United States 

Environmental Protection 

Agency 

Research and 

Development 

METHANE EMISSIONS FROM THE 

NATURAL GAS INDUSTRY 

Volume 6: Vented and Combustion Source Summary 

Prepared for 

Energy Information Administration (U.S. DOE) 

Prepared by 

National Risk Management 

Research Laboratory 

Research Triangle Park, NC 27711 

GRI-941 0257.23 

EPA - 600/R-96 -0801 

June 1996 
FOREWORD 

tecting 

The U.S. Environmental Protection Agency is charged by Congress with proenvironmental 

the Nation's land. air. and water resources. Under a mandate of national 

ing to a compatible 

laws, the Agency strives to formulate and implement actions leadbalance between human activiti~s and the ability of natural 

systems to support and nurture life. To meet this mandate, EPA1

program 

s research 

blems 

is providing data and technical support for solving environmental protoday and building ~ science knowledge base necessary 

logical 

to manage our ecovent or 

resources wisely. understand how pollutants affect our health. and prereduce environmental risks in the future. 

The National Risk Management Research Laboratory 

investigation 

is the Agency's center for 

of technological and management approaches for reducing risks 

from threats to human health and the environment. The focus of the Laboratory's 

land, 

research 

water. 

program is on methods for the prevention and control of pollution to air. 

systems; 

and subsurface resources; protection of water quality in public water 

control of 

remediation of contaminated sites and groundwater; and prevention and 

development 

indoor air pollution. The goal of this research effort is to catalyze 

and implementation of innovative, cost-effective environmental 

technologies; develop scientific and engineering 

support 

information needed by EPA to 

regulatory and policy decisions; and provide technical.support 

mation 

and infortransfer to ensure effective implementation of environmental 

and 

regulations 

strategies. 

term 

This publication has been produced as part of the Laboratory's strategic longsearch 

research 

and Development 

plan. It is published and made available by EPA's Office of Rewith 

to assist the user community and to link researchers 

their clients. 

E. Timothy Oppelt. Director 

National Risk Management Research Laboratory 

EPA REVIEW NOTICE 

This report has been peer and administrativefy 

Protection 

reviewed by the U.S. Environmental 

commercial 

Agency, and approved for publication. Mention of trade names or 

products does not constitute endorsement or recommendation for use. 

Service, 

This document is available to the public through the National Technical lnfonnation 

Springfield, Virginia 22161. 
METHANE EMISSIONS FROM 

TIIE NATURAL GAS INDUSTRY, 

&f\ ;- 7'/jo;~_S7.23 

EPA-600 /R- 96-080f 

June 1996 

VOLUME 6: VENTED AND COMBUSTION SOURCE SUMMARY 

FINAL REPORT 

Prepared by: 

Theresa M. Shires 

Matthew R. Harrison 

Radian International LLC 

8501 N. Mopac Blvd. 

P.O. Box 201088 

Austin, TX 78720-1088 

DCN: 95-263-081-01 

For 

GRI Project Manager: Robert A. Lott 

GAS RESEARCH INSTITUTE 

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-DI-0031 

National Risk Management Research Laboratory 

Research Triangle Park, NC 27711 
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. Envirotunental Protection 

Agency (EPA). Neither EPA, GRI, members of GRI, nor any person acting on behalf of 

either: 

a. Makes any warranty or representation, express or implied, with respect to the 

accuracy, completeness, or usefulness of the information contained in this 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 

(QNQC) 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 EPNORD's QNQC policies. 

panel 

In all cases, data and results were reviewed by the 

of experts listed in Appendix D of Volume 2. 

u 
Title 

Contractor 

Principal 

Investigators 

Report Period 

Objective 

Technical 

Perspective 

Results 

RESEARCH SUMMARY 

Methane Emissions From Vented and Combusted 

Sources 

Final Report 

Radian International LLC 

GRI Contract Number 5091-251-2171 

EPA Contract Number 68-D1-0031 

Theresa M. Shires 

Matthew R. Harrison 

March 1991 -June 1996 

Final Report 

This report summarizes methane emissions from vented and combusted 

sources. Significant sources of vented and combusted emissions are 

discussed, as well as miscellaneous minor sources of emissions. In 

addition, docmnentation for the methane compositions used for each 

industry segment is provided. This report also discusses inconsistencies 

in reported vented and flared emissions reported by other sources. 

The increased use of natural gas has been suggested as a strategy for 

reducing the potential for global warming. During combustion, natural 

gas generates less carbon dioxide (CO;) per unit of energy produced than 

either coal or oil. On the basis of the amount of C02 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 C02 emissions. 

To investigate this, Gas Research Institute (GRI) and the U.S. 

Envirorunental Protection Agency's Office of Research and Development 

(EP A/ORD) cofunded a major study to quantify methane entissions from 

U.S. natural gas operatior.s for the 1992 base year. The results of this 

study can be used to construct global methane budgets and to determine 

the relative impact on global warming of natural gas versus coal and oil. 

Vented emissions account for approximately 94 Bscf of methane 

emissions annually. Compressor exhaust is the primary source of 

iii 
Technical 

Approach 

Project 

Implications 

emissions 

combustion emissions, contributing approximately 25 Bscf of methane 

annually. 

Based on data from the entire program, methane emissions 

gas operations 

:from natural 

are estimated 

year. 

to be 314 ± I 05 Bscf for the 1992 base 

overall 

This is about 1.4 ± 0.5% of gross natural gas production. The 

an incremental 

program also showed that the percentage of methan' entitted for 

increase in natural gas sales would be significantly lower 

than the baseline case. 

of 

The 

methane 

project reached its accuracy goal and provides an accurate estimate 

emissions that can be used to conduct methane 

and 

inventories 

analyze fuel switching strategies. 

Vented emissions primarily result from three categories: I) pneumatic 

Combusted 

devices, 2) blow and purge entissions, and 3) dehydrator entissions. 

emissions result from the incomplete combustion of methane 

in burners, flares, and engines. 

Vented and combusted emissions are typically considered unsteady 

emission sources, 

emission 

that is. sources with highly variable emissions. These 

sources vary from company 

because 

to company and site to site. 

Therefore, 

of different maintenance practices and operating conditions. 

it is impractical to measure every source continuously 

year. Each 

for a 

unsteady emission soUrce requires a unique set of equations 

and gathered data based on the equipment 

operating modes 

type, various components, and 

to produce an emissions factor. Data on unsteady 

emissions were gathered at multiple sites in each segment of the 

industry: production, gas processing, transmission, storage. and 

distribution. 

This report swnmarizes methane emissions 

minor miscellaneous 

from significant, as well as 

sources of vented and combusted emissions. 

addition, 

In 

this report serves to document 

determine methane 

the data sources used to 

compositions for the various industry segments. 

Finally, a discussion of inconsistencies 

emissions 

in reported vented and flared 

is provided to support the decision for using a bottom-up 

approach in this project to more accurately account for emissions from 

these sources. 

U.S. 

For the 

natural 

1992 base year the annnal methane entissions estimate for the 

gas industry 

equivalent 

is 3!4 Bscf ± 105 Bscf (± 33%). This is 

this program 

to 

were 

1.4% ± 0.5% of gross natural gas production. Results from 

used to compare greenhouse gas emissions 

fuel cycle 

from the 

for natural gas, oil, and cnal using the global warming 

IV 
potentials (GWPs) recendy published by the Intergovernmental Panel on 

Climate Change (IPCC). The analysis showed that natuta! gas 

contributes less to potential global wanning than coal or oil, which 

supports the fuel switchbg strategy suggested by IPCC aud 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 m 

cooperation with the American Gas Association to implement costeffective emission reductions and to report reductions to the EPA. Since 

this program was begun after the 1992 baseline year, any 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 

v 
TABLE OF CONTENTS 

Page 

1.0 SUMMARY ................................................. I 

2.0 INTRODUCTION ............................................. 2 

3.0 DATA COLLECTION .......................................... 4 

4.0 RESULTS .................................................. 8 

4.1 Compressor Exhaust ...................................... 

4.2 Pneumatic 

8 

Devices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 

4.3 Chemical 

I 0 

IJ1jection Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 

4.4 Dehydrator Vents 

12 

....................................... 

4.5 Dehydrator 

13 

Glycol Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 

4.6 Blow 

14 

and Purge ......................................... 15 

5.0 MISCELLANEOUS MINOR CATEGORIES . . . . . . . . . . . . . . . . . . . . . . . . . I8 

5.1 Burners .............................................. 

5.2 Flares 

18 

................................................ 20 

5.2.1 Combustion Efficiency ............................... 

5.2.2 Total Natural 

21 

5.3 Acid Gas 

Gas Flow to Gas Industry Flares .............. 24 

Recovery Vents .................................. 

5.4 Salt Water 

27 

Tanks ........................................ 

5.5 Drilling 

28 

. . . ................. ' . . . . . . . . . . . . . . . . . . . . . . . . . 

5.6 Drips 

29 

................................................ 

5. 7 Sampling 

30 

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 

6.0 REFERENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 

APPENDIX A Methane Composition ........................... A-1 

APPENDIX B Reported "Vented and Flared" Data . . . . . . . . . . . . . . . . . . B-1 

Vl 
LIST OF TABLES 

Page 

3-1 Emission Sources ........... , .................................. 6 

3-2 Emission Source Groups by Type .................................. 7 

4-1 Swnmary of Unsteady Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 

4-2 Blow and Purge Emission Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 

5-l Burner Fuel Gas Activity Factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 

5-2 Summary of Previous Flare Combustion Efficiency Studies . . . . . . . . . . . . . . . 22 

5-3 Non-Combusted Emissions from Production and Gas Processing 

(GRI!EPA Estimate Basis) ...................................... 25 

5-4 Maximum Flaring Emissions ..................................... 27 

5-5 Salt Water Tank Emissions ...................................... 29 

A-1 Methane Composition by Industry Segment . . . . . . . . . . . . . . . . . . . . . . . . . A-2 

A-2 Average State Methane Content and Production Rate . . . . . . . . . . . . . . . . . . . A-4 

A-3 Methane Composition of Production Gas A-5 

A-4 Methane Composition in Gas Processing A-5 

B-1 Comparison of 45-I Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-9 

B-2 1991 Flaring Pennits for Oklahoma .............................. B-10 

B-3 Supply and Disposition of Gas in the United State&-1989 .............. B-13 

vii 

1.0 SUMMARY 

This report is one of several volumes that provides backgrotmd information 

supporting the Gas Research Institute and U.S. Environmental Protection Agency, Office of 

Research and Development (GRl-EP AJORD) 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 swnrnarizes methane emissions from vented and combustion 

sources. Vented emissions primarily result from three categories: I) pneumatic devices, 2) 

blow and purge emissions, and 3) dehydrator emissions, which combined account for 

approximately 94 Bscf of methane emissions armually. Combustion emissions result from 

the incomplete combustion of methane in burners, flares, and engines. Compressor engine 

exhaust is the only significant source of methane in this category, accounting for 

approximately 25 Bscf of methane emissions annually. 

I 
2.0 INTRODUCTION 

For this project, sources of methane emissions from the natural gas industry 

were classified as follows: 

• Vented - Vented emissions are intentional releases from equipment 

blowdown for maintenance, releases from emergency depressuring 

(from safety valves and station emergency blowdown), direct venting 

of gas used to power equipment (such as pneumatic devices), or 

accidental releases due to mishaps (such as pipeline dig-ins). 

• Combustion - Combustion emissions refer to methane that enters the 

atmosphere due to the incomplete combustion of natural gas. 

Examples are methane in compressor engine exhaust and methane 

from flare stacks and burners. 

• Fugitive · Fugitive emissions are unintentional leaks from sealed 

surfaces (such as valve stem packing, flange gaskets, compressor shaft 

seals, and pipelines). 

This report summarizes emissions from vented and combustion sources. 

Vented and combustion emissions are typically considered "unsteady." Unsteady emitte~s 

are defined as sources with highly variable emissions, such as a pneumatic device on an 

isolation valve or a maintenance activity that requires blowdown. These· emission sources 

vary from company to company and site to site, because Of different maintenance practices 

and operating conditions. 

In contrast, emission sources with continuous bleed rates, or with reasonably 

steady bleed rates over a typical measurement time, are considered "steady" sources. 

Fugitive emissions are generally considered steady. Extensive measurements of fugitive 

emissions have been made in this and other studies in ali segments of the gas industry. 1

•

2

•

3 

Section 3 of this report discusses data collection techniques used to estimate 

unsteady emissions. Results from vented and combustion sources considered significant are 

presented in Section 4. Details on emission estimates for compressors, pneumatic devices, 

2 
dehydrators, chemical injection pumps, mishaps, etc. are available in other volumes. 4

•

5

•

6

•

7

•

8

•

9 

Section 5 discusses miscellaneous minor emission sources. Documentation supporting the 

methane compositions used for each industry segment is provided in Appendix A. This 

report also discussed inconsistency in vented and flared emissions in Appendix B. 

3 
3.0 DATA COLLECTION 

This GRI!EPA study calculated emission factors for unsteady emission 

sources, rather than measuring them. Each unsteady source requires a unique set of 

equations and gathered data based on the equipment type, various components, and 

operating modes to produce the emission factor quantity. However, all sources require the 

following general infonnation: 

I) A detailed technical description oftbe source, identifying the 

important emission-affecting parameters (i.e., equipment components 

and operating modes). This was generally accomplished through a 

source characterization report. 

2) Data to estimate the volume of natural gas released and the frequency 

of releases from multiple site visits or existing reports. 

3) Data on gas composition (percent methane) in various industry 

segments (production, gas processing, transmission, and distribution). 

Details on the methane composition results are provided in Appendix 

A. 

Step 1 was accomplished by researching each particular source and gathering 

manufacturer, operator, and site data so that a full technical description of the important 

emission characteristics of the source category could be written. Using this description, 

data on the emission-affecting characteristics of each source were gathered through site 

visits or existing resources. 

For many emission sources, the frequency of release events was measured 

(such as strokes/minute for pneumatic actuators); but for extremely infrequent releases (such 

as equipment maintenance blowdowns), the frequency was estimated by gas industry field 

personnel. The emission volume per event was not measured for most sources (as in the 

case of compressor exhaust methane) but was often calculated using gathered site data, 

existing reports, and first principles. 

4 
During this study, data on unsteady emissions were gathered at multiple sites 

in each segment of the industry: production, gas processing, transmission, storage, and 

distribution. Details on the industry segments and boundaries are provided in Volume 5 on 

the activity factors. 10 The site visits and literature searches allowed construction of a matrix 

that shows all the emission sources within the gas industry grouped by process segment and 

operation mode. Table 3-1 shows this grouping. The industry characterization also allowed 

a grouping of solU'Ces by emiss'ion type, as shown in Table 3-2. 

5 
TABLE 3-1. EMISSION SOURCES 

.·. 

Industry Segment-- Operating Mode 

Emtnion So~rces (Equipment or Activities) 

Production Stan Up Drilling (mud emissions) 

Well completion testing 

No:mal Operations Fugitives 

Pneumatic devices 

-control valves 

Chemical injection pumps 

Glycol dehydrators 

Compressor exhaust 

Compressor starts 

Maintenance Well bore maintenance 

Blow and purge 

Upsets/Mishaps Emergency blowdowns 

Dig-ins 

Gas Processing Plants Stan Up Not applicable or negligible activity 

Normal .Operations Fugitives 

Pneumatic devices 

- isolation valves 

Glycol dehydrators 

Acid Gas Recovery vents 

Engine exhaust 

Compressor starts 

Maintenance Blow and purge 

Upsets/Mishaps Emergency blowdowns 

NO MISHAPS 

Transmission and Storage Start Up Not applicable or negligible activity 

Nonnal Operations Fugitives 

Pneumatic devices 

• control valves 

- isolation valves 

Glycol dehydrators . Engine exhaust 

Compressor starts 

Maintenance Blow and purge 

Upsets/Mishaps Emergency blowdown 

Dig-ins 

Distribution Start Up 

Normal Operations Fugitives 

Pneumatic devices 

- control valves 

- isolation valves 

Glycol dehydrators 

Engine exhaust 

Compressor starts 

Maintenance Blow and purge 

UpsetsMishaps Emergency blowdown Dig-ins 

6 
Source 

Combustion 

Sources 

TABLE 3-2. EMISSION SOURCE GROUPS BY TYPE 

Type Emission Sources 

Unsteady Engine exhaust (compressors and other gas-driven engines) 

Flares 

Burners 

Vented Sources Unsteady Pneumatic devices 

Chemical injection pumps 

Glycol circulation pumps 

Glycol dehydrator vent 

Fugitive 

Sources 

Steady 

Acid Gas recovery (AGR) vent 

Blow and purge 

Mishaps 

(for start up, maintenance, and 

upsets/emergency conditions) 

Leaks from sealed surfaces 

(flange gaskets, valve stem packing, valve seats 

open to the atmosphere, pressure relief valve 

seats, compressor seals. etc.) 

Leaks from small holes in pipelines 

7 
4.0 RESULTS 

This section reviews the characterization results on the major unsteady 

categories. (Major categories were defmed as any source over I Bscf.) Minor categories 

are discussed in Section 5. Table 4-1 summarizes the results determined for each category of 

unsteady emissions in each industry segment. Details on the techniques used and the data 

gathered for each of the unsteady emission categories are provided in other documents of this 

multi-volume set on methane emissions.4

•

6

•

8

•

9

•

11•

12 

4.1 Compressor Exhaust 

Methane emitted to the atmosphere in compressor engine exhaust is a 

significant source of unsteady emissions and accounts for approximately 25 Bscf of methane 

emissions.4 Methane emissions result from the incomplete combustion of the natural gas 

fuel, which allows some of the methane in the fuel to exit in the exhaust stream. There are 

two primary types of compressor drivers: I) reciprocating gas engines, and 2) gas turbines. 

A few compressors in the industry are driven by other means such as electrical motors, but 

the majority are natural gas-fueled drivers. In addition to compressors, there are some 

natural gas drivers that operate site electrical generators for gas plants and compressor 

stations. 

Reciprocating engines emit more methane per horsepower or per unit of fuel 

consumed than turbine drivers: 0.24 scf/HP•hr for reciprocating versus 0.0057 scf/HP•hr for 

turbines. Reciprocating engines account for over two-thirds of aU installed horsepower in the 

gas industry (100,500 MMhp•br compared to 44,300 MMhp•hr for gas turbines). Therefore, 

reciprocating engines account for 98% of the methane emissions for this category. 

Emissions were determined by analyzing and combining several databases. A 

GRI database, the GRI TRANSDAT compressor module, 13 contains data from American Gas 

Association (A.G.A.} on types and models of compressors in use, as well as data on 

8 
TABLE 4-1. SUMMARY OF UNSTEADY EMISSIONS 

Source 

Compressor Exhaust 

Production 

Gas Processing 

Transmission 

Pneumatic Devices 

Production 

Gas Processing 

Transmission 

Chemical Injection Pumps 

Dehydrator Vents 

Production 

Gas Processing 

Transmission 

Storage 

Dehydrator Glycol Pumps 

Production 

Gas Processing 

Transmission 

Storage 

Acid Gas Recovery Vents 

Blow and Purge 

Production 

Gas Processing 

Transmission 

Distribution 

TOTAL 

Annual Methane 

Emissions, Bscf 

6.6 

6.9 

11.4 

31.4 

0.1 

14.1 

1.5 

3.4 

1.05 

0.10 

0.23 

11.0 

0.17 

0.82 

6.6 

3.0 

18.5 

2.2 

119 

9 

.. 90% Confidence Interval 

±200% 

± 130% 

± 15% 

± 65% 

± 64% 

± 60% 

± 203% 

± 193% 

± 208% 

± 392% 

± 166% 

±110% 

± 228% 

± 109% 

± 329% 

± 262% 

± 177% 

± 1,783% 

±54% 
compressor driver exhaust from the Southwest Research Institute (SwRI). A.G.A. gathers its 

data from government agencies, such as DOE and FERC, and from surveys of its member 

companies in transmission and distribution. SwRI data were generated through actual field 

testing. The data were combined to generate emission factors for this project by correlating 

compressor driver type, methane emissions, fuel use rate, and annual operating hours for 775 

reciprocating engines and 86 gas turbines. 

Horsepower•hour activity factors were developed for each industry segment 

using TRANSDAT, FERC, A.G.A., company databases, and site-visit data. TRANSDAT 

includes horsepower data for 7, 489 reciprocating engines and 793 gas turbines in 

transmission. Transmission operating hours were based on FERC data for 1992 and one 

company's data for 524 reciprocating engines and 89 gas turbines. Storage horsepower was 

based on A.G.A. data and operating hours are based on data from II storage stations. Since 

national totals. for transmission and storage horsepower are available, no industry 

extrapolation was necessary for these activity factors. Production horsepower•hours were 

based on one company's data for 516 reciprocating engines. Horsepower and operating 

hours for the gas processing segment were based on 10 site visits and company data for 18 

gas processing plants. Horsepowe~hours for production and processing were extrapolated to 

a total for the industry by using published data for nationally marketed gas produced and gas 

processed, respectively. 

4.2 Pneumatic Devices 

Pneumatic devices in the natural gas industry are valve actuators and 

controllers that use natural gas pressure as the force for valve movement. Gas from the 

valve actuator is vented during every valve stroke, and gas may bleed continuously from the 

valve controller pilot as well. Pneumatic devices are a significant source of unsteady 

emissions and account for 45.6 Bscf of methane emissions annually. 6 Methane emissions 

from pneumatic devices were calculated based on field measurements, site data, and 

manufacturers' data. 

10 
There are two primary types of these devices: 1) control valves that regulate 

flow, and 2) isolation valves that block or isolate equipment and pipelines. Of the two main 

types, isolation valves typically have lower annual emissions, although the emission rate per 

actuation can be large. This is because isolation valves are moved infrequently, for 

emergency or maintenance activities that require isolating a piece of equipment or section of 

pipeline. Alternatively, control valves typically move frequently to make adjusttnents for 

changes in process conditions, and some types of control valves bleed gas continuously. 

Each segment of the industry has very different practices regarding the 

pneumatic devices, as described below: 

Production 

The production segment accounts for the majority of pneumatic emissions: 

31.4 Bscf, or 69% of all pneumatic emissions. Compressed air is rarely used as a pneumatic 

operating medium in the production segment, since compressed air requires electricity at the 

often remote well sites, and since gas is readily available and less expensive. A typical 

production pneumatic device releases 126 Mscf methane annually and there are an estimated 

249,000 pneumatic devices associated with natural gas production. 

Gas Processing 

Pneumatic emissions from the gas processing segment are very small: 0.12 

Bscf annually, or approximately I% of all pneumatic emissions. Only one-half (56%) of the 

gas processing plants participating in this project use natural gas to operate pneumatic 

controllers and isolation valves; other sites use compressed air or electric motors. The 

natural gas-powered isolation valves in this industry segment are operated infrequently 

(once/month or once/year), so the annual emissions per site are relatively small 

(approximately 165 Mscf of methane per gas processing plant). 

II 
Transmission/Storage 

Pneumatic emissions from the t:ra.nsmission compression stations and storage 

stations account for 14.1 Bscf annually, or 31% of pneumatic emissions. In this industry 

segment, most of the pneumatics are gas-actuated isolation valves. There are a few 

pneumatic control valves used to reduce pressure or to control liquid flow from a separator 

or scrubber. The annual methane emissions from a transmission pneumatic device are 162 

Mscf, and there are approximately 87,000 of these devices nationally. 

Distribution 

Pneumatic emissions for the distribution segment are included in the meter and 

regulation station "fugitive" emission factor. 2 

4.3 Chemical Injection Pwnps 

Chemical injection pumps are a source of unsteady emissions and account for 

1.5 Bscf of annual methane emissions. 8 Gas-driven chemical injection pumps use gas 

pressure to move a piston which pumps the chemical on the opposite end of the piston shaft; 

the power gas is then vented to the atmosphere at the end of the stroke. The power ga~ may 

be natural gas or compressed air. Two types of chemical injection pumps were observed: 1) 

piston pumps, and 2) diaphragm pumps. The larger diaphragm pumps emit more gas per 

stroke, and they are used to pump a higher flow rate of chemical or to pump the chemical 

into high pressure equipment. 

Chemical injection pumps are used to add chemicals such as corrosion 

inhibitor, scale inhibitor, biocide, demulsifier, clarifier, and hydrate inhibitor to operating 

equipment. These additives protect the equipment or help maintain the flow of gas. The 

vast majority of these pumps exist in the production segment. located at the well sites, so 

that the chemical can protect all of the downstream and downhole equipment. As with 

12 
pneumatic control valves, the chemical injection pumps in production are primarily powered 

by natural gas. 

In the production segment, significant regional differences exist. Depending 

on the gas composition and conditions, some regions use very few pumps, while other 

regions use the pumps frequently. Many pumps also have seasonal operation since they 

protect against hydrate formation, which winter temperatures exacerbate. Approximately 

17,000 chemical injection pumps are associated with natural gas production. A typical 

methane emission rate is 248 scfd per pump, based on site and manufacturer data. 

Only a few pumps exist in the gas processing and transmission segments. The 

pumps that do exist are powered by compressed air at these stations, and as a result, have no 

methane emissions. 

4.4 Dehydrator Vents 

Glycol dehydrator vents are a significant source of methane emissions and 

account for 4.8 Bscf of methane emissions annually." The majority of the glycol 

dehydrators are located in production, but dehydrators are also present in the gas processing, 

transmission, and storage segments of the natural gas industry. Methane emissions are 

higher in the production segment (71% of the total emissions are attributed to glycol 

dehydrator vents) due to the high activity factor for this segment and the lack of flash tanks 

in most production dehydrators. 

Glycol dehydrators remove water from the natural gas through continuous 

glycol absorption. The water-rich glycol is then regenerated, or heated, which drives the 

water back out of the glycol. The glycol also absorbs some other compounds from the gas, 

including a small amount of methane. The methane is driven off with the water in the 

regenerator and vented to the atmosphere. 

13 
The important emission-affecting variables for dehydrators are: gas 

throughput, use of a flash tank, ·use of stripping gas, and use of vent controls routed to a 

burner. An emission factor was established for glycol dehydrator regenerator vents using 

three sources of data: 1) computer simulations of dehydrator operations using first 

principles; 2) data from actUal on-line analyzer samples taken from regenerator vents; and 3) 

multiple site visits. The resulting annual methane emission factors are: 276 scf/ill1scf 

drroughput for production, 122 scf/MMscf for gas processing, 94 scf/MMscf for 

transmission, and 117 scf/MMscf for storage. For each industry segment, the emission 

factor was combined with an activity factor to generate the national emission rate, where the 

activity factors are based on the annual volume of gas dehydrated (12.4 Tscf for production, 

8.6 Tscf for gas processing, 1.1 Tscf for transmission, and 2.0 Tscf for gas storage). 

4-5 Dehydrator Glycol Pumps 

Glycol dehydrator circulation pumps are a signitlcant source of unsteady 

emissions and account for approximately 11 Bscf of annual methane emissions. 12 These 

pumps use the high pressure of the rich glycol from the absorber to power pistons that pump 

the low-pressure, lean glycol from the regenerator. The pump configuration pulls additioual 

gas from the absorber along with the rich glycol (more gas than would flow with the rich 

glycol if conventional electrical pumps and level control were used). This gas is emitted 

along with other absorbed methane drrough the dehydrator vent stack. 

Gas-powered glycol circulation pumps are common throughout the industry, 

even in sites where electrical pumps are the standard for other equipment. The dehydrator 

equipment is often specified as a separate bid package, and the vendors most often use the 

Kimray gas pump as their standard pumping unit. The pumps are an integral part of the 

glycol dehydrator unit and their emissions occur through the same point. However. the 

pumps are the cause for most of the methane emissions from dehydrators, so they are 

considered separately. 

14 
Unlike chemical injection pumps which vent the driving gas directly to the 

atmosphere, dehydrator pumps pass the driving gas along with the wet glycol to the reboiler. 

Therefore, methane emissions from the pump depend on the design of the dehydrator, since 

gas recovery on the dehydrator will also recover gas from the pump. The demographics 

generated for the glycol dehydrator control system (flash drum recovery and vent vapor 

recovery) were also used to determine the net emission rate for glycol pumps. 

Based on a gas throughput basis, emission factors for glycol pumps were 

estimated to be 992 scf methane/MMscf for production and 178 scf/MMscf for gas 

processing. The corresponding annual activity factors are 1.1 Tscf and 0.96 Tscf, 

respectively. 

4.6 Blow and Purge 

Blow and purge is a large source of unsteady emissions and accounts for 

approximately 30 Bscf of methane emissions annually. 9 Blow (or blowdown) gas refers to 

gas that is vented due to maintenance, routine operations, or emergency conditions. A piece 

of process. equipment or an entire site is isolated from other gas-containing equipment and 

depressured to the atmosphere. The gas is discharged to the atmosphere for one of the 

following reasons: 

1) Maintenance Blowdown - the· gas is vented from equipment to eliminate 

the flammable material inside the equipment, thus providing a safer 

working environment for workers that service the equipment or enter 

the equipment. 

2) Emergency Slowdown - the gas is vented from a site to eliminate a 

potential fuel source. For example, if an equipment flre begins at a 

compressor station, the station emergency shutdown and emergency 

blowdown system blocks the station away from the pipelines and 

discharges the gas inside the station, thus reducing the fuel that could 

feed the fire. 

15 
The factors that affect the volume of methane blowdown released to the aonosphere are: 

frequency, volume of gas blowdown per event, and the disposition of the blowdown gas. 

Biowdown from maintenance releases was detennined for each equipment 

category: compressor blowdown, compressor starts, pipeline blowdown, vessel blowdown, 

gas wellbore blowdown, and miscellaneous equipment blowdown. Emergency blowdown 

refers to the unexpected release of gas by a safety device, such as a pressure-relief valve 

(PRV) on a vessel or the automatic shutdown/emergency blowdown of a transmission 

compressor station. Dig-ins, which are pipeline ruptures caused by unintentional damage, 

were also classified as an emergency release of gas. Table 4-2 summarized the emission 

factors and activity factors for the various blow and purge sources. 

Emission estimates for each industry segment were based on data from one or 

more of the following sources: I) site-visit data; 2) company-tracked data; 3) company 

studies; and 4) equipment characteristics. Data quality in the transmission segment was 

considered superior since it was based upon rigorous company-tracked data. Gas-processing 

data were extrapolated from transmission data based upon the similarities between gas plant 

compression and transmission compressor stations. Distribution segment data were 

considered good since they were based upon company studies. Production data were 

considered poor (and may be underestimated) since they are based upon operator 

recollections of blowdown frequency gathered during site visits. 

16 
TABLE 4-2. BLOW AND PURGE EMISSION RESULTS 

National Annual 

.. Methane Emission 

Industry Segment Annual Emission Factor Activity Factor Rate, Bscf 

Production: 

Gas Wells Unloading 49,570 ± 344% scf/well 114,139 ± 45% wells 5.66 ± 380% 

Compressor Slowdowns 3,774 ± 147% scf/comp. 17, 112 ± 52% compressors 0.065 ± 173% 

Compressor Starts 8,443 ± 157% scf/comp. 17, 112 ± 52% compressors 0.144 ± 184% 

Pipeline Miles 309 ± 32% scf/mile 340,000 ± 10% miles 0.105 ± 34% 

Production Vessels 78 ± 266% scf/vessel 255,996 ± 26% vessels 0.020 ± 276% 

Completion Flaring 733 ± 200% scf/completion 844 ± 10% completions 0.0006 ± 201% 

Well Workovers 2,454 ± 459% scf/workover 9,329 ± 258% workovers 0.023 ± 1,296% 

PRY Releases 34 ± 252% scfy/PRY 529,440 ± 53% PRYs 0.018 ± 289% 

ESD Releases 256,888 ± 200% scf/platform 1,115 ± 10% platforms 0.286 ± 201% 

Dig-ins 669 ± 1,925% scf/mile 340,000 ± 10% miles 0.23 ± 1,934% 

- Gas Processing 4,060 ± 322% Mscf/plant 726 ± 2% plants 2.95 ± 262% .._, 

Transmission and Storage: 

Stations 4,359 ± 322% Mscf/station 2,175 ± 8% stations 9.48 ± 263% 

Pipeline Miles 31.6 ± 343% Mscf/mile 284,500 ± 5% miles 9.00 ± 236% 

Distribution: 

PRY Releases 0.050 ± 3,914% Mscf/main 836,760 ± 5% miles main 0.04 ± 3,919% 

Dig-ins mile 1,297,569 ± 5% miles 2.06 ± 1,925% 

Slowdowns 1.59 ± 1,922% Mscf/mile 1,297,569 ± 5% miles 0. 13 ± 2,524% 

0.102 ± 2.521 Mscf/mile 
5.0 MISCELLANEOUS MINOR CATEGORIES 

There were many emission categories that contributed negligible amounts of 

methane (less than I Bsc!). Although small, these categories are discussed in order to 

provide a complete picture of the industry, but these emission sources are not itemized in the 

summary of annual emissions reponed by this study. Emissions from a few other minor 

categories are quantified in Volume 7 on blow and purge activities. 9 

5.1 Burners 

Burner combustion refers to the controlled burning of natural gas j.n order to 

add heat to a process stream. Burners combine air and gas in a controlled manner to 

maximize combustion efficiency. In the natural gas industry, burners are used in all industry 

segments. In the production segment, a -high-pressure gas well requires a choke and an inline heater to avoid freezing water in the line from the pressure drop flash. Glycol 

dehydrators, which are present in all industry segments, require a reboiler burner to beat and 

regenerate the glycol. Above-ground liquefied natuial gas (LNG) facilities may have boilers 

or hot oil furnaces for methane vaporization. Some gas plants may have additional burners 

in boilers and other sources. 

Non-combusted methane may he emitted by burners in two ways: I) since 

combustion is not 100% efficient, there is a small amount of methane that escapes from the 

burner uncombusted, and 2) if the burner has a flameout, all of the methane sent to the 

burner can be emitted uncombusted. This report has assumed that flameout emissions are 

negligible, based upon interviews with gas industry personnel. Therefore only incomplete 

combustion emissions are calculated in this section. 

The combustion efficiency of natural gas in burners was determined from 

Section !.4 of the U.S. EPA's AP-42 document." The burners in the natural gas industry 

fall under the industrial furnace category (between 10 and 100 MMBtu/hr of fuel fired). AP18 
42 shows that uncontrolled methane emissions from natural gas burners in industrial boilers 

are three pounds of methane per million cubic feet of fuel. The accuracy of these numbers is 

low, since AP-42 gives the data a rating of "C." 

In general, annual averages of combustion emissions are generated by 

estimates of the total gas flow to the burners, combustion efficiency, and flameout frequency 

and duration. The activity factor for this category is the total amount of burner fuel used in 

the industry. Nationally published numbers are available that show the total annual "lease 

and plant fuel use" and "pipeline fuel use," as shown in Table 5-1.15•

16 However, 

compressor engine fuel must be subtracted from these totals to detennine burner fuel use. 

Since there are no nationally available numbers 'for compressor engine fuel, compressor fuel 

use was estimated. 

TABLE 5-1. BURNER FUEL GAS ACTIVITY FACTOR 

National Fnel Use Ul' scf 

"Lease and Plant Fuel" (Gas Facts, Table 3-3)" 

- Production Compressor Fuela 

- Gas Plant Compressor Fuer 

- Estimated Burner Fuel (Production) 

"Pipeline Fuel Use" (Gas Facts, Table 3-4) " 

- Transmission Compressor Fuela 

- Storage Compressor Fuel" 

- Estimated Burner Fuel (T &s) 

1,070,452 

-219,700 

-469,500 

381,252 

630,083 

-400,100 

-53,210 

176,773 

'Estimated based on HP·hr from Volume 11 on compressor driver exhaust, the AP-42 "C02 

per HP•hr" emission factor, and the combustion equation. 4

•

14 

In addition, gas lift compressors also consume natural gas as fuel. Emissions 

from these compressors are considered to be attributed to the petroleum industry, based on 

the industry boundaries defmed by this project. 10 Methane emissions from this source have 

not been quantified and subtracted from the natural gas industry emissions. 

19 
The burner combustion efficiency was determined by using the AP-42 emission 

factors. The AP-42 emission factor (3 lb/10' ft') can be converted to a combustion efficiency 

as follows: 

3 lb CH4 

106 cf fuel 

X 

lbmol CH4 

16 lb CH4 

X 379 scf = 0.000071 

lbmol 

scf CH, 

scf fuel 

Multiplying the emission factor by the activity factor yields the emission rate for burners: 

(I) 

(381,252 MMscf scf CH • 176,773 MMscf) x 0.000071 4 = 0.039 Bscf (2) scffuel 

This value is insignificant. and therefore is not listed as an emission source in the total 

emissions estimate for this project. 

5.2 Flares 

Flares are devices used to provide a safe and economical means of gas disposal 

from routine operations, upsets, or emergencies via combustion of the gas. Flares prevent a 

controlled release of metbane from building up into a large cloud of gas that could explode. 

There is a wide variety of flares used in the natural gas industry ranging from small open· 

ended pipes at wellheads to large, horizontal, or vertical flares with pilots, such as those at 

gas plants. 

Methane emissions from flares result from the incomplete combustion of gas in 

the flare's flame or from time periods where there is no flame at the flare tip (flame-out) due 

to flare operational problems. Either of these cases results in emissions of non-combusted 

methane to the annospbere. To determine the total emissions from flares in the gas industry. 

two factors must be known: 1) the average methane combustion efficiency of flares 

(including flame-out periods) and 2) the total annual amount of natural gas flowing to flares 

in the United States. 

20 
5.2.1 Combustion Efficiency 

The combustion efficiency of flares is primarily dependent upon the flame 

stability which, in tum, depends on the gas velocity, heat content, and wind conditions. 

There are many problems in testing industrial flares for combustion efficiency; some of these 

include flare (and therefore flame) size, radiant heat, wind conditions, and proper probe 

placement within the flare flame. Therefore, most of the studies have been conducted on 

pilot flares, with the results extrapolated to the larger industrial-size flares. Table 5-2 

provides a summary of flare combustion efficiency studies compiled by Pohl and Soelberg. 17 

Only two of these studies used natural gas as the flare gas. The study by 

Straitz has a wide-efficiency range, but instrument problems are also noted. The only other 

study to use natural gas (Howes) shows an excellent combustion efficiency (>99%). 

However, the composition of the natural gas is unknown in Howes' combustion efficiency. 

Although methane is.a clean-burning gas, the composition of the natural gas in the 

production segment can vary substantially. As shown in Table 5-2, gas streams with 

heavier hydrocarbons or with a substantial sulfur cOntent, such as sour gas, result in lower 

combustion efficiencies. 

Table 5-2 shows two studies for open-ended pipes with combustion efficiency 

ranges of 90 to 99.9% and 92 to 99.7%. The lower efficiencies for these studies are due in 

part to the lack of features and controls, which are used to ensure flame stability in the 

larger, more efficient commercial flares. Another reason for the lower efficiency was that 

these two studies were conducted on heavier gas mixtures that did not include methane or 

natural gas. In the article by Straitz, "Flare Technology Safety, n the author claims that 

typical flare combustion efficiencies are 99+% for natural gas. 18 The author also points out 

that the combustion efficiency will be lower for gases with low-Btu heat content (due to 

nitrogen, water vapor, or H2S). Other sources give typical flare efficiencies as 98 to 99% 

as long as the flare is operated within the stability limits of the flame. 19•

20 

21 
TABLE 5-2. SUMMARY OF PREVIOUS FLARE COMBUSTION EFFICIENCY STUDIES" 

·Flare Gas E:dt Gas Heating 

Size Velocity 

Measured .. Value· Combustion 

Study Year (in) Design (f/s) (Btu/It') Gas Flared Eff. (%) 

Palmer 1972 

-.Comments 

0.5 Steam assisted 50-250 1448 Ethylene <97.8 Helium tracer for 

experimental 

full-size flare 

nozzle 

Merget 

evaluation 

1977 47 Full size NA NA Carbon black 2500ol EPA ROSE remote 

vinyl monomer reduction sensing system 

Straitz 

in CO 

1978 2-6 Steam and pilot - 1000-2350 Natural gas, 75-99 Results of limited 

propane validity due to 

instrument range 

Siegel 

sensitivity 

1980 17 Conunercial flare 0.7-16 1500 Refinery gas• 97-99 Multiposition plume 

gas 

Lee& 1981 

extractive sampling 

2 Holes in 2 ~ cap 1.8 2190-2385 Propane 96-100 

Whipple (I. I in2 open 

area) 

Howes, et al. 1981 (j> Conunercial air 40-60 2385 Propane 92-100 Both extractive and 

assist. Zink 

EPA ROSE plume 

STF-LH 

sampling 

1982 3at Commercial H.P. Near Sonic 

4' 

1000 Natural gas >99 

(estimate) 

McDaniel 1983 8 Commercial Zink 0.03-62 209-2183 Propylene/N2 67-100 Extractive and EPA 

STF-S-8 

ROSE plume 

sampling 

1983 6' Commercial air 1.4-218 83-2183 Propylene/N

assist. Zink 2 55-100 

STF-LH-457-5 

Continued 
TABLE 5-2. (Continued) 

Flare Gas Exit Gas Heating 

Size Velocity Value 

Study Year (In) D<slgn (fis) (Btuift') 

Pohl, et al. 1984 3-12 Open pipe and 0.2-420 291-2350 

commercial 

Pohl and 1985 0.042 Nozzle 31-854 923-3320 

Soelberg 

1985 1.5- Commercial 0.2-591 122-2350 

12 coanda steam 

injection, pressure assisted, air 

assisted, open 

pipe, pilot 

assisted 

1985 0.042 Nozzle 5.6-891 588-2350 

-2.5 

1985 3 Open pipe 0.15-139 145-877 

NA ' Not A vat •bie 

NM = Not Measured 

• 50% hydrogen plus light hydrocarbons. 

"Supplied through spiders; high Btu gas through area is 5.30 in2 and low Btu gas through 11.24 in2

. 

e Three spiders, each with an open area of l.3 in2

. 

Measured 

Combustion 

Gas Flared Eff. (%) Comments 

Propane/N1 90-99.9 Multiprobe plume 

extractive sampling 

25 different gas >98 Comparative 

mixtures (80-99.99 screening tests 

destruction 

efficiency) 

Propane/N2 36-99.9 Comparative commercia! flare type 

evaluation 

Propane/N2 NM Flame aerodynamic 

tests 

H2S/propane/N1 92-99.7 Gas mixture testing 

NHlpropane/N2 (92-99.9 

1 ,3 bmadiene/N2 destruction 

Ethylene efficiency) 

Oxide/N2 
Additional problems exist in the case of open-ended pipes used for flaring in 

must 

the production segment of the gas industry. These flares typically do not have a pilot and 

be lit manually. Therefore, the potential exists for the gas to be vented rather than 

flared when operating personnel are not available 

pressure 

to light the flare (i.e., gas vented through a 

relief valve to a flare). Much of the flaring done in the production segment occurs 

at well completion. Since operating personnel are always present during this activity, the 

volume of gas vented during well completion is smalL In addition, most state agencies 

require that any ongoing (post-completion) vent of wellhead gas be burned; the agencies have 

field auditors to ensure that this requirement is followed. 

On the basis that natural gas is predominantly methane (as presented in 

Appendix A), a combustion efficiency of 98% was used for the production segment of the 

natural gas industty and 99% for the other industry segments. A lower efficiency was used 

for the production segment to provide a more conservative estimate of emissions due to the 

variability of the composition of the natural gas as it is extracted from the well. Both 

efficiencies assume the flare to be operating under optimum flame stability. 

Flame-out in the natural gas industry was assumed to be negligible. Most gas 

processing plants are manned, so that flame-out at the flare would be observed and corrected 

quickly. In addition, many of these sites have pilots and/ or ignitors that ensure that the 

flame remains lit. For transmission,· flare stacks at compressor stations are uncommon; 

where they do exist, they have pilots and/or ignitors that ensure that the flame remains lit. 

with 

In the production segment, most flaring from natural gas industry wells is performed either 

operator supervision or occasionally with piloted flares, so that flame-out is minimaL 

5.2-2 Total Natural Gas Flow to Gas Industry Flares 

There are no published sources for the total volume of gas flared in the natural 

gas industty. While the American Gas Association (A.G.A.) does publish natural gas 

production and distribution volumes that include a number cailed "Vented and Flared, "15 this 

24 
number does not split the amount vented from the amount flared. For 1992, A.G.A. reports 

167.5 Bscf of natural gas "vented and flared" from production and gas processing. The 

A.G.A. number is derived by a pseudo material balance and includes all gas that is not 

marketed, reinjected, or used in the production field. Therefore, the A.G.A. estimate 

includes fugitive gas losses and vented losses, as well as flared volumes. If the A.G.A. 

estimate were reduced by the actual amount "vented" to the atmosphere (fugitive + vented 

volumes), the result would be the amount of natural gas that A.G.A. assumes is flared. This 

GRI/EPA study estimates 48.4 Bscf of methane from production and processing fugitive 

emissions and 58.9 Bscf of methane from production and processing vented emissions. 

Converting the GRI/EP A numbers to natural gas, based on the methane composition for each 

industry segment, results in 132.3 Bscf of natural gas as shown in Table 5-3. 

TABLE 5-3. NON-COMBUSTED EMISSIONS FROM PRODUCTION 

AND GAS PROCESSING (GRI!EPA ESTIMATE BASIS) 

Fugitive Emissions 

Production 

Processing 

Vented Emissions 

Production 

Processing 

TOTAL 

Bscfy Methane··· 

24.0 

24.4 

53.8 

5.1 

107.3 

Bscfy Natural Gas. 

30.4 

28.1 

67.9 

5.9 

132.3 

If the difference between the A.G.A. "Vented and Flared" volume (167.5 

Bscf natural gas) and the non-combusted emission volume from this study (132.3 Bscf natural 

gas) is assumed to result in the flared volume, then 35.2 Bscf of natural gas would be flared. 

Using a flaring efficiency of approximately 99% (as discussed in Section 5.2.1) and an 

average methane composition for production and processing of 82.9%, a flared emission rate 

can be estimated: 

25 
0.829 scf CH 35.2e9 set gas 4 x x scfgas 

0.01 scf CH4 non-combusted 

>d CH, flared 

• 029 Bscf CH, (3) 

There are concerns with the accuracy of this approach, in that the "Vented and 

Flared" volume report by A.G.A. is fraught with inconsistencies: it includes items not truly 

vented or flared, it does not include all vented and flared volumes (some sources from 

production and processing are overlooked, and transmission and distribution sources are not 

included). and each state may have different reporting requirements for the number. 

Appendix B discusses why this number is an inaccurate representation of the total vented and 

flared volume. 

Selected Method 

Without reasonable nationally-tracked numbers for flaring, site data were 

sought. Most sites, however, did not measure nor track flared volumes. lbis was especially 

true in the production segment. Therefore, an alternate approach was used based on an 

assumption that the total amount of gas flared would be equal to half of the total amount 

directly vented to the atmosphere by the industry. Table 5-4 shows the mefuane volumes 

vented in each industry segment, as presented in Volume 7 (Methane Emissions from Blow 

and Purge Activities).9 Using the flaring efficiencies for each industry segment discussed 

earlier, a flare emission rate can be calculated by multiplying the assumed flow by the 

combustion inefficiency term. 

As shown in Table 5-4, this alternate approach produces an estimate of 15.2 

Bscf of natural gas flared, which is significantly smaller than the A.G.A. approach. Since 

the A.G.A. approach is believed to overstate the flared amount, this alternate approach was 

selected. 

26 
TABLE S-4. MAXIMUM FLARING EMISSIONS 

Assumed Maximum Annual 

Flow to Flare, a Methane Emissions 

Industry Segment Bscf Flaring Efficiency from Flaring, Bscf 

Production 0.5 (6.6 ± 329%) 98% 0.066 + 329% 

Gas Processing 0.5 (3.0 ± 262%) 99% 0.015 ± 262% 

Transmission and 0.5 (18.5 ± 177%) 99% 0.093 ± 177% 

Storage 

Distribution 0.5 (2.2 ± 1,783% 99% 0.011 ± 1,783% 

TOTAL 15.2 ± 185% 0.185 ± 183% 

"Tile methane volume is assumed to be equivalent to half the vented quantity, where the vented volumes are 

reponed in the Blow and Purge Report. 9 

With either calculation approach, the estimated annual emissions from flares 

are negligible (less than 0.3 Bscf), and may be conservatively high, given the problems built 

into the A.G.A. number and that the flow to natural gas industry flares flare may be 

overestimated in the second approach. Therefore, this small category does not show up as an 

itemized contribution to total emissions in this report. 

5.3 Acid Gas Recovery Vents 

Acid Gas Recovery (AGR) vents are a very minor source of methane 

emissions and account for only 0.82 Bscf of methane emissions. AGR systems are used to 

remove acid gases (H2S and C02) by contacting the stream with a solvent (usually amines) 

and then driving the absorbed components from the solvent. The amines can also absorb 

methane and, therefore, methane can be released to the atmosphere through the reboiler 

vent. 

27 
Methane emissions were calculated using an ASPEN PLUS" process 

simulation. The disposition of AGR vent gas and the number of AGR units were taken 

from an API survey of U.S. Natural Gas Reserve Demographics. 21 The following 

assumptions were used in determining the emission rate: I) AGR units do not use flash 

drums or stripping gas; 2) AGRs have an absorption of methane similar to water; 3) the 

total number of AGR units in the United States are in the gas processing segment; and 4) 

82% of AGR emissions are controlled (I 8% of the emissions are vented). 

5.4 Salt Water Tanks 

Methane emissions from production salt water tanks were estimated using an 

ASPEN PLUS* process simulation. The flash calculations were based on the following 

assumptions: 

I) The natural gas industry produces 497 million barrels of salt water 

annually, of which approximately !00 million barrels are from coal 

bed methane wells. 21 

2) 70'/o of the water from gas wells is reinjected, 

water 

leaving 30% of the 

stored in atmospheric tanks. 22 

3) The hydrocarbon composition is 100% methane. 

The flash calculation results are summarized in Table 5-5 for cases with the 

salt content varied from 2 to 20%, and the pressure varied from 50 psi to 1000 psi. The 

simulation results indicate that methane emissions from salt water tanks are negligible. 

*ASPEN PLUS" is a registered trademark of Aspen Tecimology, Inc. 

28 
TABLE 5-5. SALT WATER TANK EMISSIONS 

Methane 

Methane Emissions, Emissions,. 

Salt Content, Wt % Pressure, pSi 106 lb/yr Bscf 

20% Salt 50 1.6 0.0 

250 10.8 0.0 

1000 38.8 0.0 

10% Salt 250 16.4 0.0 

1000 58.7 0.0 

2% Salt 250 19.4 0.0 

1000 69.5 0.0 

5.5 Drilling; 

Drilling operations typically use hydraulic pressure from the drilling mud to 

keep the oil and gas in the formation while drilling. The intent is to prevent the 

uncontrolled flow of oil and gas up the well bore (a potential blowout) until the snrface 

equipment is ready to receive the material. Drilling mud does absorb some gas and releases 

it in the degasser at the snrface. The quantity is typically small and has been excluded for 

this project. 

Blowouts during driliing or completion can be a large individual source of 

emissions, since the formation flows uncontrolled to the surface. The drilling industry has 

developed procedures and devices throughout the evolution of oil and gas production to 

prevent such an event. As a result, blowouts today are very infrequent and have not been 

considered. 

Once the desired formation or depth is hit, the well must be "completed" 

before it can be produced. Less expensive tubing replaces the strong drill string and an 

outer annular casing is cemented in place. The casing has many uses. It prevents the 

formation from caving in around the tubing, allows easier well maintenance, and allows 

29 
onshore, dead (no surface pressure) oil wells to produce oil up the tubing string and gas up 

the outer casing. If the oil and gas were produced in the tubing, the pumps would become 

vapor locked. 

Once the casing is in place, it is perforated and the formation begins to flow 

into the well. A clear completion fluid is used (heavy salt water) instead of mud, and the 

completion fluid will flow or be pumped to surface tanks or pits. Again, some small 

amount of gas may evolve from the completion fluid, but it is typically insignificant. 

After the completion fluid is out of the well, oil and/or gas flow begins. 

Depending on the type of weii, the gas may be vented, flared, or immediately produced. If 

the well was drilled in a known field with other existing wells, it is called a Developmental, 

or an Infill well. In that circumstance, the reservoir pressure and size are already defined, 

and the operator can have production meters and equipment sized and in place for 

completion. Very little venting and flaring would occur at completion, if any. 

If the well was an exploratory "discovery" well (i.e., one drilled in a new 

area of unknown reservoir potential), facilities may not be ready for the well's production. 

The well is flared for the time that it takes to measure the flow rates so that equipment can 

be sized. This period is referred to as completion, completi<?n flaring, or well testing. 

Emissions from completion flaring are minimal but are included in the blow and purge 

emissions.9 

5.6 

Some longer sections of gas-gathering and transmission pipelines may have 

small liquid collection pots located along the line. These pots are periodically blown down 

to clear collected hydrocarbon condensate, and the blowdown vents methane directly to the 

atmosphere. An unaccounted-for (UAF) gas study by Pacific Gas and Electric (PG&E) 

30 
defined drip blowdown emissions under urunetered company gas usage.23 They found the 

category to be insignificant, at 0.00035% of their total throughput. 

5.7 Sampling 

Gas is consumed in sampling and analyzing gas for composition and heating 

value. Much of this gas is then emitted to the atmosphere from the on-line analyzers or 

from the sample containers. Most sampling efforts begin in the gas processing areas, and 

field sampling represents a small fraction of the total samples. The PG&E UAF gas project 

estimated this category as insignificant, at 0.00107% of their total throughput. 23 

31 
6.0 REFERENCES 

!. Hummel, K.E., L.M. Campbell, and M.R. Harrison. Methane Emissions from 

the Natural Gas Industry, Volume 8: Equipment Leaks, Final Report, GRJ94/0257.25 and EPA-600/R-96-080h, Gas Research Institute and U.S. 

Environmental Protection Agency, June 1996. 

2. Campbell, L.M. and B.E. Stapper. Methane Emissions from the Natural Gas 

Gas 

Industry, Volume 10: Metering and Pressure Regulating Stations in Natural 

Transmission and Distribution, Final Report, GRl-94/0257.27 

600/R-96-080j, 

and EPAAgency, 

Gas Research Institute and U.S. Environmental Protection 

June 1996. 

3. Campbell, L.M., M.V. Campbell, and D.L. Epperson. Methane Emissions 

from 

Report, 

the Natural Gas Industry, Volume 9: Underground Pipelines, Final 

GRJ-94/0257.26 

U.S. Environmental 

and EPA-600/R-96-080i, Gas Research Institute and 

Protection Agency, June 1996. 

4. Stapper, C.J. Methane Emissions 

Compressor Driver 

from the Natural Gas Industry, Volume I 1: 

Exhaust, Final Report, GRJ-94/0257.28 and EPA-600/R96-080k, Gas Research Institute and U.S. Environmental Protection Agency, 

June 1996. 

5. Picard, D.J., B.D. Ross, and D.W.H. Koon. "A Detailed Inventory of CH4 

VOC Emissions 

and 

From Upstream Oil and Gas Operations in Alberta." 

Canadian Petroleum Association, Calgary, Alberta, 1992. 

6. Shires, T.M. and M.R Harrison. Methane Emissions from the Natural Gas 

Industry. Volume 12: Pneumatic Devices, Final Report, GRJ-94/0257.29 

EPA-600/R-96-0801, 

and 

Gas Research Institute and U.S. Environmental 

Protection Agency, June 1996. 

7. 

Methods 

Radian Corporation. Glycol Dehydrator Emissions: Sampling and Analytical 

Chicago, 

and Estimation Techniques. GRI-94/0324, Gas Research Institute, 

IL, March 1995. 

8. 

Chemical 

Shires, T.M. Methane Emissions from the Natural Gas industry, Volume 13: 

Injection Pumps, Final Report, GRJ-94/0257.30 and EPA-600/R-96-

080m, Gas Research Institute and U.S. Environmental Protection Agency, 

June 1996. 

32 
9. 

!0. 

11. 

12. 

13. 

14. 

15. 

16. 

17. 

18. 

19. 

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. 

Stapper. B.E. Methane Emissions from the Natural Gas Industry, Volume 5: 

Activity Factors, Final Report, GRJ-94/0257.22 and EPA-600/R-96-080e, Gas 

Research Institute and U.S. Environmental Protection Agency, June 1996. 

Myers, D. Methane Emissions from the Natural Gas Industry, Volume 14: 

Glycol Dehydrators, Final Report, GRJ-94/0257.31 and EPA-600/R-96-0SOn, 

Gas Research Institute and U.S. Environmental Protection Agency, June 

1996. 

Myers, D.B. and M.R. Harrison. Methane Emissions from the Natural Gas 

Industry, Volume I5: Gas-Assisted Glycol Pumps, Final Report, GRJ94/0257.33 and EPA-600/R-96-080o, Gas Research Institute and U.S. 

Environmental Protection Agency, June 1996. 

Biederman, N. GRJ TRANSDAT Database: Compressor Module. (prepared 

for Gas Research Institute). npb Associates with Tom Joyce and Associates, 

Chicago, IL, August 1991. 

U.S. Environmental Protection Agency. Compilation of Air Pollutant 

Emission Factors, U.S. EPA Office of Air Quality, Planning, and Standards, 

AP-42, Fifth Edition, Research Triangle Park, NC, January 1995. 

American Gas Association. Gas Facts: I990 Data, (Table 3-3), Arlington, 

VA, 1991. 

American Gas Association. Gas Facts: I993 Data, (Table 3-4), Arlington, 

VA, 1994. 

Pohl, J.H. and N.R. Soelberg. "Evaluation of the Efficiency of Industrial 

Flares: H,S Gas Mixtures and Pilot Assisted .Flares," EPA-60012-86-080 

(NTIS PB87-102372), September 1986. 

Straitz, J.F., III. "Flare Technology Safety," Chemical Engineering Progress, 

Volume 83, No.7, July 1987, pp. 53-62. 

Romano, R.R. "Control Emissions with Flare Efficiency," Hydrocarbon 

Processing, Volume 62, No. 10, October 1983, pp. 78-80. 

33 
20. Pohl, 

Flares," 

J.H., J. Lee, R. Payne, and B. Tichenor. "Combustion Efficiency of 

Association, 

77th Annual Meeting and Exhibition of the Air Pollution Control 

San Francisco, CA, June 24-29, !984. 

21. American Petroleum Institute. Survey of U.S. Natural Gas Reserve 

Demographics, Washington, DC, !992. 

22. 

ENSR 

Energy Environmental Research Center, University of North Dakota, and 

Consulting and Engineering. Atlas of Gas Related Produced Water 

for 1990. Gas Research Institute, 95/00!6, May !995. 

23. Pacific Gas & Electric Company. "Unaccounted-For Gas Project." Volume 

I, 1989. 

34 
APPENDIX A 

Methane Composition 

A-1 
APPENDIX A 

METHANE COMPOSffiON 

The composition of methane in natural gas is needed to calculate methane emissions 

from natural gas that is emitted to the atmosphere. This section describes the characteristics 

of natural gas streams in productio:t, processing, transmission, and distribution. The 

methane composition for each segment is presented in Table A-1. 

TABLE A-1. METHANE COMPOSffiON BY INDUSTRY SEGMENT 

Segment 

Production 

Gas Processing 

Transmission/Storage 

Distribution 

Methane (volume o/o) 

78.8 ± 5% 

87.0 ± 5% 

93.4 ± !.5% 

93.4 ± !.5% 

Production Segment · The production segment of the gas industry includes natural 

gas produced from gas wells (non-associated) and oil wells (associated). Data from the 

United States Bureau of Mines, Division of Helium Field Operations, and A.G.A. Gas 

Facts were used to calculate the production methane composition. 1

'

1 The Bureau of Mines 

(BOM) has been collecting analytical data from oil and gas wells and natural gas pipelines 

since 1917 in an effort to locate sources of helium. Under another GRl project, all 

published BOM data through 1987 were obtained on magnetic tape and loaded it into an 

Empress® database. 3 The focus of this earlier project was to determine the major 

contaminants in sour natural gas, specifically, hydrogen sulfide and carbon dioxide. Over 

14,000 records were used to determine county and state averages for natural gas 

composition, including methane content. 

The BOM data were corrected since a few non-gas industry wells that have very 

high helium or carbon dioxide content with little or no methane were included in the data 

A-2 
set. For the largest producing states, the Empress data files were reviewed and the entries 

with less than 40% methane were removed. Table A-2 shows the average methane content 

and marketed production by state. This information was regionalized to estimate the 

national average methane content of 78.8 mol % ± 5% as shown in Table A-3. 

Gas Processing Segment - The only source of methane data identified for the 

processing segment is from the Gas Engineer's Handbook. 4 These data are from November 

1951 and consist of eight data points with only two states, California and Texas, 

represented (see Table A-4). The data are reported as nafter processing plant" and were 

assmned to represent typical speciation data for natural gas leaving this industry segment. 

Due to the limited data set, an average methane content was calculated instead of a 

weighted average based on the state's fraction of U.S. production. The average methane 

content for the processing segment is 87 mol percent. A 90% confidence interval of 5% 

was calculated based on the spread of the available data. 

Transmission and Storage Segments - The methane composition for transmission 

and storage was based on the GRI TRANSDAT database,' which has analyses of fifty fuel 

gas samples from various transmission compressor stations. Since the fuel gas is from the 

pipeline, these should represent transmission gas quality. The resulting average methane 

composition for transmission is 93.4 mol% ± 1.5% (90% confidence interval is based on 

the spread of data). 

Distribution Segment - The Gas Engineer's Handbook provided methane 

composition data for the distribution segment.4 This data set includes distribution in 48 

cities, representing 29 states and the District of Columbia, for the fall of 1962. A weighted 

average was not used for this industry segment since the distribution of natural gas does not 

necessarily reflect the origin of the gas. The resulting average methane content is 

approximately 89 mol %. 

A-3 
The composition of gas leaving the processing segment should agree with the 

methane composition in the transmission and distribution segments, since the gas is only 

transported or stored. However, the distribution value is less than the methane composition 

determined for the transmission segment. Because the transmission data are based on the 

more recent and more extensive data source, the same composition is used for distribution. 

Therefore, the distribution methane composition used in determining emission factors is 

93.4 vol % ± 1.5%. 

' 

TABLE A-2. AVERAGE STATE METIIANE CONTENT AND PRODUCTION 

RATE 

Methane Composition, 

Region s·tates• 1989. Marketed Gas 

. Volume o/o ·· PrOduction, Bscf 

Gulf Coast AL 86.4 !51 

FL 60.2 ·8 

LA 87.8 

MS 5,087 

79.8 

TX 165 

75.1 6,401 

Central Plains AR 87.7 174 

co 65.4 227 

KS 69.4 

MO 60! 

69.4 

MT 

4 

69.4 

ND 

51 

62.5 

NE 

56 

53.4 

NM 

I 

64.4 

OK 856 

79.8 2,237 

SD 

WY 

4 

69.9 756 

Pacific and Mountain AK 76.5 394 

AZ 

I 

CA 75.3 

OR 364 

UT 3 

120 

Atlantic & Great IL 86.2 

Lakes KY 2 

76.2 

MI 

72 

74.4 !56 

NY 90.0 

OH 20 

82.0 160 

PA 91.0 192 

TN 85.2 

VA 

2 

88.0 

wv 18 

86.9 177 

States not shown had insignificant 1989 marketed gas production rates. 

A-4 
TABLE A-3. METHANE COMPOSITION OF PRODUCTION GAS 

Volume Percent MetbllDe (from 

state vol %'s weighted by state 

Region 

Gulf Coast 

Central Plains 

Pacific and 

Mountain 

Atlantic and Great 

Lakes 

Total U.S. 

production) Comments 

80.76 All states but GA represented 

73.68 Some states with insignificant 

production were excluded (lA. 

MN) 

75.92 Alaska and California only 

83.59 Some states with insignificant 

production were excluded (CT, 

DE, IN, MA, MD, ME, NC, NH, 

NJ, Rl, SC, VT, WI) 

78.8 Weighted average by regional 

production 

TABLE A-4. METHANE COMPOSITION IN GAS PROCESSING 

Location 

CA, Kettleman North Dome 

CA. Ventura 

TX, Agua Dulce 

TX, Carthage 

TX, Hugoton 

TX, Keystone 

TX. Panlumdle 

TX. Wasson 

Average 

A-5 

Methane Composition, Vol % 

93.0 

92.7 

93.0 

9!.7 

79.0 

86.2 

81.5 

76.9 

86.8 
REFERENCES: 

1. 

Operations, 

U.S. Bureau 

Amarillo 

of Mines. 

TX. 

Analyses of Natural Gases, 1917-1987. 6 vols. Helium Field 

February !988 (magnetic tape and hard copy). 

2. 

1991. 

American Gas Association. Gas Facts: 1990 Data, (Table 3-3), Arlington, VA, 

3. Radian Corporation. 

Gas Treatment Processes, 

Investigation of U.S. Natural Gas Reserve Demographics and 

Topical Report. Gas Research Institute, January 1991. 

4. 

Engineers 

"Natural Gas 

Handbook, 

from Various Gas Fields (As of November !951)," Table 2-12, Gas 

Industrial Press Inc., New Yorlc, NY, 1977. 

5. 

Gas 

Biederman, 

Research 

N. GRI TRANSDAT Database: Compressor Module. (prepared for 

August 1991. 

Institute) npb Associates with Tom Joyce and Associates, Chicago, IL, 

A-6 
APPENDIXB 

Reported "Vented and Flared" Data 

B-1 
APPENDIX B 

REPORTED "VENTED AND FLARED" DATA 

National numbers for "vented and flared" volumes are reported by production and 

processing companies to state agencies. which then report to the Department of Energy 

(DOE) Energy Infonnation Administration (EIA). Gas Facts publishes this EIA national 

number for "venting and flaring" (V&F) at approximately 0.71% of the total natural gas 

production. 1 Initially, it was assumed that the reponed V&F number was valid, and the 

approach for this project focused on simply splitting this number into a vented volume and a 

flared volume, so that vented emissions could be accurately quantified. However, this study 

discovered that the reported V &F number has many problems, and it is not a useful measure 

of actual venting or flaring. 

The reported numbers do not represent actual "vented and flared" quantities of gas, 

since companies do not use a standard practice or protocol for determining their V&F 

amount. In fact, many sites use a protocol 

Many 

that results in an erroneous value for V&F. 

gas plants simply report all material balance discrepancies as "vented and flared," even 

though most material balance losses are due to other factors, such as metering inaccuracies. 

Other companies have operators simply guess the amount of gas vented or flared in order to 

fill out a state form. Very few sites actually measure or accurately calculate V&F volumes. 

Even if the reponed V&F volumes were accurate. there is not a reliable method of splitting 

the number into the amounts flared (burned) and the amounts vented. Furthermore, there is 

no method for separating the amount of vented, unmarketed natural gas attributable to oil 

production. 

The GRI/EPA project abandoned use of the reported V &F number, and turned to a 

technique that identified each source of vented emissions, and estimated emissions from each 

source type. This technique is described in more detail in Volwne 3 on general 

methodology. 2 Tills appendix discusses the problems with the V &F numbers reported by 

operators to various state and federal government agencies. This section is only intended to 

B-2 
offer data supporting the decision not to use the reported V &F numbers in this GRI/EP A 

project. Sources of data for the United States and for individual states, as well as the quality 

of the data are covered in detail in the following subsections. 

B.l Specific States 

Specific state data were analyzed for Texas, Oklahoma, and Louisiana. These three 

states comprise 68% of all the gas produced in the U.S. in 1989 and are representative of gas 

production facilities. States that are major producers of oil and gas generally have state 

governmental agencies that regulate and maintain data on the oil and gas industry. The 

regulating agencies for Texas, Louisiana, and Oklahoma are the Texas Railroad Commission 

(RRC), the Louisiana Department of Natural Resources (DNR), and the Oklahoma 

Corporation Commission, respectively. 

The primary goal of these agencies is to control the industry (provide "fair play" for 

all operators), collect fees, and protect the community and the environment. Methane 

emissions have not been a concern for these agencies except where the emitted methane 

represents. 1) an unnecessary waste of natural resources that should come out of a company's 

"allowable" production quota; 2) a toxic gas hazard (H2S); or 3) a fire or explosive hazard. 

To the extent that methane emissions represent a measurable loss of natural resources, the 

agencies track data on "venting and flaring! For many agencies, the V&F numbers are 

grouped together. No differentiation is made between amounts acrually burned versus 

amounts vented; however, there is one exception. Permits filed under Rule 32 in the Texas 

RRC code do differentiate between venting and flaring. 

The accuracy and extent of the reported V &F numbers are a function of the V &F 

defmition the state uses in the reporting regulations, the state's enforcement of reporting 

regulations, and the exclusions that the state allows. Given a broader definition, more 

emissions are included; however, given more exclusions, fewer events will be reported. 

B-3 
Finally, given weaker enforcement, more unreported quantities will exist. Some of the statespecific data are discussed below. 

B.I.l Texas 

For Texas, most of the V &F numbers are reported as one number to the RRC on a 

monthly basis. Gas plant operators send in R-3 forms, and oil and gas producers send in P-1 

and P-2 forms, respectively. Oil wells are tracked by the lease, and gas wells are tracked by 

the individual well. The data from these forms are summed into tables in the RRC's 

published Oil and Gas Annual Repon' The RRC also requires a permit for flares or vents 

lasting more than 24 hours in the R-32 form. The specific forms are discussed in more 

detail below. 

Among the states, Texas probably has the strongest regulations, the strongest enforcement, and the most comprehensive published data. Nevertheless, the reported vented and 

flared numbers in Texas are difficult to assess; there are areas over-reported and underreported due to definition. Amounts vented from compressor engine exhausts, pneumatic 

actuators, glycol vents, and acid gas recovery vents have never been considered as part of 

the V&F definition for reporting. In addition, the definition of V&F is different even among 

the various RRC forms. 

R-3 Gas Plants- For gas plants, the V&F number on the R-3 is simply the result of 

a material balance closure around the gas plant. The rule is: 

GAS IN - PRODUCTS OUT- CONSUMPTION = V&F 

Measured outlet dispositions (pipeline gas, fuel, extraction loss, etc.) are subtracted from the 

inlet plant meter, and the difference is reported as V&F. The difference is really just an 

"unaccounted-for" (UAF) number arrived at by an accounting procedure; it is usually 

positive and in the range of 0.3% of the total gas processed. The flare, which in the gas 

B-4 
plant has orifice meter readings near zero, is not considered in the calculation of the reported 

V&F number. 

If the gas plant material balances are absolutely accurate (all quantities included are 

on the same basis) and have a zero meter bias (doubtful, but possible), then the reported 

V&F number, even though a calculated value, is a true "emitted, vented, or flared" amount. 

From the V&F number, the flare meter reading could be subtracted, the fugitive emissions 

subtracted, and the remaining value would be material actually vented. This is the "topdown" yardstick that the "bottom-up" emissions rates for gas plants can be compared to. 

R-3 Cycling Plants (Pressure Maintenance) - Cycling plants process gas to reduce 

the dew point of condensibles in the formation and thus extend the life of a field. In most 

cases, not all of the gas is returned to the formation in a cycling plant. Again, data from the 

Texas Railroad Commission indicate that for the 15 pressure maintenance facilities in Texas, 

51.6% of the residue gas is used for repressurizing or cycling, while 26.6% is sent to 

transmission pipelines. 3 It should be noted also that the V &F estimate for cycling plants is 

0.3% of the total gas processed, which is the same as for gas plants. 

P-1, P-2 Production- A P-1 report is generated for each oil lease and a P-2 report 

for each gas well. For production facilities, V&F on the P-1 and P-2 reports is meant to 

represent a real vented and flared quantity at the wellhead. Nevertheless, many releases are 

exceptions to the reponing requirements, including: well completion flaring for up to 10 

days, events less than 24 hours in duration, well cleanups, and venting and flaring from 

certain field equipment (glycol separators and pneumatic devices). This excludes many of 

the true release events from the numbers recorded by the RRC. 

Even the accuracy of the categories that are included in reporting is questionable. 

Production flares have no pilot and no meter, so reported values are operator estimates. The 

operators generally base their estimates upon the most recent well test data or upon the 

B-5 
field's gas-to-oil ratio. No actual measurements are used for P-1 or P-2 reported values, and 

the RRC admittedly has no way to verifY the reported values. 

There are so many exceptions and estimations in the reported production numbers that 

it is impossible to intuitively tell whether the number is over- or under-reported. As with 

gas plants, a method that does not use the reported V&F numbers must be used to estimate 

real production emissions. The reported numbers can then be adjusted to use only as a check 

value for the bottom-up calculations. 

Rule R-32- The Texas RRC Rule 32 does have some impact on the V&F amounts. 

The rule allows 10 days of venting following completion of a well, and then requires all gas 

to be flared. In addition, permits are required for flares or vents beyond initial completion 

(exceptions are well cleanups or repairing/modifying a gas-gathering system). The permit 

form has one very useful piece of data: ·a designation of venting that is different from 

flaring. The form is the only place in the reported V&F category where the operator must 

designate whether he intends to vent or to flare for the specific release permit. 

The RRC tracks Rule 32 pennits to make sure that sour gas is burned and that large 

vented releases are not near major roadways nor populated areas. Releases of unburned sour 

gas can be toxic, and large vented releases can be explosion or fire hazards. The R-32 data 

were used for this project to establish a percentage split between vented versus flared for all 

the production V&F totals that are reported. The data were reviewed for 1991 permits and 

showed that the amount vented was 7.7% and the amount flared was 92.3% of the total 

V&F. However, the assumption that the non-permitted quantities have the same split may be 

incorrect, since events less than 24 hours and well cleanups are exceptions. Therefore, many 

venting events may not be part of these data. 

Oil and Gas Annual Report - With all of the above limitations in mind, the data 

from annual reported values were analyzed. Most of the reported venting and flaring 

volumes were for casinghead gas (oil well gas). There are many more oil wells than gas 

B-6 
wells. For that reason. there is a significant quantity of casinghead gas produced. In Texas. 

23% of all gas produced is casinghead gas. 

Of the total reported V &F amounts, V &F from casinghead gas at the well accounts 

for 47.5%, while V&F from gas at the well accounts for only 5%. Gas well gas V&F is 

likely under-reported, since well cleanups are not reported. The data show that a disproportionate amount of the reported V&F is due to casinghead gas. The remainder of the 

reported V&F amounts is due to V&F reported at gas plants. This accounts for 47.5% of 

the reported total V &F amount. 

These data show that gas wells typically vent or flare infrequently. This makes sense 

from an economic point of view, since vented gas represents a direct loss of the well's only 

revenue. Casinghead gas (oil well gas) is vented or flared more frequently. Gas lost. 

through V &F at oil wells is also a loss of revenue but on a much less significant scale. The 

oil revenue is typically much larger than the gas revenue. 

Casinghead gas that is V &F may he from wells that never produce gas to a pipeline 

and, therefore, should not be considered part of the gas industry emissions. Those wells 

would either consume all of the produced gas as lease fuel, reinject all of the gas, or 

vent/flare all of the gas. Summing those three disposition categories for the RRC's 

casinghead gas annual table shows that 4.3% of the total casinghead gas is used for those 

purposes. If all oil wells had identical gas production, tltis would mean that the maximum 

amount of oil wells that should be excluded is 4.3%. For a more exact answer, the number 

of oil wells that do not market gas must be known. 

The reported V &F numbers for Texas imply that 0.53% of all gas produced is vented 

or flared. However, the following problems are associated with the Texas statistics [pluses 

( +) are shown for comments that would raise the reported numbers when corrected, and 

minus (-) symbols are shown for items that would reduce the reported numbers]: 

B-7 
(-) 

an 

Approximately 

accounting 

one-half of the V&F amount is due to gas plant V&F, which is 

closure number and not really venting and flaring. Even if a 

gas plant material balance is assumed to have a zero bias. fugitives should be 

subtracted from the V &F numbers reported. 

(-) Nearly half of the reported venting and flaring gas is from casinghead gas. 

a 

Some 

gas 

of this casinghead gas is associated with oil wells that do not produce to 

pipeline, and that fraction is, therefore, not part of the namral gas 

industry as defined by this project. This amount could be excluded if a 

defensible basis were derived to separate those wells. 

(-) Venting and flaring permit rates are usually overestimated (in the RRC's 

opinion) because many of the producers do not want to apply for pennit 

exceptions if the rate increases. 

( +) Many events are exempted from the reporting rules (such as well cleanup, well 

completion, and events less than 24 hours). 

(+) Some oil wells that produce associated or dissolved gases do not report V&F. 

( +) 

miscellaneous 

Emissions from tank batteries, glycol dehydrators, AGRs, and other 

sources are not reported. 

Therefore, even though Texas' reported V &F numbers appear to give an overall entission 

estimate for V &F emissions. they cannot be used as a quantitative measurement. 

B.l.2 Louisiana 

The Louisiana Department of Namral Resources (DNR) tracks V &F in a manner 

similar to the Texas RRC. Operators report the monthly production (wellhead) disposition 

data on the R-5D forttt and the gas plant data on the R-6 forttt. The DNR, like the Texas 

RRC, compiles all of the monthly data on computer files. The DNR, however, only makes 

the data available through specific, standardized computer runs which must be pre-paid by 

the requestor. 

B.S 
Radian has not requested Louisiana runs; however, Louisiana provided the 1988 

Parish Report during a visit to the DNR. The report showed a total onshore V &F number 

similar ro Texas, ar 0.47% of total gas production (Texas was 0.51 %). 

Louisiana's definitions of venting and flaring for reported numbers appear to be 

similar to Texas; and, therefore, Louisiana data will have the same problems that were 

described for the Texas data. Louisiana also has no method of separating the split between 

vented and flared quantities from the single V&F numbers reported on the R-5D and R-6 

forms. In fact, the term "venting," such as the "vented" column on the R-6 form, refers to 

venting or flaring. 

Although Louisiana does not have a Rule 32 flare pennit requirement as Texas does, 

it has a Statewide Order 45-I that requires a semiannual status report, which lists casinghead 

and natural gas "vented" by lease and explains why the gas is not being recovered. 

Unfortunately, the DNR does not aggregate these data; the data are received in nonstandard 

letter format and stored as received. It would be very difficult and time-consuming to 

assemble all of these data into a meaningful form. ·For example, Radian's examination of 

three 45-I status reports indicated very different results as shown in Table B-1. 

Company 

Mid-size company 

Large company 

Small company 

TABLE B-1. COMPARISON OF 45-1 REPORTS 

Type of Gas Reason for Venting 

Casinghead gas Uneconomical to recover. Most vent points were lowpressure heater treaters. Some fields used intermittent 

gas lift, thus, consuming all of the produced gas . 

intermittently. 

Unknown Majority of emissions were from compressor 

downtimes. 

Unknown Compressor downtimes. 

B-9 
B.l.3 Oklahoma 

The Oklahoma Corporation Commission's Oil and Gas Conservation Division issues 

venting and tlating permits. However, only rates above 50 Mcfd require a permit, and few 

wells fall into that category. The permit file 'or 1991 bad only nine permits issued as shown 

in Table B-2. 

TABLE B-2. 1991 FLARING PERMITS FOR OKLAHOMA 

Number of 

Permits 

6 

1 

2 

Percent of Total 

Permits 

67 

11 

22 

Reason for Request 

Recover load water from gas well (well clean-up). 

H,S found, pulled from gathering system and flared. 

Other (unknown) 

Oklaboma appears to have significantly fewer reporting requirements than Texas or 

Louisiana and had no other data on V&F available. Interestingly, Oklaboma does not appear 

to exclude well cleanups from the permit requirements as Texas does. As shown above, well 

cleanups constitute a large percentage of the permits issued in Oklaboma. 

B.2 United States 

There are several sources of information gathered on the natural gas industry for the 

entire United States. These sources include federal agencies, such as the Federal Energy 

Regulatory Commission (FERC) and the Department of Energy (DOE), and gas industry 

representatives, such as the American Gas Association (A.G.A.). Numerous publications are 

compiled by these agencies and include information on gas industry fmancials, gas 

production and disposition, and gas storage and reserves. Data are also collected from 

regulatory agencies and other private agencies, such as the American Petroleum Institute 

(APD. 

B-10 
There are five PERC forms that deal specifically with the natural gas industry. The 

main form completed by gas companies regulated by FERC is the FERC Form No. 2, 

"Annual Report for Major Natural Gas Companies." This form is an annual requirement for 

major gas companies, which are defined by the FERC as "baving combined gas sold for 

resale and gas transported or stored for a fee exceeding 50 Bcf (at 14.73 psia 60"F) in each 

of the three previous calendar years." Most of the information collected on this form is 

fmancial and, therefore, does not contribute to the data gathering effort for V&F. The other 

FERC forms collect information on underground storage (FERC-8), gas pipelines (FERC11,-15), and gas supply (FERC-16). 

The Energy Information Administration (EIA) of the DOE, publishes many reports on 

the natural gas industry. One of the most useful publications is the Natural Gas Annual.4 

Two EIA forms provide most of the information used in this report; EIA-176, "Annual 

Report of Natural and Supplemental Gas Supply and Disposition," and EIA-627, "Annual 

Quantity and Value of Natural Gas Report." The EIA-176 is a mandatory form to be 

completed by all companies that deliver natural gas to consumers or transport interstate gas, 

The EIA -627 is a voluntary form completed by energy or conservation agencies in gasproducing states. Other sources of information used by EIA for the Natural Gas Annual 

include the FERC, the United States Geological Survey (USGS), and the Interstate Oil 

Compact Commission (IOCC). Information directly from the USGS and the IOCC bas not 

been gathered for this venting and flaring task. 

The Natural Gas Annual provides information on gas production, transmission, and 

consumption for the United States as a whole and for each gas-producing state individually. 

Included in this report are numbers for gas V&F. Both the EIA-176 and the EIA-627 collect 

gas V &F information. Since these data are taken directly from the responsible state 

agencies, any differences in reporting requirements and/or the definition of vented and flared 

are not accounted for in this publication. Some of these differences were identified in the 

previous sections on individual state reporting. The EIA is aware of this inherent problem, 

but it is not known if the agency adjusts the data to reflect these differences. 

B-11 
The A.G.A. 's Gas Facts is an annual publication containing data on the gas utility 

industry. The data concentrate on gas distribution and transmission but also include some 

information from the gas-producing segment of the industry. Most of the information is 

gathered by the A.G.A. in its survey entitled "Uniform Statistical Report. The only 

information on venting and flaring provided in the Gas Facts was taken from the EIA 

Natural Gas Annual. Again, this infonnation is just a reiteration of the numbers reponed by 

the responsible state agencies with the inherent problems already discussed. A summary of 

the national statistics in Gas Facts is shown in Table B-3. 1 

It appears that any data ~hich are derived from an overall United States approach are 

just a summation of the data reported by the individual gas-producing states. Due to the 

variability in these data, the task of characterizing V &F in the natural gas industry should 

follow a bottom-up approach and begin with the identification of the individual sources. 

Then, respective methane emission estimates could be calculated and added to determine the 

overall emission number for the entire United States. 

REFERENCES 

I. 

1991. 

American Gas Association: Gas Facts: 1990 Data, (Table 3-3), Arlington, VA, 

2. Harrison, M.R., HJ. Williamson, and L.M. Campbell. Methane Emissions 

Natural Gas 

from the 

94/0257 

Industry. Volume 3: General MethodiJlogy, Final Report, GRIProtection 

.20 and EPA-600/R-96-080c, Gas Research Institute and U.S. Envirotunental 

Agency, June 1996. 

3. 

Operations 

Texas Railroad Co!Illlrission. Oil and Gas Annual Repon. Volume I "Cycling Plant 

in Texas," Data Source: RRC Form R-3, 1991. 

4. 

State," 

U.S. Department 

Natural Gas 

of Energy. "Quantity of Natural Gas Used as Lease Plant Fuel by 

Office 

Annuall992, Volume I. Energy Information Administration, 

240. 

of Oil and Gas, U.S. Dept. of Energy, Washington, DC, November 1993, p. 

B-12 
TABLE B-3- SUPPLY AND DISPOSITION OF GAS IN 

THE UNITED STATES - 1989' 

MMcf Percent of Total 

Production 

Gas Wells 

Oil Wells 

Total 

Disposition 

Extraction Loss 

Fuel and Lease Use 

Pipeline Fuel 

Gas Lift 

Repressure and Pressure Maintenance 

Cycled 

Underground Storage (Net Charge) 

To Transmission Lines 

To Carbon Black Plants 

Vented or Flared 

Acid Gas (H2S, C02, H,O) 

Plant Meter Difference (UAF) 

a Data reported includes gas processing. 

15,735,849 

5,262,981 

20,998,030 

784,502 

1,070,452 

630,083 

Unreported 

2,451,342 

Unreported 

(310,802) 

15,688,047 

Unreported 

140,532 

362,457 

182,217 

B-13 

74.9 

25.1 

100.0 

3.7 

5.1 

3.0 

·-

11.7 

(1.5) 

73.3 

0.7 

1.7 

0.9 
(PI~ 

TECHNICAL REPORT DATA rou/ 1/IIUnlt:tiOIU 01t th~ ~be/~ compl~tingj 

T. REPORT NO. 

I' 3. RECIPIENT'S ACCESSION NO. EPA-600/R-96-0SOf 

4. TITLE AND SUBTITLE 

5. REPORT DATE Methane Emissions from the Natural Gas Industry, June 1996 Volumes 1-15 (Volume 6: Vented and Combustion 6. PERFORMING ORGANIZATION CODE 

Source Summary) 

.,_ AUTHOR(s' L. camf1bell. M. camrfbelL M. Cow~l. D. Ep- . PERFORMING ORGANIZATION REPORT NO 

~erson, M. Hall, • Harrison. • Hummel, D. yers. DCN 96-263-081-17 

g_ PERFORMING 

• Shires, B. 

OROANIZATION 

Stapper. C. Stapper. J. Wessels, and * NAME ANO ADDRESS 10. PROGRAM ELEMENT NO. Radian International LLC 

P.O. Box 20!088 

11. CON RAC /GRANT NO. 

A us tin, Texas 78720-1088 5091-251-2171 (GRI) 

68-DI-0031 (EPA) 

12. SPONSORING AGENCY NAME AND ADDRESS 

13. TYPE OF iPORT /NO PERIOD COliER EO 

EPA, Office of Research and Development Final; 3 91-4 96 

14. SPONSORING _..CENCY CODE 

.Air Pollution Prevention and Control Division 

Research Triangle Park, NC 277ll EPA/600/13 

1f.SUPPLEMENTARY NOTEs EPA project officer is D. A. Kirchgessner. MD-63. 919/541-4021. Cosponsor GRI project officer is R .. A .. Lott. Gas Research Institute, 8600 West Bryn 

Mawr Ave., Chicago, IL 60631. (*)H. Williamson (Block 7). 1G • .i:!STRACTThe TO-volume report summarizes the results of a comprehensive program 

o quantify methane (CH4) emissions from the D. S. natural gas industry for the base 

~~ar. The objective was to determine CH4 emissions from the wellhead and ending 

ownstream at the customer's meter. The accuracy goal was to determine these 

~missions within +/-Of 5% of natural gas production for a 90% confidence interval. For 

[the 1992 base year. total CH4 emissions for the U .. S. natural gas industry was 314 

+I- 105 Bscf (6. 04 +I- 2. 01 Tg). This is equivalent to I. 4 +I- 0. 5% of gross natural 

gas production. and reflects neither emissions reductions (per the voluntary AmeriGas Association/EPA Star Program) nor incremental increases (due to increased 

gas usage) since 1992. Results from this program were used to compare greenhouse 

as 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 the IPCC and others. In addition. study results are being used by the n"a.tural gas 

industry to reduce operating costs while reducing emissions. 

I 

I 

' 

.. 

"· KEY WORDS ANO DOCUMENT ANALYSIS 

DESCAIPTORS b. IDENTIFIERS/OPEN ENOEO TEAMS 

Pollution 

c COSA Tl Field/Group 

lPollution Prevention 

Emission 

13B 

Stationary Sources 

Greenhouse Effect 

14G 

Global Warming 

Natural Gas 

04A 

Gas Pipelines 

21D 

Methane 

l5E 

07C 

18. OISTA19UTION STATEMENT 

19. SECURITY CLASS (This R~port) 21. No6

yF PAGES 

Release 

Unclassified 

to Public 20. SECURITY CLASS (Thisp4gej 

Unclassified 22. PRICE 

EPA Form 2220·1 (9-73) B-14 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

Office of Research and Development National Risk Management Research Laboratory 

Technology Transfer and Support Divfsfon 

Cincinnati, Ohio 45268 

OFFICIAL BUSINESS 

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Publication No. EPA- 600/R-96-0BOf