94/0257.21 and EPA-600/R-
96-080d, Gas Research Institute and U.S. Environmental Protection Agency, June 1996.
American Gas Association. Gas Facts, 1992 Data (Table 5-3), Arlington, VA, 1993.
B-4
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P-9
PRODUCTION SOURCE SHEET
SOURCES: Various Production Equipment (vessels)
OPERATING MODE: Upsets
EMISSION TYPE: Unsteady, Vented
ANNUAL EMISSIONS: 0.3 Bscf ± 190%
BACKGROUND:
Upsets in process conditions can cause pressure rises that exceed the maximum design pressure for
equipment. To prevent equipment overpressure and damage, pressure relief valves (PRVs) open and vent the
excess gas to the atmosphere. These PRVs are spring loaded or pilot actuated valves that are designed to
handle the upset conditions. A few offshore production facilities (but no onshore facilities) have Emergency
Shutdown Systems (ESDs) that depressure the entire facility to a vent or a flare.
EMISSION FACTORS: PRV Discharge Blowdown 34 ± 252% sc»PRV
ESD Blowdown 257 ± 200% Mscf/platform
(Corrected for the production methane composition of 78.8 mol%)
Emergency blowdown volumes and frequencies were estimated at each site visited. The average volume of
gas released at lift pressure was calculated for a typical PRV size and duration, and corrected for the fraction
of PRVs that release gas to the atmosphere. ESD blowdown volumes were based on the platfonn volume and
corrected for the fraction of platforms with ESDs and the fraction that vent gas to the atmosphere. The
annual emission factor (scffunit) for each category was calculated as follows:
EF = Volume x Frequency x % Methane
where:
Volume = Gas released to the atmosphere during an event (scf/event/unit);
Frequency = Number of events per year;
% Methane = 78.8 mol % ± 5% for the production segment.
EF DATA SOURCES:
1. The GRI/EPA Methane Emissions from the Natural Gas Industry, Volume 7: Blow
and Purge Activities (1) establishes emission affecting characteristics of blowdown
practices.
2. Volumes (duration, release rate, % to atmosphere) and frequencies were calculated
from each site visit based on data collection, observation, and interview. Data were
available from the following number of sites:
PRV discharge (11 sites)
ESD activation (5 platforms)
3. The count of equipment at each site was gathered during the site visits by obser-
vation, record search, or interview.
EF PRECISION:
Basis:
The accuracy was propagated from the spread of the site data. A 90% confidence interval is
calculated using the method presented in the Methane Emissions from the Natural Gas
Industry, Volume 4: Statistical Methodology (2).
B-5
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ACTIVITY FACTORS: 539,440 ± 53% Production PRVs
1,115 ± 10% Platforms
The activity factors for equipment types in the segment were compiled from ORI/EPA site visit data as well
as published statistics on the gas industry.
AF DATA SOURCES:
1. The count of platforms is from Offshore Data Services and the Minerals
Management System Outer Continental Activity Database as reported in Methane
Emissions from the Natural Gas Industry, Volume 5: Activity Factors (3).
2. The number of production PRVs is based on counts of PRVs per equipment type
from site visit data:
Equipment
Type
Separators
Heaters
Dehydrators
Compressors
PRV
Count
2 ± 68%
1 ± 89%
2 ± 53%
4 ± 84%
Number
of Sites
20
11
10
13
Details are provided in the Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks
report (4).
AF PRECISION: Pange ± 10% to 53%
Basis:
1. Confidence intervals for the platform count were assumed and assigned based upon
an excellent recorded source of data [see Methane Emissions from the Natural Gas
Industry, Volume 5: Activity Factors (3)].
2. Ninety percent confidence limits for production vessels with PRVs were calculated
from the confidence intervals of each type of equipment. See Methane Emissions
from the Natural Gas Industry, Volume 5: Activity Factors (3) for details of
equipment count determination.
ANNUAL METHANE EMISSIONS: 0.30 Bscf ± 190%
The annual methane emissions were determined by multiplying an emission factor (rate per avg unit) by the
activity factor (population) of the category. Each emission factor was adjusted for the average methane
content in the production segment of 78.8 mol%.
REFERENCES
1. 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-600/R-96-080g, Gas
Research Institute and U.S. Environmental Protection Agency, June 1996.
2. Williamson, H.J., M.B. Hall, and M.R. Harrison. Methane Emissions from the Natural Gas
Industry, Volume 4: Statistical Methodology, Final Report, GRI-94/0257.21 and EPA-600/R-
96-OSOd, Gas Research Institute and U.S. Environmental Protection Agency, June 1996.
B-6
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3. 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.
4. 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.
B-7
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P-10
PRODUCTION SOURCE SHEET
SOURCES: Pipeline
OPERATING MODE: Mishaps (Dig-ins)
EMISSION TYPE: Unsteady, Fugitive
ANNUAL EMISSIONS: 0.2 Bscf ± 1,934%
BACKGROUND:
Dig-ins are gathering pipeline raptures caused by unintentional (sometimes third-party) damage. Production
companies do NOT estimate and record the quantity of gas lost during a dig-in event; therefore, distribution
data has been used.
EMISSION FACTOR: 669 ± 1,925% scf/mile
(Corrected for the production methane composition of 78.8 mol%)
The emission factor was derived from four distribution company estimates of the losses from dig-ins: the
Pacific Gas and Electric unaccounted-for (UAF) gas study (1) results showed that losses from dig-ins were
estimated at 91,178 Mscf for 58,024 miles of distribution mains and services; the Southern California Gas
Company estimate (2) of losses from dig-ins was 170,457 Mscf for £2,337 miles of distribution mains and
services; a third company estimate of losses from dig-ins was 19,581 Mscf for 24,916 miles of distribution
mains and services; and a fourth company reported dig-in losses of 10,453 Mscf for 18,713 miles of
distribution mains. The ratio of the total dig-in emissions to the total pipeline miles from these companies
was used to estimate the annual national methane emission factor, resulting in 2.06 Mscf/mile.
This value was halved (and adjusted for the different methane compositions of the two industry segments)
based upon an engineering assumption that production dig-ins occur much less frequently than distribution
dig-ins, and so account for approximately one-half of the distribution emission rate per mile. This is
supported by the fact that most production sites are remotely located, while distribution sites are by definition
located in population centers where third-party dig-ins are more likely.
ACTIVITY FACTOR: 340,000 ± 10% miles of production gathering pipeline
The annual number of miles of gathering pipeline in the U.S. gas industry was derived from site data. See P-
3 and Methane Emissions from the Natural Gas Industry, Volume 5: Activity Factors (3) for more details.
ANNUAL METHANP EMISSIONS: 0.23 Bscf ± 1,934%
REFERENCES
1. Pacific Gas & Electric Company and Gas Research Institute. Unaccounted-For Gas Project.
Volume 1, Final Report, San Ramon, CA, June 1990.
2. Southern California Gas Company and Gas Research Institute. A Study of the 1991
Unaccounted-For Gas Volume at the Southern California Gas Company, Final Report, Los
Angeles, CA, April 1993.
3. Stapper> B.E. Methane Emissions from the Natural Gas Industry, Volume 5: Activity
Factors, Final Report, BPA-600/R-96-080e, Gas Research Institute and U.S. Environmental
Protection Agency, June 1996.
B-8
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p-11
PRODUCTION SOURCE SHEET
SOURCES: Gas Wells
OPERATING MODE: Maintenance
EMISSION TYPE: Venting and Flaring
ANNUAL EMISSIONS: 0.02 Bscf ± 1,263%
BACKGROUND:
Two minor sources of maintenance releases are completion flaring and well workover. Completion flaring
occurs at a new well's open ended pipe flare immediately following the drilling process. During completion
testing, the gas is flared to determine the available pressure and flow rates at the surface. This allows proper
sizing of meters and surface equipment. Most completion flaring occurs at exploratory wells, since the
production rates and needed facilities for in-fill wells (also called development wells) are often available or
can be determined before the well is completed.
Well workovers are another type of maintenance venting. During a well workover, the tubing is pulled from
the well to repair tubing corrosion/erosion or other downhole equipment problems. The well is "killed" by
replacing the gas in the column with water or mud, thus stopping all production flow. The well can then be
opened to the atmosphere.
EMISSION FACTORS: Completion Flaring 733 ± 200% set/completion well
Well Workovers 2,454 ± 459% sef/well workover
(Emission factors were adjusted for the production methane fraction of natural gas of 78.8 mol%.)
The flow rate of gas at completion is the highest that the well will produce. For emission estimate purposes,
the maximum gas flow rate was not availab's. Instead, the completion flaring emission factor was calculated
based on the average annual natural gas production per well and an assumed flaring efficiency as shown:
EFouBpiMioj fl^g = Average Annual Volume x Duration x % Methane x Flaring Efficiency
where:
Average Annual Volume = 16.97 MMscf for natural gas
Duration = Flaring duration is one day/completion well
% Methane = 78.8 mol% for production
Flaring Efficiency = 98% efficient (2% methane not burned)
This results in an emission factor of 733 ± 200% scf/completion well for completion flaring.
The emission factor for well workovc's was determined from two gas production fields. Data from these
fields are shown in the following table:
Site 1 Site 2
Total number of wells 21 400
Number of workovers/year 1 8
Methane emissions/workover, scf/workover 670 4,238
Average scf methane/workover 2,454 ± 459%
B-9
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EF DATA SOURCES:
1. One operator provided data on the typical duration of completion flaring and which
types of completions were flared. Average is one day/exploratory completion well.
2. Average gas production per well from Gas Facts (1).
3. Multiple reports on methane flare combustion efficiency support 98% combustion.
4. Pipeline Systems Incorporated (PSI) reported gas well workover emissions from two
sites (2).
EF PRECISION: ± 200% to 459%
1. Engineering judgement was used to establish the upper confidence limit for the
completion flaring emission factor.
2. Confidence bound for well workover emission factor is based on the average of data
from two sites.
ANNUAL ACTIVITY FACTORS:
844 ± 10% completed gas wells
9,329 ± 258% well workovers
AF DATA SOURCES:
1. Number of exploratory wells completed per year based on data from the Energy
Information Administration (EIA) Drilling and Production under Title 1 of the
Natural Gas Policy Act (3). This data excludes Alaska.
2. PSI data showed 1 workover/yr per 21 wells at Site 1 and 1 workover/yr per 50
wells at Site 2.
3. The Activity Factors Report (4) provides details on the total number of gas
producing wells (276,014 ± 5%).
AF PRECISION: Range + 10% to 258%
1. 10% upper confidence bound for completion wells is assigned based on good
precision from national statistics of 1987 data.
2. Well workover confidence interval is based on the average of data from two sites
combined with the confidence bound for the total number of gas producing wells.
ANNUAL METHANE EMISSIONS: Completion Wells: 619 ± 201% Mscf
Well Workovers: 22.9 ± 1296% MMscf
The annual methane emissions were determined by multiplying an emission factor (methane emissions per
event) for each category by the activity factor (events/year) of the category.
REFERENCES
1. American Gas Association. Gas Facts: 1992 Data (Table 3-3), Arlington, VA, 1993.
2. Pipeline Systems Incorporated. Annual Methane Emission Estimate of the Natural Gas
Systems in the United States, Phase 2. For Radian Corporation, September 1990.
3. Energy Information Administration. Annual Energy Review 1994, Table 4.5 "Oil and Gas
Exploratory Wells, 1949-1994." EIA, Office of Oil and Gas, U.S. Department of Energy,
DOE/EIA-0384(94), Washington, DC, July 1995.
B-10
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Stapper, B.E. Methane Emissions from the Natural Gas Industry, Volume 5: Activity
Factors, Fina) Report, GRJ-94/0257.22 and EPA-600/R-96-080e, Gas Research Institute and
U.S. Environmental Protection Agency, June 1996.
B-ll
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B.2 Gas Processing
GP-4
PROCESSING SOURCE SHEET
SOURCES: All Equipment (vessels, compressors, pig traps, manifolds)
OPERATING MODE: Maintenance
EMISSION TYPE: Unsteady, Vented
ANNUAL EMISSIONS: 3.0 Bscf ± 262%
BACKGROUND:
Slowdown is the direct, intentional venting to the atmosphere of gas contained inside operating equipment.
The gas is released to provide a safer working environment for maintenance activities around or inside the
equipment.
EMISSION FACTORS: 4,060 ± 262% Mscf/gas plant
(Corrected for the gas processing methane composition of 87 mol%)
Slowdowns at gas plants consist primarily of the following types of events: compressor blowdown,
compressor starts, pipeline pig receiver blowdown, and miscellaneous vessel blowdow^. Due to the
similarities hi station blowdown practices between the gas processing and transmission segments, transmission
station company tracked data were applied to gas plants. Blowdown volumes per station were provided based
on company tracked data from 9 transmission companies.
EF DATA SOURCES:
1. The Methane Emissions from the Natural Gas Industry, Volume 7: Blow and Purge
Activities (1) establishes emission affecting characteristics of blowdown practices.
2. Company tracked data were provided from 9 transmission companies representing a
total of 328 stations.
EF ACCURACY: ±262%
Basis:
The accuracy was calculated from the spread of the company tracked data. A 90% con-
fidence interval is calculated for the data using the method presented in Methane Emissions
from the Natural Gas Industry, Volume 4: Statistical Methodology (2).
ACTIVITY FACTOR 726 ± 2% gas plants
AF DATA SOURCES:
1. The number of gas processing plants for 1992 is reported in the Oil and Gas
Journal (3).
AF ACCURACY:
Basis:
An accurate count of gas plants by the Oil and Gas Journal is very likely since counting
such large, discrete facilities should be straightforward. The ± 2% was assigned by
engineering judgement.
B-12
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ANNUAL METHANE EMISSIONS: 2.95 ± 262 Bscf
The annual methane emissions were determined by multiplying an emission factor by the activity factor
(population). Each emission factor was adjusted for the average methane content in the gas processing
segment of 87 mol%.
REFERENCES
1. 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-600/R-96-080g, Gas
Research Institute and U.S. Environmental Protection Agency, June 1996.
2. Williamson, H.J., M.B. Hall, and M.R. Harrison. Methane Emissions from the Natural Gas
Industry, Volume 4: Statistical Methodology, Final Report, GRI-94/0257.21 and EPA-600/R-
96-080d, Gas Research Institute and U.S. Environmental Protection Agency, June 1996.
3. Bell, L. "Worldwide Gas Processing," Oil and Gas Journal, July 12, 1993, p. 55.
B-13
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B.3 Transmission and Storage
T-5
TRANSMISSION AND STORAGE SOURCE SHEET
SOURCES: Various Equipment
OPERATING MODE: Maintenance/Upsets
EMISSION TYPE: Unsteady, Vented
ANNUAL EMISSIONS: 18.5 Bscf ± 177%
BACKGROUND:
Maintenance activities can release gas to the atmosphere through blowdown or through purge, Slowdown is
the direct, intentional venting to the atmosphere of gas contained inside operating equipnent. The gas is
released to provide a safer working environment for maintenance activities around or inside the equipment.
After the equipment is serviced, the oxygen inside the equipment is often cleared to the atmosphere by
purging natural gas through the equipment.
Upsets can also emit gas directly to the atmosphere. Upsets in process conditions can cause pressure rises
that exceed the maximum design pressure for equipment. To prevent equipment overpressure and damage,
pressure relief valves (PRVs) or remotely actuated valves open and vent the excess gas to the atmosphere.
PRVs are spring loaded or pilot actuated valves that are designed to handle the upset conditions. Remotely
actuated valves are usually designed to vent entire compressor stations or areas (such as compressor piping) in
the event of a station emergency such as a fire or a large gas release.
EMISSION FACTORS: Station Slowdowns 4,359 ± 262% Msctfstation
Pipeline Slowdowns 31.6 + 236% Msc£/mile
(Corrected for the transmission methane composit on of 93.4 mol%)
Company tracked data were available from either company gas use estimates reported to accounting
departments from each site (accounted-for), or from special "unaccounted-for" studies that searched for
unmetered company gas use. Most of the company data could be separated into two event types: station
blowdowns (includes compressor blowdowns, compressor starts, PRV lifts, BSD activation, and other verting
sources) and pipeline blowdowns. These data are summarized in the following table.
EF DATA SOURCES:
1. GRI/EPA Methane Emissions from the Natural Gas Industry, Volume 7: Blow and
Purge Activities (1) establishes emission affecting characteristics of blowdown
practices.
2. Company tracked data were available from 8 companies.
EF ACCURACY: Range ± 236% tc 262%
Basis:
The accuracy was calculated from the spread of the company data. A 90% confidence
interval is calculated for the 8 companies using the method presented in the Methane
Emissions from the Natural Gas Industry, Volume 4: Statistical Methodology (2).
B-14
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Annual Station Annual
Slowdown Pipeline Total Annual Total
Emissions, Slowdowns, Slowdowns-, Nuwber of
Company
1
2
3
4
5
6
7
8
TOTALS
ANNUAL AVERAGE,
ANNUAL AVERAGE,
Mscf Mscf
120,757 189,044
272,589 11,358
33,731 138,988
..
325,418 Unknown
Unknown 161,628
60,956 750,000
194,541 315,058
1,007,992 1,566,076
Mscf natural gas/station
Mscf natural gas/mile
Mscf Stations
309,801
283,,94"'
172,719
172,776
Unknown
Unknown
810,956
509,599
\\
15
27
(\?T
47
(48)
69
47
216
Total Number
of
Pipeline Miles
3,857
4,000
5,886
(5,450)
(4,725)
7,896
14,666
9,915
46,220
4,667 ± 262%
33.9 ± 236%
'Parentheses indicate that the value was not included in the total because a station or pipeline emission rate
was not available.
ACTIVITY FACTORS:
2,175 ± 8% compression facilities
284,500 ± 5% transmission pipeline miles
The activity factors for the segment were compiled from published statistics on the gas industry. The total
count for transmission compressor stations was 1700; the total underground and liquefied natui-al gas storage
Station count was 475. The number of transmission pipeline miles comes from A.G.A. Gas Facts (3) which
shows 284,500 miles of pipeline in the United States for 1992.
AF DATA SOURCES:
1.
2.
3.
4.
The number of transmission compressor stations was compiled from FERC Form
No. 2: Annual Report of Major Natural Gas Companies (4).
The number of underground storage facilities is taken directly from A.G.A. Gas
Facts, Table 4-5, "Number of Pools, Wells, Compressor Stations, and Horsepower in
Underground Storage Fields" (3).
The number of liquefied natural gas storage facilities was summed from A.G.A. Gas
Facts, Table 4-3, "Liquefied Natural Gas Storage Operations in the U.S. as of
December 31, 1987" (3). The table lists 54 complete plants, 32 satellite plants, and 3
import terminals for a total of 89 facilities.
The number of transmission pipeline miles comes from A.G.A. Gas Facts which
shows 284,500 miles of pipeline in the U.S. for 1992 (3).
AF ACCURACY: Range ± 5% to 8%
Basis:
Extremely tight confidence limits are expected due to the well documented and reviewed
DOE numbers published in A.G.A. Gas Facts (3).
B-15
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ANNUAL METHANE EMISSIONS: 18.5 Bscf ± 177%
The annual methane emissions were determined by multiplying an emission factor (rate per avg unit) for each
category by the activity factor (population) of the category. Each emission factor was adjusted for the
average methane content in the transmission segment of 93.4 mol%.
REFERENCES
1. Shires, T.M. and M.R. Harrison. Methane Emissions from the Natural Gas Industry, Volume
7: Blow and Purge Activities, Final Report, QRI-94/0257.24 and EPA-600/R-96-080g, Gas
Research Institute and U.S. Environmental Protection Agency, June 1996.
2. Williamson, H.J., M.B. Hall, and M.R. Harrison. Methane Emissions from the Natural Gas
Industry, Volume 4: Statistical Methodology, Final Report, GRI-94/0:z57.21 and EPA-600/R-
96-080d, Gas Research Institute and U.S. Environmental Protection Agency, June 1996.
3. American Gas Association. Gas Facts: 1992 Data, Arlington, VA, 1993.
4. Department of Energy, FERC Form No. 2: Annual Report of Mayor Natural Gas
Companies. OMB No. 1902-0028, Department of Energy, Federal Energy Regulatory
Commission, Washington, DC, December 1994.
B-16
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B.4 Distribution
D-3
DISTRIBUTION SEGMENT SOURCE SHEET
SOURCES: Pressure Relief Valves
OPERATING MODE: Maintenance/Upsets
EMISSION TYPE: Unsteady, Vented
ANNUAL EMISSIONS: 0.04 Bscf ±3,919%
BACKGROUND:
Pressure relief valves (PRVs) are often used in the distribution network to prevent the over-pressure of
distribution main pipelines. Typically, PRVs are used in conjunction with pressure regulators as a secondary
protection mechanism in the event of regulator failure. Gas is released during any emergency actuation of the
PRVs.
EMISSION FACTOR: 0.050 ± 3,914% Mscf/mile
(Adj-isted for the distribution methane fraction of natural gas of 93.4 mol%)
The estimated emission factor was based on two separate distribution company studies which quantified losses
from PRVs as part of unaccounted-for (UAF) gas studies. The studies calculated PRV releases per mile of
pipeline mains. The GRI/EPA emission factor was estimated as the ratio of emissions per mile of main from
the two companies, and corrected for the methane composition in distribution.
EF PRECISION: ± 3,914%
Basis:
The precision was calculated using the method outlined in the Statistics Report (I).
ACTIVITY FACTOR: 836,760 + 5% miles of main
The activity factor is based on the total miles of distribution main pipeline in the U.S.
AF PRECISION: ± 5%
Basis:
The accuracy was assigned based on engineering judgement.
ANNUAL METHANE EMISSIONS: 0.042 ± 3,919% Bscf
The annual methane emissions were determined by multiplying an emission factor (annual methane emissions
per mile of main) by the activity factor (miles of distribution main pipeline nationally).
REFERENCES
1. Williamson, H.J., M.B. Hall, and M.R. Harrison. Methane Emissions from the Natural Gas
Industry, Volume 4: Statistical Methodology, Final Report, GRI-94-0257.21 and EPA-600/R-
96-080d, Gas Research Institute and U.S. Environmental Protection Agency, June 1996.
B-17
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D-4
DISTRIBUTION SEGMENT SOURCE SHEET
SOURCES: Pipeline
OPERATING MODE: Mishaps (Dig-ins)
EMISSION TYPE: Unsteady, Fugitive
ANNUAL EMISSIONS: 2.1 Bscf ± 1,925%
BACKGROUND:
Dig-ins are distribution main or service pipeline ruptures caused by unintentional third-party damage. Some
distribution companies estimate and record the quantity of gas lost during a dig-in event; therefore, they keep
records of estimated annual losses due to dig-ins. From these annual records, a national emission rate for dig-
ins was determined.
EMISSION FACTOR: 1.59 ± 1,92?% Mscfmile
(Adjusted for the disti ibution methane fra-tion of natural gas of 93.4 nso!%)
The emission factor was derived from four distribution company estimates of the losses from dig-ins: the
Pacific Gas and Electric unaccounted-for (UAF) gas study (1) results showed that losses from dig-ins were
estimated at 91,178 Mscf for 58,024 miles of distribution mains and services; the Southern California Gas
Company estimate (2) of losses from dig-ins was 170,457 Mscf for 82,337 miles of distribution mains and
services; a third company estimate of losses from dig-ins was 19,581 Mjcf for 24,916 miles of distribution
mains and services; and a fourth company reported dig-in losses of 10,453 Mscf for 18,713 miles of
distribution mains. The ratio of the total dig-in emissions to the total pipeline miles from these companies was
used to estimate the national methane emission factor, resulting in 2.06 Mscfi'mile.
EF PRECISION: ± 1,922%
Basis:
The precision was calculated from the spread of the company data using the method presented
in the Methane Emissions from the Natural Gas Industry, Volume 4: Statistical Methodology
(3).
ACTIVITY FACTOR: 1,297,569 ± 5% miles of mains and services
The total number of miles of main pipeline in the U.S. gas industry was based on U.S. Department of
Transportation, Research and Special Projects Administration (4). The total miles of service pipeline was
reported in A.G. V's Gas Facts, 1990 (5).
AF PRECISION: ± 5%
Basis:
A 5% confidence bound was assigned on the basis of good precision from national statistics
of 1990 data.
ANNUAL IIETHANE EMISSIONS: 2.06 ± 1,925% Bscf
The annual methane emissions were determined by multiplying i. sion factor (annual methane emissions
per mile of pipeline) by the activity factor (number of mibs)
B-18
-------
REFERENCES
1. Pacific Gas & Electric Company and Gas Research Institute. Unaccoimied-For Gas Project,
Volume 1. Firm! Report, San Ramon, CA, June 7, 1990.
2. Southern California Gas Company and Gas Research Institute. A Study of the I9i '
Unacceunted-For Gas Volume at the Southern California Gas Company, Final Report, Los
Angeies, CA, April 1993.
3. Williamson, H.J., MB. Hall, and M.R. Harrison. Methane Emissions from the Natural Gas
Industry, Volume 4: Statistical Methodology, GR1-93/0257.21 and Final Report, EPA-600/R-
96-080d, Gas Research Institute and U.S. Environmental Protection Agency, June 1996.
4. U.S. Department of Transportation, Research and Special Projects Administration,
Washington, DC, 1991.
5. American Gas Association. Gas Facts, 1992 Data, Arlington, VA, 1993.
B-19
-------
SOURCES:
OPERATING MODE:
EMISSION TYPE:
ANNUAL EMISSIONS:
D-6
DISTRIBUTION SEGMENT SOURCE SHEET
Pipeline
Maintenance
Unsteady, Vented
0.13 Bscf± 2,524%
BACKGROUND:
Gas is blown to the atmosphere as a result of pipeline abandonment, installation, and repair.
EMISSION FACTOR: 0.102 ± 2,521 Mscffmile
^Adjusted for the distribution methane fraction of natural gas of 93.4 mol%)
The emission factors for pipeline blowdown are based on estimates from four companies: the Pacific Gas &
Electric Unaccounted-for Gas (UAF) Project, 1987 (1); the Southern California Gas Company (SoCal) project
(2); and two additional company estimates. The estimated total gas losses were adjusted for 93.4 volume
percent methane. The annual methane emissions per mile of mains and services for each of the four
companies was calculated based on the ratio of emissions to miles of distribution mains and services. The
following table summarizes the individual company estimates and the national emission factor. The precision
of the estimate is based on the 90 percent ->nfidence level for the four companies providing data.
Coiapany
1
2
3
4
Annual
Slowdown
Methane
Emissions, Mcsf
8,972
5,688
2,360
1,695
Pipeline
Miies
58,024
82,337
24,916
18,713
Annual
Blowdown Methane
Emission Factor,
scfmile
0.155
0.069
0.095
0.091
TOTALS
18,715
183,990
ANNUAL BLOWDOWN EF, Mscf methane/mile
0.102 ±2,521%
ACTIVITY FACTOR: (1,297,569 ± 5% miles mains and services)
The total number of miles main pipeline in the U.S. gas industry was based on U.S. Department of
Transportation, Research mid Special Projects Administration (3). The total miles of service was reported in
Gas Facts (4). The precision, or 90 percent confidence level, was estimated to be ± 5%, based on
engineering judgement.
ANNUAL METHANE EMISSIONS: 0.13 ± 2,524% Bsef
The annual methane emissions were determined by multiplying an emission factor (annual methane emissions
per mile of pipeline) by the activity factor (number of miles).
B-20
-------
REFERENCES
1. Pacific Oas & Electric Company and Gas Research Institute. Unaccounted-For Gas Project.
Volume 1, Final Report, San Ramon, CA, June 7, 1990.
2. Southern California Gas Company and Gas Research Institute. A Study of the 1991
Unaccounted-For Gas Volume at the Southern California Gas Company, Final Report, Los
Angeles, CA, April 1993.
3. U.S. Department of Transportation, Research and Special Projects Administration,
Washington, DC, 1991.
4. American Gas Association. Gas Facts, 1992 Data, Arlington, VA, 1993.
B-21
-------
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