- -- -
\ 

\ 

' 

FOREWORD 

The U.S. Environmental Protection Agency is charged by Congress with protecting the Nation's land. air. and water resources. Under a mandate of national 

environmental laws. the Agency s·trives to formulate and implement actions leading to a compatible balance between human activities and the ability of natural 

systems to support and nurture life. To meet this mandate. EPA's research 

program is providing data and technical support for solving environmental problems today and building a science knowledge base necessary to manage our ecological resources wisely. understand how pollutants affect our health. and prevent or reduce environmental risks in the future. 

The National Risk Management Research Laboratory is the Agency's center for 

investigation of technological and management approaches for reducing risks 

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

research program is on methods for the prevention and control of poll~tion to air. 

land. water. and subsurface resources; protection of water quality in public water 

systems; remediation of contaminated sites and groundwater: and prevention and 

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

development and implementation of innovative,. cost-effective environmental 

technologies: develop scientific and engineering information needed by EPA to 

support regulatory and policy decisions: and provide technical support and inf6:rmation transfer to ensure effective implementation of environmental regulations 

and strategies. 

This publication has been produced as part of the Laboratory's strategic longterm research plan. It is published and made available by EPA's Office of Research and Development to assist the user community and to link researchers 

with their clients. 

E. Timothy Oppelt. Director 

National Risk Management Research Laboratory 

EPA REVIEW NOTICE 

This report has been peer and administratively reviewed by the U.S. Environmental 

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

commen:::ial products does not constitute endorsement or recommendation for use. 

This dOa.Jment is available to the public through 

Service, Springfield, 

the National Tec/lnicallnfonnation 

Virginia 22161. 
EPA-600 /R-96-CSOb 

June 1996 

METHANE EMISSIONS FROM 

TiiE NATURAL GAS INDUSTRY 

VOLUME 2: TECHNICAL REPORT 

FINAL REPORT 

Prepared by: 

Matthew R. Harrison 

Lisa M. Campbell 

Theresa M. Shires 

R. Michael Cowgill 

Radian International LLC 

8501 N. Mopac Blvd. 

P.O. Box 201088 

Austin, TX 78720-1088 

DCN: 650-049-20-01 

For 

GRI Project Manager: Robert A. Lott 

GAS RESEARCH INSTITUTE 

Contract No. 5091-251-2171 

8600 West Bryn Mawr A venue 

Chicago, IL 60631 

and 

EPA Project Manager: David A. Kirchgessner 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

Contract No. 68-01-0031 

National Risk Management Research Laboratory 

Research Triangie Park, NC 27711 
DISCLAIMER 

work 

LEGAL NOTICE: This report was prepared by Radian International LLC as an account of 

sponsored by Gas Research Institute (GR1) and the U.S. Environmental Protection Agency 

(EPA). Neither EPA, GRl, members of GRl, 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 (QA/QC) 

requirements are applicable to some of the count data generated by this project. Emission data 

and additional count data are from industry or literature sources, and are not subject to 

EP NORD's QAIQC policies. In all cases, data and results were reviewed by the panel of experts 

listed in Appendix D of Volume 2. 

11 
Title 

Contractor 

Principal 

Investigators 

Report Period 

Objective 

Technical 

Perspective 

RESEARCHSUNDdARY 

Methane Emissions from the Natural Gas Industry, 

Volume 2: Technical Report 

Final Report 

Radian International LLC 

GRI Contract Number 5091-251-2171 

EPA Contract Number 68-01-0031 

Matthew R. Harrison 

Lisa M. Campbell 

Terri M. Shires 

R. Michael Cowgill 

March 1991- June 1996 

Final Report 

Tbis report describes the results of a study to quantify the annual methane 

emissions from the natural gas industry. 

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

reducing the potential for global warming. During combustion, natural gas 

generates less carbon dioxide (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. Environmental 

Protection Agency's Office of Research and Development (EPAIORD) 

cofunded a major study to quantify methane emissions from U.S. natural gas 

operations for the 1992 base year. The purpose of this study was to provide 

emissions data that could be used to construct global methane budgets and to 

detennine the relative impact of natural gas on global warming versus the 

impact from coal and oil. 

Titis summary report is volume 2 of a multi-~olume set of reports that fully 

describe the project. 

Ill 
Results 

Technical 

Approach 

Project 

Implications 

is 

The 

equivalent 

national emissions for the base year are 314 ± 105 Bscf(± 33%), which 

program 

to 1.4 ± 0.5% of gross natural gas production. The overall 

also showed that the percentage of methane emitted for an 

incremental increase in natural gas sales would be significantly 

the baseline 

lower than 

case. 

processing 

On an industry segment basis, the production segment emits 84.4 Bscf, gas 

116.5 Bscf, 

plants emit 36.4 Bscf, transmission and storage facilities emit 

and distribution systems emit 77.0 Bscf. The report also shows 

that the largest type of methane emissions 

195.2 Bscffrom 

is fugitives, which accounts for 

all segments combined. 

methane 

The program 

emissions 

reached its accuracy goal and provides an accurate estimate of 

and 

that can be used to construct U.S. methane inventories 

analyze fuel switching strategies. 

The techniques used to determine methane emissions were developed 

representative of 

to be 

annual emissions from the natural gas industry. However, 

is impractical 

it 

to measure every source continuously 

emission 

for a year. Therefore, 

emission 

rates for various sources were determined by developing annual 

factors for sources in each industry segment and extrapolating 

data based on 

these 

national 

activity factors to develop a national estimate, where the 

factor. 

emission estimate is the product of the emission factor and activity 

industry 

The development of specific emission factors and activity factors for each 

segment are presented in a separate report. 

For 

U.S. 

the !992 base year the annual methane emissions estimate for the 

natural gas industry is 314 Bscf± 105 Bscf(± 33%). This is equivalent 

were 

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

natural 

used to compare greenhouse gas emissions from the fuel cycle for 

gas, oil, and coal using the global wanning potentials (GWPs) 

recently published by the Intergovernmental Pane! on Climate Change 

(IPCC). The analysis showed that natural gas contributes 

global wanning 

less to potential 

than coal or oil. which supports 

suggested 

the fuel switching strategy 

by the !PCC and others. 

In addition, results from this study are being used by the natural gas industry 

participating 

to reduce both operating costs and emissions. Some companies are also 

by EPA's Office 

in the Natural Gas-Star program, a vohmtary program sponsored 

of Air and Radiation 

Association 

in cooperation with the American Gas 

to implement cost-effective emission reductions and to report 

iv 
reductions to 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 

!.0 SUMMARY ............................................................ I 

2.0 INTRODUCTION ....................................................... 3 

3.0 METHODS ............................................................ 9 

3.1 Emission Source Characterization ..................................... 

3 .l.l General 

9 

Industry Description .................................. 

3. 1.2 Operating Mode 

9 

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

3.1.3 Emission Types 

17 

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

3.2 Emission Estimation Technique 

19 

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

3.2.1 Measurement Techniques 

20 

for Steady Emissions .................. 

3.2.2 Calculation Approach 

20 

for Unsteady Emissions .................. 

3.3 General Extrapolation Methodology 

23 

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

3.3.1 Sampling Approach 

24 

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

3.3.2 Redefining 

25 

the Emission Factor .............................. 

3.4 Accuracy ....................................................... 

26 

3.4.1 Precision 

27 

................................. · ................ 

3.4.2 Bias 

27 

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

3.5 Quality Assurance 

28 

and Quality Control Approach ....................... 

3.5.1 Overview 

28 

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

3.5.2 Definitions 

29 

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

3.5.3 Quality Control 

30 

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

3.5.4 Quality Assurance 

31 

......................................... 33 

4.0 DETAILED RESULTS .................................................. 37 

4.1 Emission Type Summary ........................................... 

42 Fugitive Emissions 

37 

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

4.2.1 Equipment Leaks 

39 

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

4.2.2 Underground 

41 

Pipelioe Leaks ................................. 

4.3 Vented Emissions 

50 

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

4.3.1 Pneumatic Devices 

52 

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

4.3.2 Blow and Purge 

52 

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

4.3.3 Dehydrator Glycol 

55 

Pumps ................................... 

4.3.4 Dehydrator Vents 

56 

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

4.3.5 Chemical 

57 

Injection Pumps ................................... 

4.4 Combusted Emissions 

58 

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

4.5 Largest Sources by 

59 

Industry Segment ................................. 61 

VI 
TABLE OF CONTENTS 

(continued) 

4.6 Equipment Emissions ............................................. 68 

4.7 Accuracy Results ................................................. 72 

5.0 ANALYSIS AND CONCLUSIONS ........................................ 74 

5.1 Impact ofNatural Gas Use on Global Warming ......................... 75 

5.2 Comparison to Previous Estimates ................................... 78 

5.3 Current and Future Industry Emissions ................................ 80 

5.3.1 Industry Practices to Reduce Methane Emissions ................. 80 

5.3 .2 Incremental Increases in System Throughput .................... 82 

5.4 Lessons Learned for Future Studies ................................... 83 

5.4.1 Sampling/Statistical Methods ................................. 83 

5.4.2 Measurement Methods ...................................... 86 

5.4.3 Significant Sources ......................................... 90 

6.0 REFERENCES ........................................................ 91 

APPENDIX A- Summary Table of Emissions Sources ....................... A-1 

APPENDIX B -Effect of Methane Emissions on Global Warming ............... B-1 

APPENDIX C - Conversion Table ........................................ C-1 

APPENDIX D - Project Reviewers . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . D-1 

v:r 
LIST OF FIGURES 

Page 

3-1 Gas Industry Flow Chart ................................................. II 

3-2 Gas Industry Boundaries ................................................. 14 

3-3 Transmission and Storage Stations ......................................... 16 

3-4 Distribution Segment Equipment ........................................... 18 

4-1 Emissions by Type ...................................................... 38 

4-2 Major Contributors to Fugitive Emissions from the Natural Gas Industry ........... 39 

4-3 Major Contributors to Fugitive Emissions-By Segment Facilities ................ 40 

4-4 Contributions to Vented Emissions ......................................... 52 

4-5 Summary of Methane Emissions ........................................... 61 

4-6 Production Segment Largest Sources ....................................... 64 

4-7 Gas Processing Segment Largest Sources .................................... 65 

4-8 Transmission and Storage Largest Sources ................................... 66 

4-9 Distribution Largest Sources .............................................. 67 

5-l Contribution of Major Methane Sources to Total U.S. Anthropogenic Emissions ..... 74 

B-I Breakeven Percentage-Natura! Gas Compared with Coal ..................... B-10 

viii 
LIST OF TABLES 

Page 

2-1 U.S. Gas Industry Methane Emissions Study Report List ......................... 5 

3-1 Industry Characterization ................................................. 12 

3-2 Emission Characterizations ............................................... 21 

4-1 United States Natural Gas Industry Largest Methane Emissions Sources ............ 38 

4-2 Example of National Emissions Estimation for Gas Storage Facilities ............. 43 

4-3 Summary of Methane Emissions ........................................... 61 

4-4 Emissions by Type ............................................. ·.· ....... 63 

4-5 Production Segment Largest Sources ....................................... 64 

4-6 Gas Processing Segment Largest Sources .................................... 65 

4-7 Transmission and Storage Segment Largest Sources ........................... 66 

4-8 Distribution Segment Largest Sources ....................................... 67 

4-9 Emissions by Equipment ................................................. 69 

4-10 Estimated Equipment Emission Factors ..................................... 71 

5-1 Equivalent C02 Emissions ................................................ 78 

B-1 Global Warming Potential of Methane ..................................... B-5 

B-2 Amount of C02 and Methane Remaining in Atmosphere with Time .............. B-7 

B-3 Breakeven Percentage (BP) for Coal and Oil for Various GWP Integration Intervals . B-9 

B-4 Incremental Changes in Emissions Resulting from Increased Gas Sales 

- Expected Gas ....................................................... B-12 

lX 
LIST OF TABLES 

(Continued) 

B-5 Incremental Changes in Emissions Resulting from Increased Gas Sales -

Page 

Upper Limit Case ..................................................... B-12 

B-6 Sources of C02 Equivalents for Each Fue!Type ............................. B-16 

B-7 C02 Equivalent Emissions from Natural Gas ............................... B-19 

B-8 C02 Equivalent Emissions from Coal ..................................... B-20 

B-9 1990 Methane and C02 Emissions 

Product 

from Crude Production Through Refined 

Transportation ................................................. B-2 I 

B-10 Properties of Fuel Oils ................................................. B-23 

B-11 C02 Equivalent Emissions from Fuel Oil .................................. B-24 

B-12 Equivalent C02 Emissions for Natural Gas, Oil, and Coal ..................... B-24 

X 
1.0 SUMMARY 

This report summarizes the results of a project sponsored by Gas Research 

Institute (GRl) and U.S. Environmental Protection Agency's Office of Research and 

Development (EPA/ORD) to quantify methane emissions from the natural gas industty. The 

project was initiated to evaluate whether the suggested strategy of increasing the use of natural 

gas to reduce global warming was valid in light of methane emitted from the industry. It also had 

the purpose of determining the gas industry's contribution of methane to the global inventory of 

greenhouse gas emissions. 

During combustion, natural gas generates less carbon dioxide (C02) 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, GRI and EPA/ORD cofunded a major study to quantify 

methane emissions from U.S. natural gas operations for the 1992 base year. The results of this 

study can be used to construct global methane budgets and to detennine the relative impact on 

global warming of natural gas versus coal and oil. 

For the 1992 base year the annual methane emissions estimate for the U.S. natural 

gas industry is 314 Bscf ± 105 Bscf(± 33%)." This is equivalent to 1.4% ± 0.5% of 1992 gross 

natural gas production. The project reached it accuracy goal of determining emissions within 

± 0.5% of production, and provides an accurate methane emissions estimate that can be used in 

fuel switching analyses. The program also showed that the percentage of methane emitted for an 

"Readers more comfortable with metric units will find a conversion table in Appendix CI 
incremental increase in natural gas production would be significantly lower than the baseline 

case. 

Results from this program were used to compare greenhouse gas emissions from 

the fuel cycle for ~atural gas, oil, and coal using the global warming potentials (GWPs) recently 

published by the Intergovernmental Panel on Climate Change (IPCC). 1 The analysis showed that 

natural gas contributes less to potential global wanning than coal or oil, which supports the fuel 

switching strategy suggested by the IPCC and others. Even across a wide range of assumptions 

on factors affecting the global wannir.g potentials, natural gas production and use in the United 

States contributes less to global warming than coal or oil. 

The results are currently being used by the natural gas industry to reduce 

operating costs while reducing emissions. This has led to the development of a voluntary 

program, the Gas-Star program, sponsored by EPA in cooperation with the American Gas 

Association (A.G.A.).' As part of this voluntary program, participating companies implement 

cost-effective emission reductions and report the reductions to EPA. 

2 
2.0 INTRODUCTION 

The increased use of natural gas has been suggested by IPCC and EPA as a 

strategy for reducing global wanning.L3 During combustion, natural gas generates less carbon 

dioxide (C02) per unit of energy produced than either coal or oil. On the basis of the ammmt of 

C02 emitted, global wanning could be reduced by substituting natural gas for coal. However, 

since natural gas is primarily methane, a poten! greenhouse gas, losses of natural gas during 

production, transmission, and distribution could reduce the inherent advantage of its lower C02 

emissions. For this reason, GRI and EPA jointly funded and managed a program to estimate 

methane emissions from the U.S. natural gas industry for the 1992 base year. The objective of 

this comprehensive program was to quantify methane emissions from the gas industry starting at 

the wellhead and ending immediately dovmstream of the customer's meter. The accuracy goal of 

the project was to determine these emissions to within 0.5% of natural gas production based on a 

90% level of confidence. This is equivalent to an accuracy goal of ±Ill billion standard cubic 

feet (Bscf) per year for the 1992 base year. 

The methane emissions program was conducted in three phases: scopmg, 

methods development, and implementation phase. During the scoping phase of the program, the 

methane emissions from each source in the gas industry were quantified on the basis of available 

data and engineering judgement. These initial estimates were used to set priorities for data 

collection according to the relative importance of their contribution to emissions or the 

Wlcertainty in emissions. 

In the second phase of the program, methods were developed to measure and/or 

calculate methane emissions from the variety of sources that make up the gas industry. These 

methods were validated through tests designed to quantify the accuracy of the measurement 

approach (i.e., proof of concept tests), and through industry review of the analytical methods. 

However, emissions could not be measured or calculated from each piece of equipment (e.g., 

every glycol dehydrator, compressor engine, etc.) in the industry because of the vast amount of 

3 
equipment. Therefore, a major task in the second phase was to develop defensible techniques for 

extrapolating a limited amount of data collected for each source category to other sotrrees in the 

category in order to develop a national emissions estimate. 

The tlli:d phase of the program focused on collecting data needed to define 

emissions from all sources and extrapolating these data to estimate nationwide methane 

emissions. Data collection in the third phase of the program concentrated on hlgh priority 

sources (i.e., sources with large emissions and/or large uncertainties). An Advisory Committee 

consisting of industry representatives, project sponsors, and other interested parties including 

scientists, government policy analysts, and environmentalists provided guidance and peer review 

for all phases of the program. In addition, Gas Industry Review Panels for each segment of the 

gas industry provided more detailed technical review of the project to ensure that the 

methodologies and assumptions used in the stUdy were consistent with industry practices. 

The final analysis of the data and the methodologies used in the program have 

been documented in a series of31 reports. Table 2~1 shows the report name, report volume 

number, report reference number, and the author of each report. The first 15 reports present final 

data and analysis, and these reports have been assigned volume numbers. The first 15 reports are 

available through the National Technical Information Service (NTIS) or from GRI. The 

remaining reports represent field data, proof of concept tests, and efforts cofunded by others, and 

have not been assigned volume numbers. These reports are listed here only as references, and 

must be ordered from the listed author by the reference number. 

The first five volumes present the executive summary, the technical report, the 

general methodology, the statistical methodology, and the activity factors. These first five 

volumes are the most important source of overall information on the project. Volumes 6 through 

15 present the details of the test program and calculation procedures for determining specific 

emission and activity factors. 

4 
TABLE 2-1. U.S. GAS INDUSTRY METHANE EMISSIONS STUDY REPORT LIST 

Report Name Report Number or Authors/ 

Reference Contractor --

Methane 

------------ ----------------- - ------ "----·---·-------··------- ----------···- -- -------- -·---- -

Emissions from the Natural Gas Industry, Volume 1: Executive Summary 4 

Methane Emissions from the Natural Gas Industry, Volume 2: Teclmical Report 

------------- - --

GRJ-94/0257 

EPA-600/R-96-080a 

GRI-94/0257.1 

EPA-600/R-96-080b 

M.R. Harrison 

eta!. 

M.R. Harrison 

et al. 

Methane Emissions from the Natural Gas Industry, Volume 3: General Methodology 5 GRI-94/0257.20 M.R. Harrison 

EPA-600/R-96-080c ---+------- eta!. - -· ---- --- - ---- --- ---- - - - -------

Methane Emissions from the Natural Gas Industry, Volume 4: Statistical Methodology 6 GRI-94/0257.21 

- ---- - ------- ---

Methane Emissions from the Natural Gas Industry, Volume 5: Activity Factors 7 

EPA-600/R -96-080d 

GRJ-94/0257.22 

EPA-600/R-96-080e 

Methane Emissions from the Natural Gas Industry, Volume 6: Vented and Combustion GRJ-94/0257.23 

Source Summary 8 

EPA-600/R-96-080f 

Methane Emissions from the Natural Gas Industry, Volume 7: Blow and Purge 

Activities 9 

Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks 10 

---·--

Methane Emissions from the Natural Gas Industry, Volume 9: Underground 

Pipelines JI 

Methane Emissions from the Natural Gas Industry, Volume 10: Metering and Prel!sure 

__ 1_3.-e_gu_l31ting Sta!~o~~~!l N~t~r~l gas Tran~!lli~~iol! ~~1~_ Distribut_io~ ~--- ____ _ 

Methane Emissions from the Natural Gas Industry, Volume I I: Compressor Driver 

Exhaust 13 

GRI-94/0257.24 

EP~-600/R:96-080g 

GRI-94/0257.25 

EPA-600/R-96-080h 

GR!-94/0257.26 

EPA-600/R -96-080i 

GRI-94/0257.27 

EP A-6_00/R -96-080j 

GRI-94/0257.28 

EPA -600/R -96-080k 

ILJ. Williamson 

et al. 

B.E. Stapper 

T.M. Shires and 

M.R. Harrison 

T.M. Shires and 

M.R. Harrison 

K.E. Hummel 

et al. 

L.M. Campbell 

et al. 

L.M. Campbell 

and B.Ec Sta_llper 

C.J. Stapper 

(Continued) 
TABLE 2-1. U.S. GAS INDUSTRY METHANE EMISSIONS STUDY REPORT LIST 

(Continued) 

Report Name 

Methane Emissions from the Natural Gas Industry, Volume 12: Pneumatic Devices 14 

Pumps

Methane Emissions from the Natural Gas Industry, Volume 13: Chemical Injection 15 

___________________________________ --~~----

Report Number or 

Reference 

GRI-94/0257.29 

EPA-600/R -96-0801 

GRI-94/0257.30 

EPA-600/R -96-080m 

Authors/ 

Contractor 

T.M. Shires and 

M.R. Harrison 

T.M. Shires 

Methane Emissions from the Natural Gas Industry, Volume 14: Glycol GRJ-94/0257.31 D. Myers 

_De_~ydr~_tor~~-- ____ ---------------~~-- ___________________ 

Methane 

---~~ 

Emissions 

Pumps 

from the Natural Gas Industry, Volume 15: Gas-Assisted Glycol 17 

Jhr~~-p~~n 

An Engineering 

~ 

Estimate 

~od~l~atura~ 

of the Incremental Change in Methane Emissions with Increasing 

Ga~ Syst~~ 1

_

8 _ 

EPA-600/R -96-080n 

GRI-94/0257.33 

EPA-600/R -96-080o 

GRJ-94/0257.32 

Results of Tracer Measurements 

- --~--

of Methane Emissions 

Facilities, Final Report 

from Natural Gas System GRI-94/0257.43 19 

Evaluation of Methane Emissions 

Methodologies 

from Natural Gas Production Operations Using Tracer 20 

Fugitive Hydrocarbon Emissions from Oil and Gas Production Operations21 

GRI-92/0102 

API4589 

Fugitive Hydrocarbon Emission: Eastern Gas Wells (Final Reportf2 

GRI-95/0II? 

D. Myers and 

M.R. Harrison 

Columbia Gas 

Aerodyne, 

Washington State 

University, 

University of New 

~famp_s~ire _ _ __ 

SRl International 

STAR 

Environmental 

STAR 

Environmental 
TABLE 2-1. U. S. GAS INDUSTRY METHANE EMISSIONS STUDY REPORT LIST 

(Continued) 

Report Name 

Leak Rate Measurements for Natural Gas Customer Meters (Draft)n 

Leak Rate Measurements at U.S. Natural Gas Transmission Compressor Stations (Draft)24 

Emission Factors for Oil and Gas Production Operations25 

Report Number or Authors/ 

-- Reference Contractor --- .. ----f---

GRI-94/0257.36 lndaco Air Quality 

GRI-94/0257.37 

--

API 4615 

Services 

Indaco Air Quality 

Services 

----- -----+---------

STAR 

Environmental 

Fugitive Methane Emissions: Customer Meter Sets (Final Reportf6 GRI-95/0204 

Phase 3 Program Plan- Implementation Plan 27 

Mass Balance of a Natural Gas Transmission System for Improved Estimates of Methane 

Emissions 28 

---- -- Soil Consumption of Methane from Natural Gas Pipeline Leaks29 

Sampler Enables Measurement of Leaks on Site-Specific Basis 30 

RadianDCN 

92-263-081-02 

SwRI 04-4447 

GRI-94/0257.35 

---

American Oi I and 

Gas Reporter, 

March 1995 

STAR 

Environmental 

Radian 

Corporation 

Southwest 

Research Institute 

Aerodyne, 

Washington State 

University, 

University of New 

Hampshire 

Lott, Webb, 

Howard 
This technical report is organized as follows: Section 2 presents background 

information; Section 3 provides an overview of the methodologies developed and followed in the 

study which includes methods for characterizing the industry, measuring and calculating 

emission factors, collecting activity factor data (equipment and component counts), and 

extrapolating the data to derive an annuai. methane emissions estimate for the U.S. natural gas 

industry. Section 4 provides summaries of the largest methane emission sources. Section 5 

provides an overview of the major conclusions drawn from the study. 

8 
3.0 METHODS 

This section characterizes the natural gas industry and describes in general terms 

the methods used to define and extrapolate err.issions for all source types or categories that 

comprise the industry. 

3.1 Emission Source Characterization 

The first step for estimating methane emissions from the U.S. natural gas industry 

is to identify and characterize each emission source within the industry, so that all significant 

sources are included. To fully characterize the industry. sources were defined by equipment 

type, mode of operation, and type of emissions. 

"While this section draws a general picture of the industry, it is not intended to be a 

definitive picture of any company or of the industry regarding specific operational practices and 

procedures. Rather, it is intended to define the general industry equipment practices and 

procedures used in 1992, the base year of the p:-ogram, that could lead to measurable emissions 

of methane. Details that were useful for detennining methane emissions are contained in specific 

reports (see Table 2-1). 

3.1.1 General Industry Description 

The natural gas industry uses wells to produce natural gas existing in underground 

formations, then processes, compresses, and trar1sports the gas to the customer. Transportation 

and distribution of natural gas involve interstate and intrastate pipeline transportation, storage, 

and fmally distribution of the gas by local distribution pipeline networks. 

9 
The generally accepted segments of the natural gas industry are: 

!) Production 

2) Processing 

3) Transmission/storage 

4) Distribution 

Each of these segments is shown in the flow chart for the industry in Figure 3-1. Some of the 

major equipment in each segment is s:town in Table 3-1. Each segment is described in more 

detail in the following subsections. 

This project set specific boundaries for each segment of the industry that specify 

what equipment is included in the study. The guideline used for setting the boundaries was to 

include only the equipment in each segment that is required for marketing natural gas. For 

example, oil production equipment is excluded if it is used to produce oil and not natural gas. 

Similarly, gas processing equipment associated with the fractionation of propane, butane, and 

natural gas liquids are excluded from consideration. In distribution, all equipment up to and 

including the customer's meter are included. End-user emissions are not included in this 

estimate. 

Each industry segment is described in more detail in the following subsections: 

Production Segment Description 

The production segment is comprised of gas and oil wells and the surface 

equipment required to produce gas. The well includes the holes drilled through subsurface rock 

to reach the producing formation and the subsurface equipment such as casing and tubing pipe. 

Gas and oil surface equipment can include separators, heaters, heater-treaters, tanks, dehydrators, 

compressors, pumps, and pipelines. 

10 
PRODUCTION 

Surface Facilities 

Liquids 

PROCESSING 

Liquids 

TRANSMISSION/ 

STORAGE 

I 

I 

I 

I 

I 

Direct 1 

Compressor 

Stations 

Sales 1 

DISTRIBUTION 

Main and 

Service Pipelines 

I 

I 

I 

.-~c~~~~~~--~~~~f~~~~~ Pipelines I 

I 

I 

I 

I 

I 

I 

L-J c l-----r-~~l~i ~_i~--~~a-~ IH~+---4M 

Storage 

Underground 

Storage 

Reservoir 

Customer Meters 

IIJ Compressor 

@ Meter 

Q Pressure 

1>'<1 Regulator 

Figure 3-1. Gas Industry Flow Chart 
Segment 

Production 

Processing 

Transmission 

Storage 

Distribution 

TABLE 3-1. INDUSTRY CHARACTERIZATION 

·Facilities 

1 

Well Sites, 

Central Gathering Facilities 

' 

1 Gas Plants 

i Transmission Pipeline Networks, 

I Compressor Stations, 

, Meter and Pressure Regulating Stations 

I 

, Underground Injection/Withdrawal 

' 

' 

i Facilities, and Liquefied Natural Gas 

' (LNG) Facilities 

' 

i Main and Service Pipeline Networks, 

' 

: Meter and Pressure Regulating Stations ' 

12 

I Equipment at the Facility 

I 

· Wellheads, Separators, 

Pneumatic Devices, Chemical 

Injection Pumps, Dehydrators, 

Compressors, Heaters, Meters, 

Pipelines 

Vessels, Dehydrators, 

\ Compressors, Acid Gas 

I Removal (AGR) Units, Heaters, 

1 Pneumatic Devices 

~Vessels, Compressors, Pipelines, 

\ Meters/Pressure Regulators, 

i Pneumatic Devices 

i 

) Wellheads, Vessels, 

j Compressors, Dehydrators, 

. Heaters, Pneumatic Devices 

; Pipelines, Meters and Pressure 

I Regulators, Pneumatic Devices, 

: Customer Meters 
The definition for gas industry production equipment excludes equipment 

associated with oil production. Also, unmarketed natural gas, such as that produced by oil wells 

that vent gas or that reinject gas for gas lift circulation only, are not considered part of the natural 

gas industry. Figure 3-2 shows the general equipment found in the oil and gas production 

segment, as well as the boundaries between gas and oil production equipment used by this study. 

The boundary between oil and gas equipment shov.n in Figure 3-2 affects the gas 

industry emissions estimate since it excludes some high emission rate production equipment 

associated with oil production. An accounting oftotal production segment emissions, or just oil 

industry emissions, 'Wi11 have to include the oil industry equipment excluded from this study 

(such as some pnewnatics, some chemical injection pumps, and oil tanks). 

Gas Processing Segment Description 

Natural gas processing plants recover high value liquid products from the gas 

stream and maintain the quality (i.e., content and heating value) of the gas stream. The liquid 

products include natural gasoline, butane, propane, and in some cases, ethane. The products are 

removed by compression and cooling or by absorption. 

A gas plant may have fractionation towers and stabilization towers to further 

purify the individual components of the product stream. The back end of the gas plant, such as 

the fractionation train, is excluded from the gas industry defmition since its function is to purify 

and market liquid products. Also, the back end of the gas plant has negligible methane emissions 

since the liquids handled have little methane content. 

The front end of the gas plant often contains dehydration facilities, wet gas 

compression, and the absorption or compression and refrigeration process. All natural gas 

processing plants are considered part of the natural gas industry, and methane emissions from 

these facilities are included in this study. 

!3 
-

0 

-

"' 

-

"' :: 

OH Wd> ,--A r::::=t 

Wellhead ! L__.l l__J 

~ Compressor 

Oil Well 

w~Jlhe•d r--------, (producing 

gas} 

Coal Bed 

Methane Well 

Gas Well 

Wellbe•d 

Petrokum Industry 

,.... ---- -rCOI!lj)ft$SOf 

------

Sa!rWattt 

T~k 

~ 

~ 

~ Vapor Recovery 

Comp"'ssor 

Pe1rokum Industry 

Figure 3-2. Gas Industry Boundaries 

14 
Transmission and Storage Segment Description 

The transmission segment moves the natural gas from the gas plant or directly 

from field production to local distribution companies (LDCs). Gas is often transported across 

many states, such as from the Gulf Coast to the Eastern seaboard of the United States. The 

transmission segment consists of large diameter pipeline, compressor stations, and metering 

facilities. All of these facilities and all of the equipment they contain are considered part of the 

natural gas industry. 

Transmission compressor stations usually consist of piping manifolds, 

reciprocating engines or gas turbines, reciprocating or centrifugal compressors, and generators, 

as shown in Figure 3-3. Dehydrators may be included but are not typically present because of 

upstream gas drying. Some transmission compressor stations may also include metering 

facilities. 

Transmission companies also have metering and regulating stations (M&PR) 

where they exchange gas with other transmission companies, or where they deliver gas to LDCs 

or industrial customers. These stations may contain heaters, small dehydrators, and odorant 

addition equipment. 

Most storage facilities exist to store natural gas produced during off-peak times 

(usually summer) so that gas can be produced and delivered during peak demand. Storage 

facilities are often located close to consumption centers so that cross-country transmission 

pipelines do not have to be sized for peak demand. Storage facilities can be below or above· 

ground. Above-ground facilities are liquefied natural gas (LNG) facilities that liquefY the gas by 

supercooling and then storing the liquid phase methane in above ground, heavily insulated 

storage tanks. Below-grotmd facilities compress and store the gas (in vapor phase) in one of 

several fonnations: I) spent gas production fields, 2) aquifers,·or 3) salt caverns. Below-ground 

storage is the predominant means of gas storage. 

!5 
Gas 

from 

Pipeline 

TRANSMISSION ABOVE GROUND STORAGE 

COMPRESSOR STATION 

g Cooling 

Compressors ~ LNG Process Tank 

c 

Heaters I 

c 

Gas Transmission Pipeline 

c from 

Pipeline 

BELOW GROUND STORAGE 

c 

Compressor 

c 

~.~.~ Station 

Wells 

Dehydrator ~ ~ ~ Storage Field 

Figure 3-3. Transmission and Storage Stations 
Most storage stations consist of a compressor station that is very similar to a 

transmission compression station (see Figure 3-3). UndergroWld storage facilities also have 

storage field wells, and usually have dehydrators to remove water absorbed by the gas while 

Wlderground. All storage equipment is included in boundaries of the natural gas industry defined 

by this project. 

Distribution Segment Definition 

The distribution segment receives high pressure gas from transmission pipelines, 

reduces the pressure, and delivers the gas to residential, commercial, and industrial consumers. 

Tills segment includes pipelines (mains and services), M&PR stations and customer meters. All 

of these facilities are considered to be an integral part of the gas industry. Figure 3-4 shows a 

schematic of the distribution segment and the equipment that it includes. 

3.1.2 Operating Mode 

After identifying the major equipment (source types) in each industry segment, 

emissions from each source were identified by examining the operating modes of the equipment 

that may lead to emissions, and by associating one of three possible types of emissions from the 

source: fugitive emissions, vented emissions, or combustion emissions. 

The cause of emissions is directly related to the operating mode of the equipment. 

Since more than one cause of emissions can be associated with a particular piece of equipment, it 

is important to identify the various operating modes in order to identify all emissions. In general, 

the operating modes are: 

• Start-up; 

• Normal operations; 

• Maintenance; 

• Upsets; and 

• Mishaps. 

17 
Regulating (M&PR) Station Pressure-Reducing 

Station 

Meter and Pressure 

Main~ (Pipeline) 

~ 

!'?. 

-""" 

-00 

M 

Transmission @ 

Pipeline ""' Meter 

Pressure-Reducing 

Regulators 

Figure 3-4- Distribution Segment Equipment 

Services (Small Pipe) M 

~ 

""' 

M 

M 

-® 

M 

! 

""' Customer Meters 

(Residential, 

Commercia!, 

Industrial, 

Electric Utility) 
Start-up operations, such as purging a newly constructed plant or pipeline, can 

involve purging natural gas directly to the atmosphere. Emissions associated with normal 

operations include emissions from process vents, fugitive emissions from packed or sealed 

surfaces or undergrmmd pipeline leaks, and emissions from gas-operated pneumatic devices. 

Maintenance operations involve blowing down equipment, such as compressors, pipelines, or 

vessels, before equipment maintenance. Process upsets usually involve releasing natural gas to 

the atmosphere or to a combustion device, such as a flare, as the result of overpressure or 

emergency shutdown conditions. Mishaps are intended to include accidental occurrences that 

result in emissions, such as third-party damage to pipelines (dig-ins). 

3.13 Emission Types 

Emissions from each piece of equipment in the natural gas industry can be 

classified in one of three general emission types: I) fugitive emissions; 2) vented emissions; and 

3) combustion emissions. Fugitive emissions a:e unintentional leaks emitted from sealed 

surfaces, such as packings and gaskets, or leaks from underground pipelines (resulting from 

corrosion, faulty connections, etc.). Vented emissions are releases to the atmosphere by design 

or operational practice. Examples of vented emissions include emissions from continuous 

process vents, such as dehydrator reboiler vents; maintenance practices, such as blowdowns; and 

small individual sources, such as gas-operated pneumatic device vents. Combustion emissions 

are exhaust emissions from combustion sources such as compressor engines, burners, and flares. 

In summary, the facilities and equipment comprising each segment of the industry 

were identified. Each source (i.e., piece of equipment) was then examined for different 

emissions during different operating modes. Emissions from each source were also categorized 

as either combustion, vented, or fugitive. Equipment, such as compressors, might emit gas nnder 

all three categories (fugitive emissions when pressurized, vented emissions when blovm down 

for maintenance, and combustion emissions during normal operations). 

19 
3.2 Emission Estimation Technique 

After all potential sources of methane emissions in the industry were identified 

and characterized, the annual emissions were estimated. Because it would be impractical to 

measure emissions all year for every source, it is important that a measurement be representative 

of the annual emissions. Some emissions from natural gas industry sources are continuous and 

nearly "steady" and a single measurement is representative of annual emissions. ("Steady" is a 

relative tenn and to some extent is dependent on the time period of data needed for the study. 

For this study, the annual value of methane emissions is needed.) The measurement techniques 

used in this study depended on the variability of the emission rate with time. 

Emissions that are intennittent are considered "unsteady" and have variable 

emission rates during a year. Because it would not be practical to collect data continuously for a 

year for each source, emissions from these sources were calculated rather than measured. Table 

3-2 shows examples of emission sources characterized by operating mode emission type and 

whether the emissions are steady or unsteady. 

3.2.1 Measurement Techniques for Steady Emissions 

Steady emissions result from unintentional leaks from sealed surfaces such as pipe 

connectors, valve packing, flange gaskets at surface facilities, and from components and sma11 

holes in below-ground equipment (i.e., pipelines). One method for measuring these steady 

fugitive emissions from above-ground facilities (surface production equipment, gas plants, 

compressor stations, etc.) is to measure emissions from individual components, and then sum all 

the component emissions for the facility. Other surface facility methods include the tracer gas 

method. Measuring emissions from buried pipelines is done through a leak statistics method. 

Each of these methods is described in the following subsections. 

20 
Emission 

Type 

Fugitive 

Vented 

Combusted 

TABLE 3-2. EMISSION CHARACTERIZATIONS 

Specific Source Examples 

Packed or Sealed Surfaces 

I 

Operating Mode ' 

~ 

I 

Normal Operations 

Steady or 

Unsteady 

Steady 

Leaks (holes in gathering & distribution Normal Operations Steady 

pipes) 

[ Leaks (holes in transmission pipes) '· Normal Operations I Steady 

Dehydrator Vents : N annal Operations Steady 

I Pipeline Purge/Blowdown ! Maintenance Unsteady 

' · Pneumatic Devices 1 Normal Operations Unsteady 

Equipment Blowdown 

I Normal Operations 

I 

I Unsteady 

i Maintenance :Unsteady ' 

~ Compressor Starts 

Chemical Injection Pump Vents . Normal Operations Unsteady 

I 

I Upsets Unsteady 

·1 Normal Operations, :Unsteady 

Pressure Relief Valve Lift 

I 

I Compressor Driver Exhaust 

. Flaring \ Upsets/Maintenance ' Unsteady 

I 

Burners 1 

Nonnal Operations . Unsteady 

Component Measurement Methods 

One method for determining fugitive emissions from above-ground facilities is to 

determine emissions from basic components such as valves, flanges, seals, and other connectors 

and then sum these for a given facility to detennine total emissions. As part of this program, 

GRI cofunded studies with API and others to update emission factors for pipe fittings and other 

components used in oil and gas production. 21 .22.23.24

.25

.26 Nearly 200,000 components were 

screened at 33 facilities throughout the country. The approach was to measure emissions from a 

large nwnber of randomly selected components and to determine the average emission rate (i.e., 

21 
emission factor) for each type of component. After the components were screened to determine 

if they were leaking, the average emission rate was measured using one of several test methods: 

• 

measures 

A high flow organic vapor analyzer that captures the entire leak and 

detennined 

the methane concentration and flow rate. The emission rate is 

method 

from the product of the concentration and flow rate. This 

provide 

was developed as part of this natural gas industry program to 

a more accurate and cost-effective 

methane 

technique for measuring a 

emission rate directly. 

• A total enclosure technique called bagging. Uncontaminated air is blown 

through an enclosure surrounding the component; 

concentration 

the flow rate and outlet 

are then measured. The leak rate is detennined 

product 

from the 

of the concentration and flow rate. 

• A screening technique in which the methane concentration 

passing 

is measured by 

concentration 

a standard organic vapor analyzer around the sealed surface. The 

relates bagged 

is related to an emission rate by a correlation equation that 

emissions to measured screening values. 

Tracer Gas Method 

The tracer gas method of measuring methane emjssions consists of releasing 

tracer gas (at a known constant rate) near the emission source and measuring the downwind 

concentrations of tracer and methane. Assuming complete mixing of the methane and tracer gas, 

and assuming identical dispersion, the ratio of the downwind concentrations is equal to the ratio 

of the release rates. Based upon the do\vnw:ind concentrations of methane and tracer gas and the 

known release rate of the tracer, the emission rate of methane can then be determined. This 

method was used primarily to measure emissions from M&PR stations.l2

·

19 

22 
Leak Statistics Method 

The leak statistics method is used to quantifY methane emissions from 

underground main and service pipelines. 11 Emission rates are measured for a large nwnber of 

leaks to accurately determine the average emission rate per leak as a function of pipe material, 

age, pressure, and soil characteristics. The measurement program was conducted as a 

cooperative effort between EPAIGRJ and industry. The industry participants used specially 

designed equipment to measure leak rates from underground distribution mains and services. In 

the procedure, a pipe segment containing the leak is isolated, the isolated segment repressurized, 

and the volumetric flow required to maintain nonnal oper3.ting pressure in the isolated segment is 

equal to the leak rate. Historical leak records are analyzed to determine the number ofleak.s per 

mile for different pipe materials. Total emissions are determined by multiplying the average leak 

rate per leak by the estimated total nwnber of leaks in the distribution segment. 

3.2.2 Calculation Approach for Unsteady Emissions 

For some methane emission sources, such as releases during maintenance, 

detailed company records are available for multiple years. However, many other sources of 

unsteady emissions are not tracked by companies and, therefore, must be calculated. 

Each unsteady source of emissions requires data gathering and a unique set of 

equations to quantify the average annual emissions. In general, all unsteady sources of emissions 

require the following infonnation to quantif)r annual emissions: 

• Detailed technical characterization of the source and identification of the 

important parameters affecting emissions. (1bis information is 

docwnented for individual source types in the reports for each major 

source category.) 

• Data from multiple sites that allow the methane emitted per emission event 

to be calculated from the governing equations. 

23 
• Data on the frequency of releases. 

The estimate of emissions from a vessel blowdown for routine maintenance is an 

example of emissions calculated for an unsteady source . In this case, the volume, pressure, and 

temperature of gas contained in the vessel before blowdown is used to calculate losses from a 

blowdown event. Additionally, an average frequency of these vessel blowdown events is 

necessary to detennine the annual loss. 

In some cases, emissions per event from some unsteady sources were measured. 

These emissions data were combined with site data collected in this study to quantity the annual 

emissions from these sources. Examples of sources where emission measurements per event 

were used include emissions from compressor driver exhaust, gas-operated pneumatic devices, 

glycol dehydrator regenerator overhead vents, and gas-operated chemical injection pwnps. 

3.3 General Extrapolation Method<!logy 

By necessity, data in this project were collected for a relatively small percentage 

of sources in each source category. Therefore, these data had to be extrapolated to develop 

national estimates for each source category. The extrapolation techniques for creating national 

emission estimates were developed so that the emissions from each source could be estimated 

with a relatively high level of precision (given the nature of this study) and negligible bias. (See 

Section 3.4 for definitions of precision and bias.) 

The extrapolation approach is a method to scale-up the average emissions from a 

limited number of sources to represent the entire population of similar sources in the gas 

industry. The extrapolation approach uses the concept of emission and activity factors to 

estimate emissions based on a limited number of samples. These factors are defmed in such a 

way that the product of emission and activity factors equals the annual national emissions from 

the source category. 

24 
Emission Factor x Activity Factor = National Emissions 

Typically, the emission factor (EF) for a source represents the average emissions 

rate per source and the activity factor ( AF) represents the total industry population of the source 

category. 

3.3.1 Sampling Approach 

Even if the overall precision of an estimate is acceptable because the variability in 

the data is relatively low, the overall accuracy may still be poor if the data are biased. Several 

approaches can be applied to avoid bias. 

Because of various practical limitations, neither random sampling nor stratified 

random sampling was feasible in this study. For this reason, an alternate approach was used. 

\Vhile this approach is not a textbook sampling method, it is believed to be very effective for the 

specific needs of this project. This approach is similar to disproportionate stratified random 

sampling, with certain differences. These conventional sampling techniques and the reason why 

they were not applicable in this project are discussed in Volwne4 on statistical rnethodology.6 

Initially, some data were collected to determine if a given source was a major 

contributor to methane emissions. For each source category, an initial estimate of the number of 

data points needed was calculated based on an estimate of the target precision and the estimated 

standard deviation for the source category. The accuracy targets for precision are based on the 

need to estimate the 1992 national emissions to within 0.5% of U.S. natural gas production with 

a 90% confidence limit. Sites were selected in a random fashion from known lists of facilities, 

such as GRI or A.G.A. member companies. However, the companies contacted were not 

required to participate, and a complete list of all sources in the United States was generally not 

available. Therefore, the final set of companies selected for sampling was not truly random. 

Each company that agreed to participate in the program was asked to select representative sites 

for sampling, rather than one-of-a-kind facilities. 

25 
After a limited set of data was collected, the data were screened for bias by 

evaluating the relationship between emission rate and parameters that may affect emissions. It is 

important to realize that just because a parameter or set of strata is identified that has a large 

effect on emissions from a given source category, 

A 

it does not mean that there is bias in the data. 

second condition 

disproportionate 

is necessary, namely, that the sampling procedure would have to produce a 

number of samples in the strata. To determine whether this has occurred, 

infonnation is needed on the ratio of the total number of sources in a given stratum to the total 

number of sources throughout the country. If thls ratio is different from the corresponding ratio 

for the sample data set, then there may be bias. But this bias can be eliminated by applying the 

correct emission factors and activity factors for the different strata. 

Once the strata are identified, the precision of the emission rate extrapolated 

national 

to a 

basis was evaluated and compared to the accuracy target. Where necessary, additional 

data were collected in various strata to improve the precision of the national estimate of 

emissions from the source. The nwnber of additional data points needed to meet the newly 

calculated accuracy target was computed based on the standard deviation and a 90% confidence 

interval. 

In some cases, variability of the emissions data from source to source is very 

large. For source types of this nature, it is·norma11y possible to reduce variability by redefining 

the emission factor or by stratification. This is important because reducing variability reduces 

the number of data points needed to achieve the accuracy target. 

3.3.2 Redefining the Emission Factor 

emission 

For a few types of sources, emissions can be more accurately estimated when the 

factor is defined not as a simple average of the data but is expressed 

parameter 

in terms of a key 

that influences the emissions from the source. Since this would significantly reduce 

the variability, fewer data points are required to achieve the desired level of accuracy. For 

example, the internal combustion engines that drive compressors in the gas industry vary in size 

26 
(i.e., horsepower rating). If data were collected on individual engines in the industry, and an 

average emission rate per engine was established, the variability from engine to engine would be 

very large because of size differences. However, if the emission factor for the engines is defined 

by horsepower of the engine (i.e., annual emissions per horsepower), then the variability from 

engine to engine and therefore the number of samples required to reach an acceptable accuracy 

are both significantly reduced. 

As discussed previously, the number of data points required also may be reduced 

by stratifying on the basis of parameters that affect emissions. A source type can be stratified 

into categories with different emission characteristics; the objective is to produce strata with 

much less variability than the total data set. The sampling is performed within the strata and 

because the variability within the strata is smaller, fewer total data points are require~ to achieve 

target precision. 

3.4 Accuracy 

A key part of this project is the estimation of the accuracy of the annual national 

enusstons. Accuracy is dependent on precision and bias, as discussed in Volume 4 on statistical 

methodology.6 Precision, the random variability in the measurement, is calculated rigorously by 

propagating error from each individual group of measurements into the final numbers. However, 

bias, a systematic error in the measurements must be prevented or discovered and eliminated, 

rather than identified and calculated. 

3.4.1 Precision 

Most source activity factors and emission factors are made up of an average of 

multiple measurements or calculations. Therefore, assuming a nonnal distribution around a 

mean and error independence, standard deviations and 90% confidence limits can be calculated 

directly for each group of measurements in an activity or emission factor. 

27 
The confidence intervals or error bounds can be propagated through the addition 

of multiple emission source estinlates to arrive at a confidence bound for the national emission 

estimate. These generally accepted statistical techniques are described in detail in the statistical 

methods report cited previously. 

3.4.2 Bias 

It is impossible to prove that there is no bias in any data set. While tests can be 

designed that are capable of revealing some bias, there are no tests nor group of tests that wi!l 

reveal all possible biases. Assuming that a data set has no bias is only a hypothesis, even after 

extensive testing. Such hypotheses can be disproved, but not absolutely proven. However, the 

data collected during this project were extensively checked and rechecked to identifY and then 

eliminate biases. Three basic methods were used to screen for bias: peer review by experts, 

subdivision of the data into strata,. and extrapolation by different parameters. Some of these 

techniques were discussed previously in Section 3.3. 

Data sets were tested repeatedly through extensive technical and industrial review. 

Numerous project advisor's meetings were held during the course of the study to examine the 

data "With industry representatives and other experts so that systematic errors could be identified 

and eliminated. When biases in the sampling plan or extrapolation method were postulated, the 

project was altered to test for that bias and eliminate it if it existed. One example of the success 

of this review process is the identification of regional differences in production practices. These 

differences were identified during the advisor meeting review process. The regional bias was 

then eliminated by subdividing the production data into two offshore and four onshore regions, 

collecting random samples within each regio~ and extrapolating by region. 

3.5 Quality Assurance and Quality Control Approach 

As defined during the 1980s quality initiatives, quality is conformance to 

requirements. 31 The programmatic quality assurance requirement of this project was to develop a 

28 
national emission estimate of defined uncertainty and no know bias. Accordingly, the 

GRIIEPA-ORD program included quality assurance and quality control (QA/QC) activities 

designed to control and assess the quality of the data collected and the resultant conclusions. 

Other QAJQC activities associated with the various data sources, data handling, 

project review, and statistical analysis are outlined in subsequent reports associated with this 

project. The report on general methodology explains the industry characterization used to 

identify each emission source, the measurement techniques, and calculation approaches. 5 The 

statistical approach for this project is presented in the statistical methodology report. 6 In 

addition, the individual reports for each emission source provide detailed statements regarding 

data quality efforts and uncertainties associated with the specific components that make up 

each emission estimate. 

3.5.1 Overview 

The first step in this project's QAJQC efforts was the establishment of project 

phases that had clear QC goals and that outlined QA review steps. This allowed the nature and 

breadth of data collection to be modified to ensure consistent data collection with minimal bias. 

The three phases of this study, and their inherent QA/QC goals were: 

Scoping phase--The sCoping phase included defining the boundaries of the 

natural gas industry and a comprehensive characterization of all equipment in the 

natural gas industry that could be a source of methane emissions. This process 

minimized the potential bias of missing sources or double counting sources in 

other industries, such as the oil production industry. Steps taken during this 

planning process ensured that all sources of emissions were examined and that the 

accuracy and bias goals of the project could be met. 

Methods development phase--Based on the factors that contributed to each 

emission source, methods and protocols were developed to measure and/or 

29 
calculate each emission factor. Measurement methods were validated through 

controlled experiments (laboratory), tests in the field, and proof of concept tests 

designed to quantify the accuracy in the measurement approach. Methods were 

also developed to extrapolate limited emission estimates to a national emission 

rate, accounting for regional differences in equipment and operational practices. 

The methods were peer reviewed before they were implemented. 

Implementation phase--The implementation phase focused on collecting the 

final field data required for emission factors and activity factors based on the 

developed methodologies. QC steps were used for data collection, and QA was 

performed on the data collected. Data were screened for bias and fwther stratified 

if a relationship between the emission rate and a parameter affecting emissions 

was identified. Uncertainty bounds were calcuiated to quantifY precision and 

results were compared to the target precision. Where necessary, additional data 

were collected to improve the precision of the national emission estimate for a 

particuiar source. 

The following sections outline the specific QA and QC goals and methods used throughout the 

project. 

3.5.2 Definitions 

In general, QC activities include those designed to control the data collection and 

data handling efforts to ensure consistency and reliability throughout the process. The QC 

activities incorporated throughout the project included: 

• Proof of concept tests; 

• Protocols for test methods and data collection; 

• Methodology for data handling, and extrapolation; and 

30 
• Established documentation, reporting, and filing systems. 

Quality assurance activities are generally considered those that are independent of the data 

gathering effort, per se. The QA activities incorporated throughout the project included: 

• Quality audits; 

• Industry peer review; 

• Comparison to other studies; and 

• Statistical analysis. 

Both QC and QA steps were aimed to minimize any potential bias in the estimate. The folio \\ling 

subsections describe the QC and QA efforts in more detaiL 

3.5.3 Quality Control 

The GRIIEPA study was designed from the beginning to implement standard QC 

procedures, such as defined methods and protocols for data collection and handling. The most 

significant QC step was the development and we of general methodologies that ensured 

consistent results. During the methods development phase, a sampling plan and data gathering 

protocol were developed. Most of the plans and protocols are outlined in the Volume 3 

Methodology Report,5 or in the Phase 3 Program Plan.27 

Emission factor measurement programs had a QC plan for measurement data 

gathering that included: 

• Adherence to fonnal protocols for data collection; and 

• Sampling and analysis QC checks, including 

Sample collection during representative operations, 

Instrument calibration, 

Analysis ofblank samples, 

31 
Analysis of known standards, and 

Analysis of replicate samples. 

In addition, where new measurement technologies were being applied, proof of 

concept tests were performed and documented. For example, for the new distribution tracer 

measurements of meter and regulation stations, QC efforts associated with emission factor 

measurements are outlined in the Phase 3 Program Plan27 and in the tracer measurement field 

report. 19 Since the measurement technology is new to this distribution application, proof of 

concept tests were performed and are reported in a separate volume.20 Similar QC efforts and 

proof of concept tests exist for underground pipeline leak measurements: QC plans were 

documented in the Phase 3 Program Plan and in the detailed field planning protocol", and QC 

results are documented in the Underground Pipeline Leaks report. 11 Other QC efforts for 

emission measurements, such as other fugitive emission efforts, are outlined in the specific field 

reports cited by this project (see Table 2-1 ). 

For activity factors, a general data collection methodology was developed that is 

described in the Activity Factor Report. 7 The collection of activity factor data included the 

following QC efforts: 

• Establishing a site visit protocol and data gathering form for each type of 

site; 

• Establishing a data entry protocol (for spreadsheet data entry from the site 

visit fonns and files); 

• Validation of data entry~ 

• Comparison among site entries to identify unusual data; and 

• Verification of WlUSual data. 

In most cases, activity factor data were gathered directly through site visits or from published 

sources. In a few instances, data were coJlected from efforts outside of this program and for 

which no published field reports exist. For example, one production company provided their 

compressor database which was used in the production activity factor estimate of 

32 
horsepowerhours. 13 In these cases, QC efforts performed by this project were limited, and QA 

efforts were therefore intensified, as is described in the following section on QA. 

Data on emission and activity measurements were collected and condensed 

electronically, so that auditable electronic files contain all oftht.: major data points, calculations, 

and·extrapolations. Many of these data are also printed in the field reports, and in the reports 

comprising the 15 volumes of this set. 

In addition to methodologies and QC efforts directed at activity and emission data 

gathering, methodologies and QC efforts were developed for data handling and extrapolation 

techniques. These are outlined in the Activity Factor report7 and the Statistical Methods report.6 

3,5.4 Quality Assurance 

The main goal of the QA program was to ensure the validity of the estimate 

through data audits, result reviews, and statistical analysis. As with the QC steps, one of the main 

goals of QA was to identify and eliminate bias. The main QA steps were audits, statistical 

analysis, technical review, and comparison to other studies. Each of these are described in the 

following paragraphs. 

Quality audits of the databases and calculations were conducted to verify accuracy 

of the mathematical applications. Audits included the follo\Ving: 

• Checks of the calculations made by spreadsheets. These were provided by 

hand checking the results using the equations and data published in the 

various reports. Also, independent calculation was performed by the 

summary spreadsheet (ir. Appendix A). This validated the individual 

emission rate and confidence bound calculations made in each report. 

• Checks of conformance to known technical relations and first principles. 

For example, in the QC checks of activity factor data provided on annual 

operating hours for compressors, data were rejected if operating hours 

exceeded 8760, the maximum number of hours in a year. 

33 
QA audits were also performed on industry databases provided by participant 

companies. In a few cases, specific company data were provided to a particular emission 

estimation process, such as compressor HP-hrs for an entire company's production division, or 

vented quantities from an entire transmission company's system. The data requirements were 

listed in a letter to the particular company. These data were checked for completeness by the 

project team, using follow-up questions to the supplier of the data, and some specific QA 

requirements for the data supplied. Some supplied data 1hat did not meet the QAJQC validation 

criteria were rejected or not used. Data that were gathered in violation of typical QC controls 

such as consistently following a generally accepted measurement method. For example, 

pneumatic device emission rate data that did not follow the QC protocol of a single measurement 

for a single device were rejected from the dataset. (Some measurements were emissions from 

multiple devices; this rejected only 2 data points from a set of 43.)" In some cases, the project 

team visited the company to discuss the data. Specific data discussions are provided in the 

detailed emission source reports (Volumes 6 through !5•17 in Table 2-1). 

Another QA step was the use of statistical analysis, using error propagation to 

define the p~cision and confidence in the final estimate. Uncertainty in the emission factors and 

activity factors was calculated for each emission source based on the variability in the data. The 

few exceptions relate to well documented data or emission sources with a very small contribution 

to the overall emission estimate. Narrow confidence bounds were assigned to well-known, often 

published values, where the confidence bounds were not published and the supporting data were 

not available to calculate a confidence bound (e.g., the natural gas production rate published in 

Gas Facfi33). For source categories with a very small emission rate but unknmvn uncertainty, 

wide confidence bounds were assigned rather than expending resources to collect additional data 

for a source that had an insignificant contribution to the end result. The method for the 

confidence bound is carefully documented for each value in the applicable emission 

characterization reports. 

34 
In all cases, the resulting confidence limits on the emission rate (the product of the 

emission factor and the activity factor) were rigorously propagated from the confidence limits of 

the activity and emission factor values. The result is that statistical analysis was very robust. The 

analysis was made even more robust through analysis of potential correlation between the data, 

and potential bias effects. In addition, separate tests of the input data sets were performed. For 

example, outlier tests were performed on input datasets. {See the Statistical Methods6 report for 

further details.) Any anomalies were verified and documented or corrected. 

Another very important and unique QA step was the extensive technical review 

process. All stages of this project received detailed review by an advisory panel comprised of 

gas industry experts and representatives from other related industries, such as coal and oiL The 

panel approved the goals and scope of the project and verified that the general results of the 

project were acceptable. The advisory panel rr:.et six times during the 5-year duration of the 

project to review and approve the methods and protocols. In addition, the advisory panel 

reviewed the draft and final versions of the project reports. 

Other industry reviewers were involved in the frnal stages of the project (spanning 

approximately two years). These individuals, who had industry experience relating to one or 

more specific project areas, reviewed emission estimates and the supporting data and 

methodology to verify that the results were not biased. In addition, the reviewers provided 

comments on individual reports in their areas of expertise. The involvement of these reviewers 

served as a QA measure by ensuring that all emission sources were accounted for and that all 

data handling methods were representative of the natural gas industry. A list of the advisors and 

reviewers is included in Appendix D of this report. The reviewers met four times to examine the 

detailed results and review the project team's OMl QA efforts that checked for: 

• Representativeness-Data were analyzed to determined if the sample set 

was properly stratified with respect to pertinent emission affecting 

parameters and representative of the U.S. natural gas industry, including 

regional differences in equipment and operating practices. 

35 
• Technical and scientific validity-Data were reviewed for conflicting 

results, for data that was inconsistent with physical possibilities, and for 

results that contradicted common industry experience. 

In addition to the review provided by industry experts, production activity factors 

developed by this project were comp~red to a separate source of national equipment cotm.ts.34 

EPA's Office of Air and Radiation (OAR) worked with an independent team of industry experts 

to estimate production activity factors using a consensus approach. Although the EPA-OAR 

results were not based on measured data, they provided an alternate method for estimating 

equipment counts and provided another check for potential bias. The EPA-OAR results 

compared well to the results of this GRIIEPA-ORD project. 

36 
4.0 DETAILED RESULTS 

The natural gas indus!Iy's total methane emissions are 314 Bscffor the 1992 

baseline year with a 90% confidence bound of± lOS Bscf. (See Section 4.7 for further 

explanation of the confidence bound.) The total emissions can be expressed as a percent of 

production: 314 Bscfis !.4% of gross 1992 production, which is 22,130 Bscf, or 1.7% of 

marketed gas production, which is 18,710 Bscf. 

This section presents the detailed methane emission estimates produced by this 

project. The results are presented by emission type in Section 4.1, and the methods used for 

estimating emissions are briefly discussed in Sections 42 through 4.4. The largest sources 

within each segment are discussed in Section 4.5. The emissions are also presented for different 

types of equipment in Section 4.6. 

4.1 Emission Type Summaor 

This section presents a summary of annual methane emissions by emission type. 

The emission types are fugitive, vented, and combusted, as described earlier in Section 3.1.3. 

Table 4-llists the largest sources of methane emissions in the U.S. gas industry by emission 

type. Fugitive emissions are the largest (195 Bscf), folJowed by vented emissions (94 Bscf), then 

combusted emissions (25 Bscf). Figure 4-1 shows the percentage of emissions by type for the gas 

industry. The major contributors to each emission type are discussed in more detail in the 

following subsections. 

37 
TABLE 4-1. UNITED STATES NATURAL GAS INDUSTRY LARGEST METHANE 

EMISSIONS SOURCES 

Source 

Fugitive Emissions (Sec 4.2) SUBTOTAL 

Equipment Leaks 

Compressor Stations (transmission and storage!' 

Production Facilities -

Gas Plants 

Metering and Pressure Regulating Stationsb 

Customer Meter Sets 

Underground Pipeline Leaks (all segments) 

Vented Emissions (Sec 4.3) SUBTOTAL 

Pneumatics" (4.3.1) 

Blow and Purge (4.3.2) 

Dehydrator Glycol Pumps ( 4.3.3) 

Dehydrator Vents (4.3.4) 

Chemical Injection Pumps (4.3.5) 

Other(AGR) 

Combusted Emissions (Sec 4.4) SUBTOTAL 

Compressor Exhaust ( 4.4) 

"Includes wells at storage facilities. 

TOTAL! 

Annual Methane 

Emissions o/o of Total (Bscf) 

195.2 62.1 

67.5 21.5 

17.4 5.5 

24.4 7.8 

31.8 I 0.1 

5.8 1.8 

48.4 15.4 

94.2 30.0 

45.7 14.6 

30.2 9.6 

11.1 3.5 

4.8 1.5 

1.5 0.5 

0.9 0.3 

24.9 7.9 

24.9 7.9 

314 100 

bEmissions from meter and pressure regu!ating-(M&PRJ stations result from both. pneumatic 

emissions. Since 

.and fugitive 

these components cannot be separated, M&PR emissions are shown as fugitive by default. 

Vented 

30% 

Conlbusted 

8% 

Figure 4-1. Emissions by Type 

38 

Fugitive 

62% 
4.2 Fugitive Emissions 

Fugitive emissions are defined as unintentional releases that include methane 

emissions from equipment leaks at sealed surfaces (component fugitive emissions), as well as 

from tmderground pipeline leaks. Figures 4-2 and 4-3 show the major contributors to fugitive 

emissions. Total fugitive emissions for the natural gas industry are 195.2 Bscf Undergrmilld 

pipeline leaks account for 48.4 Bscf of erniss1ons, and include leaks from production gathering 

lines, transmission pipelines, and distribution pipe systems. Equipment leaks account for 146.9 

Bscf, and are typicaiiy low-level emissions of process fluid (gas or liquid) from the sealed 

surfaces on above-ground process equipment. Specific fugitive emission source types include 

various fittings such as valves, flanges, pump seals, compressor seals, or sampling connections. 

These components represent mechanical joints, seals, and rotating surfaces, which in time tend to 

wear and develop leaks. 

Facilities and equipment that are significant contributors to equipment leak 

emissions include: production facilities, gas processing plants, compressor stations/facilities in 

transmission and storage, and meter and pressure regulating stations in transmission and 

distribution". The following subsections describe each of the major fugitive emission sources in 

more detail. 

Production Facilities 

9"/o 

Gas P1ants 

13% 

M&PR Stations 

16% 

EQUIPMENT LEAKS 

75% 

CllSl:om~r Meter Sets 

3% 

UNDERGROUND 

PIPELINES 

;~~~{f~~?~,t~ih€;i: .. lS% 

'- • ,- •c.•,c• _. -·;·· ~ 

Compressor Stations 

(T&S) 

34% 

Figure 4·2. Major Contributors to Fugitive Emissions From the Natural Gas Industry 

39 
... 

0 

Equipment 

Leaks 

Total 147 

195 

Underground 

Pipeline 

leaks 

48.4 

M&PR 

31.8 

Production . 

17.4 

Gas 

Plants 

24.4 

Compressor 

Stations 

(Transmission 

& Storage) 

67.5 

Customer Meters 5.8 

15.2 

22.4 

Compressors 

57.5 

9.9 

Compressors 2.2 

FacHity 

Compressors 

Facility 2.1 

Facilities (wells, stations) 

Figure 4-3. Major Contributors to Fugitive Emissions- By Segment Facilities 
4.2.1 Equipment Leaks 

Fugitive emissions from equipment leaks in the natural gas industry were 

estimated to be 146.9 Bscf. Of this total, 82.1 Bscfwas attributed to compressors, 31.8 Bscfto 

meter and pressure regulating stations, 5.8 Bscffrom customer meter sets, and 27.2 Bscffrom 

other surface facilities. Other surface facilities are the non-compressor portion of production 

facilities, gas plants, and transmission and storage stations. 

There are two general approaches for estimating fugitive methane emissions from 

equipment leaks: the tracer gas method and the component method. Tracer tests are conducted 

by releasing a tracer gas such as SF 6 at a kno'"'n constant rate near the methane emissions source. 

The concentration of methane and tracer are then measured downwind. The methane emissions 

are calculated based on the relationship that the ratio of emissions is equal to the ratio of 

concentrations. The tracer method measures total emissions from the facility, and was used to 

measure emissions from metering and pressme regulating (M&PR) stations. The tracer method 

for M&PR stations is described in more detail in Volume 10. 12 The component method is 

described in more detail in Volume 8 on equipment leaks. 10 Both techniques are described in the 

following subsections. 

In the component method for estimating emissions from equipment leaks, an 

average emission rate is determined for each of the basic components, such as valves, flanges, 

seals, and other connectors that comprise a facility. The average emission rate for each type 

of component is determined by measuring the emission rate from a large number of randomly 

selected components from similar types of facilities throughout the country. By knowing the 

average emission rate per component type (i.e., the component emission factor) and the 

average number of components associated with the major equipment or facility, an estimate of 

the average emissions per equipment/facility can be detennined. Extrapolation to a national 

emission estimate can then be made by determining the total count of that specific 

equipment/facility in the United States. 

41 
The component approach was used to estimate fugitive emissions from gas 

production facilities, processing plants, transmission/storage facilities, and customer 

meters. 21.24•

26.35 Separate component emission factors were developed for each industry segment 

because of differences in design and operating practices that could lead to differences in 

emissions characteristics. Some regional differences were also deter~nined to have an impact 

on fugitive emissions; therefore, regional component emission factors were developed. (That 

is, regional component emission factors were developed for onshore and offshore production.) 

For gas processing, transmission, and storage, separate emission factors were 

developed for components physically connected to, or directly adjacent to, compressors. 10•

35 

These compressor-related components were found to have significantly higher emission rates 

than components associated with other equipment. The higher emission rate from compressorrelated components is due to the unique design, size, and operation, as well as from the 

vibrational wear associated with compressors. For gas processing, transmission, and storage 

facilities, emissions were calculated as a sum of compressor-related components and station 

(non-compressor related) components. Table 4-2 presents an example of the calculational 

approach used to calculate fugitive emissions using the ·component method. 

Two approaches were used to quantify the component emission factors for 

valves, flanges, seals, and other connectors. The :frrst approach is based on the EPA protocol 

document using EPA Reference MethOd 21. 36 The EPA protocol approach involves screening 

components using a portable instrUment to detect total hydrocarbon (THC) leaks. The 

corresponding screening value for a component, which is a concentration measurement, is then 

converted to an emission rate by using a correlation equation developed from data collected 

using an enclosure measurement method. The enclosure method allows the actual leakage rate 

to be measured as the product of the flow rate of inert gas through the enclosure and the TiiC 

concentration. The correlation equation is developed by correlating the screening or 

concentration data with the emission rate data measured using the enclosure method. The 

correlation equation can then be applied to the same component type in similar service within 

the gas industry to estimate emissions using only screening data. The EPA protocol approach 

42 
Storage Facility (noncompressor related 

compone!lfs) 

Injection/Withdrawal 

Wellhead 

TABLE 4-2 EXAMPLE OF NATIONAL EMISSIONS ESTIMATION FOR GAS STORAGE FACILITrES 

Average 

Component Emission- Average -Equipment Activity Factor, 

fo'actor, Component ! - Emissions, Nutnber of 

_ -~~f/~~~()n~nt-yr ____ r---:------Count ____ ~-~~~- -~ ptan_ts/Comp!~~~s __ 

Va~~:_____ ___ ____ _ _ 0.8?2_ _______ r----- 1868 ··--- 7.85 475 

Connection 

- - -- ------------- 0.147 5571 ---- --- --- 11.2 353 -------

66 --- _Pressm~~lief Val~e ________ _g__ ____ _ 

Site Slowdown Open-Ended 264 4 

~ine _____________________ _ -- f-Valv~_ _ __ --- 0.918 30 ---f------ 0.042 17,999 

__fo!Ele_ction _______ _ - --- 0._12_5 _____ +--~._ __ 

t---2-Pel!:"~ded f,_i!!_e ______ __ 0}~- _ _____ _ ___ 7 __ 

___ Pr~sur~Re_l_iefValve __ 1 

_____ --~-464 ---+----~ __ 

Reciprocating Compressors 

Centrifugal Compressors 

Compressor Slowdown 

Op_en-Ended Li~ __ 

Pressure Reliif Valve 

5024 1 

317 ___ l __ 

f\1_i~c~llan'"o~u~'-----l- __ _ _15_3 _ I 

1440 0.6 Compressor Starter OpenEnded Line - _, - --------

-~ompress~§_~---- ________ _ 300 4.5 

Compressor Slowdown 10233 I 

Open-En_~d Line__ _ _ 

Miscellaneous _17 __ - --!-----_! ----

Compressor Starter Open- 1440 0.5 

f-~d_ed _!.i~ ___ _ 

Compressor Seal !26 1.5 

7.71 1,396 

11.16 136 

National 

Methane 

Emissions, 

Bscf 

3.7 

0.75 

10.8 

1.5 
was used to quantify emissions from equipment leaks in onshore production (except for 

production facilities in the Atlantic and Great Lakes region), offshore production, and gas 

processing. 

The second approach used to quantify component emission factors modifies the 

EPA protocol approach by using the GRI Hi-Flow"' sampler and direct measurements to 

replace the data collected using an enclosure approach. The GRI Hi-FlowTM sampler is a 

newly developed device which allows the leak rate of a component to be measured directly. 

The sampler creates a flow field around the component in order to capture the entire leak. As 

the stream passes through the instrument, the flow rate and concentration are measured. The 

GRI Hi-FlowTM sampling approach was used to quantify emissions from equipment leaks in 

onshore production in the Atlantic and Great Lakes region. gas transmission and storage, and 

customer meters. Direct measurements, such as rotameter readings, were also used on very 

high leak rates from open-ended lines at transmission and storage compressor stations. 

The following subsections explain how fugitive emissions were calculated for 

each of the facility types that were significant contributors to total national emissions. 

Compressor Stations (Transmission and Storage) 

Compressor stations in transmission and storage are one of the largest sources 

of fugitive emissions. Equipment leaks from transmission compressor stations were separated 

into two distinct categories because of differences in leakage characteristics: 

• Station components including all sources associated with the station inlet 

and outlet pipelines, meter runs, dehydrators, and other piping located 

outside of the compressor building; and 

• Compressor -related components including all sources physically 

connected to or immediately adjacent to the compressors. The types of 

components associated with compressors include compressor blowdown 

44 
open-ended lines, starter open-ended lines, compressor seals, pressure 

relief valves, and other components such as cylinder valve covers and 

fuel valves. 

Fugitive emissions from compressor stations are dominated by emissions from 

components related to compressors, which emit 57.5 Bscf, while emissions from ali of the 

remaining components not associated with compressors contribute only 9.9 Bscf. 

Fugitive emissions were estimated from measurement data collected at 15 

compressor stations using the GRI Hi-FlowTM approach.24 Leaking components were 

identified using soaping tests and all leaking components were directly measured using the GRI 

Hi-Flow TM sampler or a direct flow measurement, such as a rotameter. Based on the 

measurement data, fugitive emissions from the compressor blowdown open-ended line were 

found to be the largest source. Compressor blowdown open-ended lines allow a compressor to 

be depressurized when idle, and typically leak when the compressor is operating or idle. 

There are two primary modes of operation leading to different emission Tates for compressor 

blowdown open-ended lines: 

• Blowdown valve is closed and the compressor is pressurized, either 

during normal operation or when idle. 

• Compressor blowdown valve is open. This occurs when the compressor 

is idle, isolated from the compressor suction and discharge manifolds, 

and the blowdown valve is opene9 to depressurize the compressor. 

The fugitive emission rate is higher for the second operating mode when the 

blowdown valve is open, since leakage occurs from the valve seats of the much larger suction 

and discharge valves. Separate component emission factors were developed for the two 

operating modes of the compressor blowdown open-ended line. An overall average 

component emission factor was derived for compressor blowdown open-ended lines by 

45 
determining the fraction of time transmission compressors operate in each mode (i.e., 

pressurized and depressurized). 

The majority of compressor fugitive emissions result from the transmission and 

storage segments, where a high number of very large compressors exist. Since compressors 

are also a part of production facilities and gas plants, the compressor component emission 

factors developed for the transmission and storage segments were also used for compressor 

components in those segments. 

Production Facilities 

Annual fugitive emissions from gas production facilities in the United States 

were estimated to be 17.4 Bscf. Component emisSion factors for fugitive equipment leaks in 

gas production were estimated separately for onshore and offshore production due to 

differences in operational characteristics. Regional differences were found to exist between 

onshore production in the Atlantic and Great Lakes region (i.e., Eastern U.S.) and the rest of 

the country (i.e., Western U.S.), and between offshore production in the Gulf of Mexico and 

the Pacific Outer Continental Shelf (OCS). In general, these regional differences were due to 

differences in the number, type, age, and leak detection and repair characteristics of 

equipment. Therefore, separate measurement programs were conducted to account for these 

regional differences. 

For onshore production .in the Eastern U.S., component emission factors and 

average component counts were based on a measurement program using the GRI Hi-FlowTM 

sampler to quantitate emission rates from leaking components.22 A total of 192 individual well 

sites were screened at 12 eastern gas production facilities. 

Fugitive emissions from onshore production in the rest of the U.S. (excluding 

the Eastern U.S.) were estimated using the EPA protocol approach. Component emission 

46 
factors were based on screening and enclosure data collected from 83 gas wells at 4 gas 

production sites in the Western U.S. 21 The average component counts were based on data 

from the onshore production measurement program and additional data collected during 13 site 

visits to gas production fields. 10 

Emissions from equipment leaks from offshore production sites in the U.S. 

were quantified based on two separate screening and enclosure studies using the EPA protocol 

approach: 

• The oil and natural gas production operations measurement program}1 

which included 4 offshore production sites in the Gulf of Mexico; and 

• The offshore production measurement prograrn,37 which included 7 

offshore production sites in the Pacific OCS. 

Gas Processing Plants 

Fugitive emissions from gas processing plants contribute 24.4 Bscf to national 

annual methane emissions. The majority of fugitive emissions from gas processing plants are 

attributed to compressor-related components. which account for 22.4 Bscf. The component 

emission factors for compressor-related components in gas processing plants were based on the 

fugitives measurement program at 15 compressor stations. 1

° Fugitive emissions from the 

remaining gas plant components, not associated with compressors. were estimated based on the 

oil and gas production measurement program.21 In the oil and gas production measurement 

program. equipment leaks from a total of 8 gas processing plants were measured using EPA 

protocol approach. 

47 
Meter and Pressure Regulating Stations 

Fugitive emissions from meter and pressure regulating stations (M&PR stations) 

contribute 3 I .8 Bscfto total annual methane emissions. Emissions from this category of surface 

equipment were measured using the tracer measurement approach, and therefore were reported 

separately from other categories of surface equipment fugitives. A total of95 M&PR facilities 

were measured using the tracer technique. 12 

The primary losses from M&PR stations include both fugitive emissions and, in 

some cases, emissions from pneumatic devices. Since the tracer measurement teclmique used 

does not differentiate between fugitive and vented emissions, the vented pneumatic emissions are 

therefore included in the fugitive category by default. Some pressure regulating stations use gasoperated pneumatic devices to position the pressure regulators. These gas-operated pneumatic 

devices bleed to the atmosphere continuously and/or when the regulator is activated for some 

system designs. Other designs bleed the gas downstream into the lower pressure pipeline and, 

therefore, have no losses associated with the pneumatic devices. 

Tracer measurements were used to derive the emission factors for estimating 

emissions from M&PR stations in both the transmission and distribution segments of the gas 

industry. The total emissions are a product of the emission factor and activity factor, which were 

stratified into inlet pressure and location (above ground versus in a vault) categories to improve 

the precision of the emissions estimate. 

Metering/pressure regulating stations in the distribution segment include both 

transmission-to-distribution custody transfer points and the downstream pressure reduction 

stations. The emission factors for distribution are based on the average measured emissions for 

each station category, and the activity factors are based on the average data supplied by 12 

distribution companies. The annual methane emissions for the M&PR stations in the distribution 

segment of the gas industry are 27.3 Bscf 

48 
For the transmission segment, the stations include transmission to transmission 

custody transfer points and transmission-to-customer transfer. Emission factors for the 

transmission segment are derived from the tracer measurement database for M&PR stations, and 

the activity factors are based on survey data from six transmission companies. The annual 

e:;:timated methane emissions for the transmission segment are 4.5 Bscf. 

Customer Meter Sets 

Fugitive emissions from commercial/industrial and residential customer meter 

sets contribute 5.8 Bscf to total national emissions. The average leak rate per residential meter 

set is only 0.01 scf/hr, but there are approximately 40 million customer meters located 

outdoors. The meter sets include the meter itself and the related pipe and fittings. Methane 

emissions from commercial and residential customer meter sets are caused by fugitive losses 

from the connections and orher fittings surrounding the meter set. No losses have been found 

from the meter itself; only the pipe fittings surrounding the meter have been found to be 

leaking. 

Methane emissions from customer meter sets were estimated based on fugitives 

screening data collected from 10 cities across the United States. 10.24 -

26 Although a total of 

around 1600 meter sets were screened as part of the GRI/EPA study, only about 20% of the 

meter sets screened were found to be leaking at low levels. For the majority of customer 

meter sets screened, the GRI Hi-Flow device was used to develop emission factors. For the 

other meter sets screened, the EPA protocol approach was used to convert the screening data 

into emission rates. 

Emission factors for residential customer meter sets were defmed as the average 

methane leakage rate per meter set for outdoor meters. Emissions from indoor meters are 

much lower than for outdoor meters because gas leaks within the confmed space of a residence 

are readily identified and repaired. This is consistent with the fmdings that pressure regulating 

49 
stations located in vaults have substantially lower emissions than stations located above 

ground. Emission factors for commercial/industrial meter sets were estimated separately as 

the average emission rate per meter set. 

The activity factors for residential customer meter sets were defmed as the 

number of outdoor customer meters in the United States. The activity factor was based on 

published statistics including a breakdown of residential customer meters by region in order to 

estimate the number of meter sets located indoors. Data were obtained from 22 individual gas 

companies within different regions of the United States to estimate the number of indoor 

residential customer meters. 

4.2.2 Underground Pipeline Leaks 

Fugitive leakage from underground piping systems contributes 48.4 Bscfto total 

methane emissions. Pipeline leaks are caused by corrosion, material defects, and joint and fitting 

defects/failures. Based -on limited leak measurement data from two distribution companies, 

leakage from underground distribution mains and services was targeted as a potentially large 

source of methane emissions from the gas industry. 

A leak measurement technique was developed (Section 3.2.1) and was 

implemented as a method to quantifY methane emissions from undergrmmd pipelines in the 

natural gas industry .

11 A total of 146 leak measurements were collected from the participating 

companies. These data were used to derive the emission factors for estimating methane leakage 

from distribution, transmission, and production underground pipelines. 

The total emissions are a product of the emission factor and activity factor, and 

are stratified by pipe use (mains versus services) and pipe material categories to improve the 

precision of the estimate. The total annual methane emissions from underground pipeline leaks 

in all segments are 48.4 Bscf. 

50 
The soil oxidation rates of methane were experimentally detennined to be a 

function of the methane emissions rate, pipe depth, and soil temperature. The methane leakage 

rate for underground pipelines was detennined to be a function of the pipe service (main versus 

services) and the pipe material type. In general, the larger the leakage rate per leak, the lower the 

soil oxidation rate. Because of the type of pipelines in service in the distribution segment, the 

overall leakage rate per peak is lower. Therefore, the overall oxidation rates for distribution 

pipelines is higher than for transmission or gathering lines. 

In the distribution segment, activity factors were based on the national database of 

leak repairs broken down by pipe material using information from ten companies, and then 

combined with historical leak records provided by six companies. The activity factors represent 

the number of equivalent leakS that are continuously leaking year round. (Repaired leaks are 

cmmted as fractional leaks.) 

The activity factor combined with the emission.factors derived from the leak 

measurement data produced an overall methane emissions estimate of 41.6 Bscf, which includes 

an adjustment for soil oxidation. The largest contributor to the overall annual emissions was cast 

iron mains, followed by unprotected steel services and mains. The average soil oxidation rate 

applicable to distribution piping was 18%, which primarily affects the emissions from cast iron 

mains, which have low leak rates per leak. 

In the transmission and production segments, the estimated methane leakage was 

based on the emission factors derived from the leak rates measured on distribution mains and on 

activity factors derived from a nationally tracked database of pipe mileage/leak repairs. For 

transmission pipeline leakage, the estimated annua1 methane emissions were 0.2 Bscf, which 

includes an adjustment for soil oxidation. 

51 
For gathering pipeline in the production segment, the estimated armual methane 

emissions were 6.6 Bscf. The estimated methane emissions to the atmosphere from gathering 

lines includes an adjustment of 5% average methane oxidation in the soil. 

4.3 Vented Emissions 

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

2) blow and purge emissions, and 3) dehydrator emissions. Emissions from chemical injection 

pumps is a minor category. Figure 4-4 shows each of the contributions to vented emissions. 

Each of these are described in more detail in the following sections. 

Dehy. Glycol Pumps 

12% 

Blow and Purge 

32% 

Dehy. Vents 

5% 

Other 

3% 

Figure 4-4. Contributions to Vented Emissions 

4.3.1 Pneumatic Devices 

Pneumatics 

48% 

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 

52 
as well. Pneumatic devices are a major source of unsteady emissions and account for 45.7 Bscf 

of methane emissions. 14 Methane emissions from pneumatic devices were calculated based on 

field measurements, site data, and manufacturers' data. 

There are two primary types of these devices: I) 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 emission rates, although the emission rate per 

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

maintenance activities that require isolating a piece of equipment or section of pipeline. 

Alternatively, control valves typically move frequently to make adjustments for changes in 

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

Emission factor estimates for pneumatic devices were based on a combination of 

site infonnation, manufacturers' data, and measured emissions from devices in the field. Each 

segment of the industry has very different practices regarding the use of pneumatic devices. 

These differences and a summary of the data collected to characterize the different pneumatic 

devices are described below. 

Production 

The production segment accounts for the majority of the pneumatic emissions: 

31.4 Bscf, or 69% of all pneumatic emissions. High pressure natural gas is used to operate most 

of these devices, since production facilities are usually located at remote sites. Natural gas is 

readily available and less expensive than compressed air or electricity at the remote sites. The 

majority of devices are used to regulate flow and can emit methane either on a continuous basis 

or only when the device actuates. Data were collected from 22 sites to detennine the fraction of 

continuous bleed devices versus intennittent bleed devices. A total of 44 measurements of 

various device types in field operation were used to estimate the emission factor. In addition, the 

four most common manufacturers of these devices were contacted for information regarding the 

53 
characteristics of the devices that affect emissions. The total number of pneumatic devices in the 

production segment were detennined based on data from more than 35 sites. 

Gas Processing 

Pneumatic device emissions from the gas processing segment are very small: 0.1 

Bscf, or less than 1% of all pneumatic emissions. Emissions were based on data collected from 

nine gas processing plants and from the. four manufacturers of the devices observed. Of the gas 

processing plants surveyed, only one-half (56%) 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 per month or 

once per year), so the emissions per site are relatively small. 

Transmission/Storage 

Emissions from pneumatic devices at transmission compression stations and 

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

most of the pneumatics are gas-actuated isolation valves. Data for these types of devices were 

provided by 16 sites and two manufacturers. There are a few pneumatic control valves used to 

reduce pressure or to control liquid flow from a separator or scrubber. Emissions for these 

devices were based on infonnation collected from 54 sites and 23 measurements of operating 

devices. Site data from 54 stations were also used to detennine the number of devices per 

station, which was extrapolated to a national number ofpneumat~c devices in the transmission 

segment. 

54 
Distribution 

Pnemnatic emissions for the distribution segment are included in the "fugitive" 

emission factor for M&PR stations. The M&PR pnemnatics cannot be separated from fugitives, 

since M&PR total emissions were measured using the downwind tracer teclmique. 

4.3.2 Blow and Purge 

Blow and purge is a major source of unsteady emissions and accotmts for 

approximately 30.2 Bscf of methane emissions.9 Blow (or blowdown) gas refers to intentional 

and unintentional venting of gas for 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: 

I) Maintenance Blowdown - The gas is vented from equipment to eliminate 

the flammable material inside the equipment, thus providing a safer 

working environment for personnel 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 fire begins at a 

compressor station, the station emergency shutdown and emergency 

blowdo'Wil system blocks the station away from the pipelines and 

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

the fire. 

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

frequency, vohune of gas blowdovm per event, and the disposition of the blowdown gas. 

Slowdown from maintenance releases were detennined by equipment category: 

compressor blowdown, compressor starts, pipeline blowdown, vessel blowdovm, gas wellbore 

55 
blowdown, and misceilaneous equipment blowdowns. Emergency blowdowns refer 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, 

pipeline ruptures caused by unintentional damage, were also classified under emergency release 

of gas and included in the blow and purge estimates. 

Emission estimates for each industry segment were based on data from site visits 

or company tracked data. Blow and purge emissions from the production segment, accounting 

for approximately 6.5 Bscf of the total blow and purge emissions, were based on data from 25 

sites. Emissions for transmission and gas processing plants, which have similar station 

blowdown practices, were based on data from eight companies. These industry segments 

account for 18.5 Bscf and 2.9 Bscf of the total blow and purge emissions, respectively. The 

distribution segment makes up about 2.2 Bscf of the total blow and purge emissions, and the 

emission estimate for this segment was based on detailed unaccounted-for gas studies from two 

distribution companies. 

4.3.3 Dehydrator Glycol Pumps 

Glycol dehydrator circulation pumps are a major source of unsteady emissions 

and account for I 1.1 Bscfofmethane emissions. 17 These pumps use the high pressure of the rich 

glycol from the absorber to power pistons tbat pump the low pressure, lean glycol from the 

regenerator. The pump configuration pulls additional gas from the absorber along \\ith 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 through the dehydrator vent stack along with the methane 

absorbed in the rich glycol stream (see Section 4.3.4). 

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

at 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 

56 
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 nearly half 

of the methane emissions from dehydrators, so they are considered separately. 

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

atmosphere, dehydrator pumps pass the driving gas along with the rich (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. Design data from 

Kimray were used to establish the amount of gas used by these pumps. Gas-assisted glycol 

pumps were found almost exclusively in prod:.Iction dehydrators, with a few in gas processing. 

No active gas-assisted pumps were found during the site visits to transmission or storage 

facilities, which is consistent with the fact that larger facilities tend to have electricity available. 

4.3.4 Dehydrator Vents 

Glycol dehydrator vents are a major source of methane emissions and account for 

4.8 Bscf of methane emissionsP The majority of the glycol dehydrators are located in 

production, but dehydrators are also used in gas processing, transmission, and storage. Methane 

emissions are highest in the production segment; 71% of the total dehydrator vent emissions are 

attributed to dehydrators in the production segment. ThiS is due to the high activity and emission 

factors for this segment. The absence of flash tanks in most production dehydrators leads to an 

emission rate per volume of gas dehydrated that is higher in production than in the other 

segments. 

Glycol dehydrators remove water from the natural gas through continuous glycol 

absorption. The water-rich glycol is 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 

57 
amount of methane. The methane is driven off with the water in the regenerator and vented to 

the atmosphere. 

The important emission-affecting variables for dehydrators are: gas throughput, 

use of a flash tank, use of stripping gas, and use of vent controls where the gas is routed to a 

burner. An emission factor per unit of gas throughput was established for glycol dehydrator 

regenerator vents using three sources of data: I) computer simulations of dehydrator operations 

using first principles; 2) data from actual samples taken from regenerator vents; and 3) multiple 

site visits. The emission factor was combined with an activity factor to generate the emission 

rate. The activity factors are the volumes of gas dehydrated in each industry segment. The total 

glycol dehydrator throughput compares well with a separate study conducted by API." 

4.3.5 Chemical Injection Pumps 

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

1.5 Bscf of methane emissions solely in the production segment. 15 Emission estimates for this 

source were based on data from 17 sites, 6 manufacturers, and emission measurements from a 

Canadian study.39 The total number of chemical injection pumps nationally was extrapolated 

from data relating the number of chemical injection pumps to the number of gas wells at 38 sites. 

Gas-driven chemical injection pumps use gas pressure to move a piston which 

pumps the chemical on the opposite end of the piston shaft; the power gas is then vented to the 

atmosphere at the end of the stroke. The power gas may be natural gas or compressed air. Two 

types of chemical injection pumps were observed: I) piston pumps, and 2) diaphragm pumps. 

The larger diaphragm pumps emit more gas per stroke, and they are used to pwnp 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 inhibitors, 

scale inhibitors, biocides, demulsifiers, clarifiers, and hydrate inhibitors to operating equipment. 

58 
These additives protect the equipment or help maintain the flow of gas. The vast majority of 

these pumps exist in the production segment where the gas is wet and has a high non-methane 

content. The pumps are most often located at the well sites, so that the chemical can protect all 

of the downstream and downhole equipment. Most of the chemical injection pumps in oil and 

gas production are associated with oil production and were not included in this study. As with 

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

natural gas. 1 

s 

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. 

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 Combusted Emissions 

Combusted emissions result from incomplete combustion of methane in burners, 

flares, and engines. Incomplete combustion of methane in compressor engine exhaust is the only 

significant source of methane in this category. 

Methane emitted to the atmosphere in compressor driver exhaust is a major source 

of unsteady emissions and accounts for 24.9 Bscf of methane emissions. 13 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 turbine drivers. A few compressors in the industry are 

driven by other means such as electrical motors, but the majority are natural gas fueled. In 

59 
addition to compressors, there are some natural gas drivers that run electrical generators at gas 

plants and compressor stations. 

Reciprocating engines emit approximately 40 times more methane per horsepower 

or per unit of fuel consumed than gas turbine drivers. Reciprocating engines account for over 

two~ thirds of all installed horsepower in the gas industry. Therefore, reciprocating engine 

compressor drivers account for over 98% of the methane emissions for this category. 

Emissions were determined by analyzing and combining several databases to 

generate emission factors and activity factors. A GRI database, the TRANSDAT compressor 

module,40 contains data from A.G.A. on types and models of compressors in use, as well as data 

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

data from government agencies, such as the U.S. Department of Energy (DOE) and the Federal 

Energy Regulatory Commission (FERC). and from surveys of its member companies in 

transmission and distribution. SwRI data were generated through actual field testing. These 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 

data from GRI 1RANSDAT, FERC, A.G.A., company databases, and site visits. GRI 

TRANSDAT includes horsepower data for 7489 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 and 

operating hours were based on A.G.A. data and data from 11 storage stations, respectively. 

Since national totals for transmission and storage horsepower were available, no industry 

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

on one company's data for 513 reciprocating engines and 6 gas turbines. Processing horsepower 

and operating hours were based on 10 site visits and company data for II gas processing plants. 

60 
Activity factors for production and processing were extrapolated to the industry using published 

data for national marketed gas production and gas processing, respectively. 

4.5 I ,argest Sources by Industry Segment 

This section summarizes the segment emissions and presents the data by largest 

emission categories within each segment. Table 4-3 presents a summary of emissions by gas 

industry sector. Figure 4-5 shows the same data in a chart fonnat. 

TABLE 4-3. SUMMARY OF METHANE EMISSIONS 

Emissions as a Percent of 

Emissions Gas Produced (Gross (Bscf) Percent ~fTotal 

Segment Eniissions (%) National Product) 

Production 84.4 26.8 0.38 

Processing 36.4 11.6 0.16 

Transmission/Storage 116.5 37.1 0.53 

Distribution 77.0 24.5 0.35 

TOTAV. 314± 105 100.0 1.42 

*Gross national production of natural gas ~ 22,132 Bscf (22.13 Tscf)41 

(Accuracy Goal is± I! 0.7 Bscf or± 0.5% of production) 

Distribution 

24% 

Transmission! 

Storage 

3?0/o 

Production 

27% 

Processing 

12% 

Figure 4-5. Summary of Methane Emissions 

61 

.. 
The total segment emissions presented in Table 4-3 and Figure 4-5 are split into 

emission type in Table 4-4. The largest emission type for the entire U.S. natural gas industry is 

fugitive emissions; however, the largest emission category in each segment varies. Vented 

emissions are the largest emission category in production because of the contribution from 

pneumatic devices. In tht• other segments of the industry, fugitive emissions are the largest 

source. 

Segment emissions also can be broken down into the largest categories that were 

presented in Table 4-I, U.S. Natural Gas Industry Largest Methane Emission Sources. These 

categories are actually a mixture of emission types and equipment types, since some 

measurement programs were specific to a type of equipment (such as the buried pipeline leak 

statistics method), while others were not. 

Since the characteristics of each segment of the natural gas industry are quite 

unique, and since companies within each segment will want to know their segment's emissions, 

the data bave been recast by segment. Tables 4-5 through 4-8 show the largest sources within 

each segment. Figures 4-6 through 4-9 show the same data in chart format. 

Table 4-5 shows that the largest sources in production were pnewnatic devices 

and fugitive emissions. Table 4-6 shows that the largest sources in gas plants are fugitive 

emissions and compressor driver exhaust. Table 4-7 shows that the largest sources in 

transmission and storage are fugitives, pneumatic devices, blow and purge, and compressor 

driver exhaust. Table 4-8 shows that the largest sources in distribution are M&PR stations and 

underground pipeline leaks. There are nine categories (rows) on Tables 4-7 through 4-8 that 

exceed I 0 Bscf, and four of these are in the transmission segment. 

62 
"' 

w 

TABLE 4-4 . EMISSIONS BY TYPE 

Gas 

Processing Transmission Distribution 

Production Segment and Storage Segment 

-----

Emission 

-··- -------

Type Segment 

.. 

(Bscl) (Bscl) Segment (Bscl) (Bscl) ----------- --------" -· ------ ----------- -------

fugitive 

- -- - -------------

24.0 24.4 72.1 74.7 ------------- -- --- ---- - - - ----- - ----

--------

Vented 53.8 5.1 33.0 2.2 -- - ------ - ----- - --- 1---- - ---

Com busted ---- ---

6.6 6.9 11.4 NIA - ----- - - ---- --- -----··-- --- ---- - 1------- -

TOTAL* 84.4 36.4 116.5 77.0 

* Individual categories may not sum exactly to totals shown due to roundoff errors. 

Natural Gas 

Industry Emission Type as 

Emissions .. Percent of Total 

(Bscl) (%) 1----------- ------ ----------- -- --·--

195.2 62.1 - ----- ---- -- -

94.2 30.0 --- --- -- - - ---------

24.9 7.9 \-------- -- ----- -- ---

314 100%) 
TABLE 4-5. PRODUCTION SEGMENT LARGEST SOURCES 

Source 

Pneumatic Devices 

Fugitive Ernissionsa 

Underground Pipeline Leaks 

Blow and Purge 

Compressor Driver Exhaust 

Glycol Dehydrator Pumps 

Glycol Dehydrator Vent 

Chemical Injection Pumps 

Other 

aExcludes underground pipeline leaks. 

Dehydrator Vents and 

Pumps 

17% 

Underground PJL 

Leaks 

8% 

Blow and Purge 

8% 

Compressor 

Driver Exhaust 

8% 

Annual Methane 

Emissions (Bscf) 

31.4 

17.4 

6.6 

6.5 

6.6 

I 1.0 

3.4 

1.5 

<0.1 

84.4 

Other 

<2% 

% of Segment Total 

372 

20.6 

7.8 

7.8 

7.8 

13.0 

4.0 

1.8 

<0.1 

100 

Fugitive Emissions 

21% 

Pneumatic Devices 

37% 

Figure 4-6. Production Segment Largest Sources 

64 
TABLE 4-6. GAS PROCESSING SEGMENT LARGEST SOURCES 

J Annual Methane 

Source Emissions (Bscf) '%of Segment Total 

Fugitive Emissions 24.4 67.1 

Compressor Driver Exhaust 6.9 18.8 

Blow and Purge 2.9 8.1 

Other 0.9 2.6 

Glycol Dehydrator Vent 1.0 2.9 

Glycol Dehydrator Pumps 0.2 0.5 

TOTAL* I 36.4 100 

*Individual categories may not sum exactly to total shown due to rmmdoff errors. 

Other 

Blow and Purge 6% 

Compressor Driver 

Exhaust 

19% 

8o/o ----~r---------_ 

Figure 4-7. Gas Processing Segment Largest Sources 

65 

Fugitive Emissions 

67% 
TABLE 4-7. TRANSMISSION AND STORAGE SEGMENT LARGEST SOURCES 

Annual Methane 

Source Emissions (Bsc1) 

Fugitive Emissions" 67.5 

Blow and Purge 18.5 

Pneumatic Devices 14.1 

Compressor Driver Exhaust 11.4 

M&PR Stations 4.5 

Glycol Dehydrator Vent 0.3 

Underground Pipeline Leaks 0.2 

Glycol Dehydrator Pumps 0.0 

Other 

0.0 

TOT ALi 116.5 

'Excludes underground pipeline leaks and M&PR leaks. 

Compressor Driver Other 

Blow and Pwge 

1&'/o 

Exhaust 4% 

10% 

Pneumatic Devices 

12% 

o/o of Segment Total 

57.9 

15.9 

12.1 

9.8 

3.9 

0.3 

0.1 

0.0 

0.0 

100 

I Fu.o·u·, 1e Emissions 

58% 

Figure 4-8. Transmission and Storage Largest Sources 

66 
TABLE 4-8. DISTRIBUTION SEGMENT LARGEST SOURCES 

Source 

Underground Pipeline Leaks 

Meter and Pressure Regulating Stations 

(includes fugitive and pneumatic device emissions) 

Customer Meters 

Other 

TOTAL*. 

Annual Metb~me 

Emissions (Bscl) 

41.6 

27.3 

5.8 

2.2 

77.0 

% of Segment Total 

54.1 

35.5 

7.5 

2.9 

100 

*Individual sources may not sum exactly to total shown due to roundoff errors. 

Customer Meters Other 

Underground P/L 

Leaks 

54% 

7% 3% 

Figure 4-9. Distribution Largest Sources 

67 

M/R. Stations 

36% 
4.6 Eguipment Emissions 

The data presented in Sections 4.1 through 4.4 and in the Sununary Table in 

Appendix A are grouped by emission source or emission category. An alternate method for 

grouping the emissions is by equipment type. Sii~ce some companies may wish to use the 

methane emissions data to make decisions on equipment choices, it is important to know all of 

the methane emissions associated with each equipment type. 

For example, this grouping would allow a company to make a better choice 

between turbine and reciprocating compressors, if methane emissions from the compressors were 

important to the company. Instead of using only the difference in compressor exhaust emissions 

between the two types, all of the compressor emissions should be used in the comp~son. For 

example, all turbine compressor emissions would include: turbine compressor exhaust, turbine 

compressor blow and purge, turbine compressor fugitives, and turbine compressor pneumatics. 

Unfortunately, 

many 

recasting the data in this fonn cannot be done with precision since 

emission categories cannot be accurately split into equipment types. The methods used to 

estimate the emissions simply do not provide this breakdown. Blow and purge emissions from 

compressors, for example, were calculated from total volumes for all events provided by a 

company. Since the companies did not provide the data by engine type, the data cannot be 

accurately split into compressor start gas for turbines, compressor start gas for reciprocating 

engines, blowdovm gas for turbines, and blowdown gas for engines. 

The assumptions used to split emlssions into equipment types are listed in Table 

4-9. Table 4-9 shows that reciprocating compressors contribute the most emissions among the 

categories (100 Bscf). This is due to the large number of reciprocating compressors, combined 

with large emission rates from the following: fugitive emissions associated with compressor 

components, the large compressor exhaust emissions from reciprocating compressors, and 

relatively large blowdown emissions associated with reciprocating compressors. The next 

highest equipment category is pipelines (60 Bscf), which have high emissions due to the 

68 
TABLE4-9. EMISSIONS BY EQillPMENT 

Estimated Annual Emissions (Bsd) 

Equipment Type Emissions Included Fugitives Vented I 

I Combusted 

Reciprocating Exhausts, blow and purge (starts and 67.4 6.4 24.6 

Compressors blowdowns), fugitives, pneumatics, 

production stations 

Pipe] ines (Gathering Fugitives, dig-ins, blow and p:.~rge 48.4 11.5 

Transmission, Dist.) 

Separators Fugitives., pneumatics, chemica.l 3.4 29.8 

injection pumps, production vessel 

blowdowns., production PRY's 

M&R Stations Fugitives, distribution PRV's 31.8 <D. I 

Transmission Station Fugitives., pneumatics, station venting 9.2 22.2 

Vessels/Piping 

Centrifugal Compressors Exhausts. blow and purge (starts and 14.7 0.4 0.3 

I b!owdowns), fugitives 

Glycol Dehydrators Fugitives, pneumatics, dehydrator vents, 1.2 17.4 

AGR vents, dehydrator pumps 

Wellheads Fugitives. well workovers. well clean 3.0 5.7 <0.1 

ups. completion flaring 

Production Meters/Piping Fugitives 6.1 

Customer Meters Residential, commerciallindustry 5.8 

Gas Plant Vessels/Piping Fugitives, pneumatics, blow and purge 2.1 0.4 

Offshore Platforms Fugitive, ESD 1.2 0.3 

Heaters Fugitives 1.1 Neg!. 

TOTAL 195 942 24.9 

Assumptions: 

·Production pneumatics are broken down as: 90% separators, 2% dehydrators, 8% reciprocating compressors. 

·Gas processing pneumatics are broken down as: 90% vessel/pipes. 10% reciprocating compressors . 

• Transmission and storage pneumatics are broken do\'fll as: 90% vessel/pipes, 10% reciprocating compressors . 

• Gas processing b!owdowns are broken do\'fll as: 76% reciprocating compressors, 14% turbine, and 10% vessel/pipes. 

69 

Total 

98.4 

59.9 

33.2 

31.9 

31.4 

15.3 

18.6 

8.7 

6.1 

5.8 

2.5 

1.5 

1.1 

314 
tremendous mileage of pipe in the United States combined with relatively large dig-in and blow 

and purge emissions rates. The third highest equipment category is production separators (3 

Bscf). Separators have a high emission rate due to the large population, combined with high 

emission rates from associated pneumatics, fugitives, and chemical injection pumps. There are 

four other equipment categories that each exceed 10 Bscf: M&R stations, transmission station 

vessels and piping (i.e. everything but the compressors), turbine compressors, and glycol 

dehydrators. 

Many of the categories in Table 4-9 have high emissions due to a high population 

of equipment, rather than due to a high emission rate per equipment. Table 4-10 recasts the total 

data in Table 4-9 into equipment emission factors by using aggregate activity factors. Many of 

these aggregate factors are groupings of multiple categories, such as all types of pipeline miles. 

They are therefore not as specific as the individual activity factors presented in Appendix A, and 

should be used only for the purposes of comparison in this table. 

Table 4-10 shows that the highest single sources on the list are gas plants and 

transmission and storage stations. These are large facilities with large equipment counts that 

result in relatively high fugitive and blow and purge emissions. The highest emission factors for 

individual equipment types are : I) compressors, 2) glycol dehydrators, 3) separators, and 4) 

M&PR stations. Each of these are explained in more detail below. 

While turbine compressors have the highest emission rates per compressor unit 

(due to fugitives and blowdowns), reciprocating engine-driven compressors have higher methane 

emissions per million horsepower hour. This makes sense because turbine driven compressors 

have specific maintenance practices that result in higher blowdown and fugitive emissions on a 

per compressor basis, yet have far lower driver exhaust emissions on a per HP-hr basis. 

70 
TABLE 4-10. ESTIMATED EQUIPMENT EMISSION FACTORS 

Estimated Aetivity Estimated Emission Factor (Msef/equipment) 

Equipment Types Factor Fugitives ! Vented Com busted i Total 

Reciprocating 

Compressors 

29,000 compressors 2,327 222 832 3,381 

102,500 MMHp-hr 658* 62.3° 240* 960* 

Total Pipelines (Gathering 1,620,000 miles 29.9 7.1 

Transmission, Distribution) 

37.0 

Separators !66.000 separators 10.2 180 20{) 

M&R Stations 207,000 : stations 154 0.202 154 

Transmission & Storage Station 2,175 stations 4,219 10,212 

Vessels/Piping 

14,430 

Turbine/Centrifugal 

Compressors 

1,540 compressors 9,530 268 164 9,962 

44,000 MMHp·hr 334* 9.4* 5.7° 349* 

Glycol Dehydrators 38,000 dehydrators 32.4 458 490 

Wellheads 272,000 wellheads 11.0 20.9 0.0 31.9 

Production Meters/Piping 377,000 meters 16.1 16.1 

Customer Meters 45,000,000 I meters 0.!28 0.128 

Gas Plant Vessels/Piping 726 plants 2,886 554 3,440 

Offshore Platforms I ,110 platforms 1,055 258 1,313 

Heaters 51,000 heaters 21.0 NegL 21.0 

Assumptions: See Table 4-8 

Note: * Mscf/MMHp-hr, not per equipment 

71 
Glycol dehydrators have high emission factors due to contributions from multiple 

sources on the dehydrator: the glycol vent, the glycol pwnp, fugitives, and pneumatics. The 

separator also has high emissions, mostly due to the high number of pneumatic devices 

associated with separators. Similarly, M&PR stations also have high emissions mostly due to the 

pneumatic devices associated with the stations. 

4.7 Accuracy Results 

The accuracy goal was to determine emissions from the natural gas industry to 

within± 0.5% of natural gas production. This goal was established based on the accuracy needed 

for constructing emission inventories for use in global climate change models and-for assessing 

the validity of the fuel switching strategy. Accuracy, which is made up of precision and bias, has 

been rigorously propagated through the calculations using techniques described in Volume 4 on 

statistical methodology.6 The propagation of error resulted in a calculated uncertainty of± 89.6 

Bscf (0.4% of gross production). However, this assumes that the errors are normally distributed 

and that there is no correlation between source categories. 

Since there are some correlated errors among categories, and since some 

categories might have lognormal distributions, the uncertainty estimate for the total emissions 

was modified. The effect of inter-category correlations was calculated, and the additional 

uncertainty was added to the tmcertainty total. In addition, the effect of lognonnal distribution 

assumptions was also calculated. A point midway between the result for normal and lognormal 

errors was used as a more reasonable conservative case than is the result based on the nonnal 

assumption. The midway point represents the possibility that there is asymmetry in the 

distribution of the error in the industry emission rate. \Vhile the selection of the midway point is 

arbitrary, it is considered a reasonable postulated conservative case, given the various issues 

discussed in the Volume 4 on statistical methodo!ogy.6 

72 
Therefore, with asstunptions of inter-category correlations and some lognormality, 

the uncertainty is calculated to be ± 104.6 Bscf, which is slightly under 0.5% of national 

production. The conclusion is that, under assumptions that are not unrealistically conservative, 

the target precision was achieved. 

The project has reached its accuracy goal for the annual emissions. The objective 

of the project was to determine the overall national methane emissions, not to accurately 

determine methane emissions for individual equipment or processes. The emission estimates for 

source categories represent industry average values and are not meant to be representative of any 

company's individual emissions or operations. Also, although the project has reached its 

accuracy goal for the total emissions, the percent accuracy of an emissions estimate for a specific 

category will likely have a much wider confidence bound than the national estimate. 

73 
5.0 ANALYSIS AND CONCLUSIONS 

As presented in Section 4, the methane emissions estimate from the U.S. natural 

gas industry for the 1992 base year is 314 Bscf, which is 1.4% of gross natural gas production 

(i.e., 1992 gross production was 22,130 Bscf). 

As part of this program, a rigorous calculation of the lUlcertainty in emissions 

from the significant sources was made to help plan the program. An overall accuracy target of 

0.5% of natural gas production(± Ill Bscf) was set as a benchmark to address the fuel switching 

issue. The overall accuracy of the total methane emissions estimate generated from this program 

is± I 06 Bscf, or 0.5% of natural gas production. Therefore, the accuracy goal originally set 

forth for the program has been met (see Section 4.7). 

Methane emissions from all U.S. anthropogenic sources are reported in the U.S. 

EPA Report To Congress (RTC).' Excluding the gas industry. the report states that total U.S. 

anthropogenic methane emissions are estimated to be between 1190 to 1336 Bscf. Therefore, the 

methane 

gas industry (based upon the new GRJ/EPA estimate) accounts for !9% to 21% oftotal U.S. 

emissions. According 

Bscf), 

to the RTC, landfills (421 to 6!4 Bscf) and livestock (328 to 546 

each has higher emissions of methane (Figure 5-1). 

Natural Gas Systems 

200.4 

15% 

Livestock Manure 

9% 

Other 

6% 

Landfills 

31% 

----~Domesticated 

Livestock 

19% 

Figure 5-L Contribution of Major Methane Sources to Total 

U.S. Anthropogenic Emissions 

74 
The following sections analyze the results of the GRIIEP A study in various 

contexts. Section 5.1 uses the results to examine the validity of the fuel switching strategy. 

Section 5.2 compares the results to previous estimates. Section 5.3 discusses trends in the 

natural gas industry that have changed total emissions since the base year of 1992. Finally, 

Section 5.4 summarizes some of the key lessons learned during this study. 

5.1 Impact of Natural Gas Use on Global Warming 

The primary purpose of the GRJ/EPA methane emissions study was to help 

answer the question of whether the strategy of switching from other fossil fuels to natural gas 

would be successful in reducing global warming. To address this question, the amount of 

greenhouse gas released during the fuel cycle for each fossil fuel and the impact of these gases on 

the atmosphere are needed. For fossil fuels, only emissions of carbon dioxide (C02 ) and 

methane play a significant role. For methane emissions, it is important to account for emissions 

from the production of gas, oil, and coal and also from the transmission and distribution of 

natural gas. Methane emissions from the transportation and distribution of coal and oil are 

negligible, as are methane emissions from end-use combustion. Nearly all the C02 emitted 

results from end-use combustion of the fossil fuels. 31 Only 7 to 9% of the C02 emitted from 

natural gas is associated with upstream production, processing, and transportation, while I I% of 

the C02 emissions associated with oil are from production through product transport. 

Approximately 1% of the C02 emitted from coal is associated with production, processing and 

transportation. 42 

After determining the emissions of C02 and methane over the fuel cycle for each 

fossil fuel, the second step is to determine the impact of those emissions on global wanning. 

This is a difficult problem because C02 and methane behave very differently when released into 

the atmosphere~ they have different lifetimes and absorb substantially different amounts of 

infrared energy. As discussed in Appendix B, an index referred to as the Global Warming 

Potential (GWP) can be calculated that describes the impact of a given greenhouse gas on global 

warming compared to C02• The G\VP can then be used to convert emissions of one greenhouse 

75 
gas, such as methane, into equivalent quantities of C02• For example, if the GWP of methane 

was seven, then one pound of methane would have the same impact on global wanning as seven 

pounds of C02• 

The impact of greenhouse gases such as C02 and methane is dependent on the 

amount of infrared energy they absorb (referred to as their radiative forcing) and their 

concentration. Since the concentration is a function of time, the GWP is calculated by 

integrating the ratio of the impact of methane to the impact of C02 as the concentration of the 

gases decreases with time. 

The value of the GWP is highly dependent on the time period over which the 

integral is evaluated because the lifetime of methane is significantly 

C0

shorter than the lifetime of 

2• Some studies select a period long enough for concentrations of both gases to decrease to 

the original value (approximately 500 years), while others have chosen a shorter time period of 

50 to 100 years. The GWP for methane is approximately 6.5 for an integration interval of 500 

years, while the value of the GWP using a 50-year period is 34. Faced with such a large 

difference, two approaches were taken to examine the validity of the fuel switching strategy. 

The first approach is to determine the breakeven percentage. The breakeven 

percentage is the amount of methane that would have to be emitted to the atmosphere from 

natural gas operations in order for narural gas to have the same impact on global warming as 

coal or oil (i.e., the amount of methane that would have to be leaked to eliminate the inherent 

advantages that gas has because of its lower C02 emissions). Comparing the break:even 

percentage to the 1992 emission estimate provides an indication of the ad vantage that natural gas 

has over coal or oil. Likewise, the break.even percentage can be compared to the percentage of 

natural gas emissions resulting from an incremental increase in gas use to determine the validity 

of the fuel switching strategy. 

The analysis presented in Appendix B indicates that between 8 and 34% of the 

natural gas produced would have to be lost to the atmosphere for natural gas to have the same 

76 
impact on global warming that coal has, depending on whether the GWP was evaluated over a 

50- or 500-year time period. A similar comparison for oil indicates that methane emissions from 

natural gas operations would have to be between 5 and 23% of production to have the same 

impact that oil has on global warming. 

As discussed in Section 5.3.2, the GRIIEPA study not only evaluated emissions 

for the 1992 baseline system, but also estimated emissions from incremental increases in natural 

gas use ranging from 5 to 30%. The study found that incremental emission increases were 

proportionally less than the increases in gas usage for the scenarios examined. 

Since the breakeven percentages for coal (8 to 34%) and oil (5 to 23%) are much 

larger than even the upper limit of the percent of gas lost per gas produced from an incremental 

increase in gas use (i.e., 1.38% compared to 1.42 for the 1992 baseline) the breakeven analysis 

shows that switching from other fossil fuels to natural gas is a valid strategy for reducing global 

wamting. 

In the second approach, the amount of''equivalent" C02 emissions was evaluated 

for each fossil fuel over the fuel cycle by con~erting methane emissions to "equivalent" C02 

emissions. Since the GWP is a factor that relates the impact of releasing a potuld of methane on 

global warming to that of releasing a pound of C02, the GWP can be used to convert methane 

emissions into equivalent amounts of C02• For the fuel switching analysis, emissions are 

expressed as the mass of equivalent C02 emissions per unit of energy (based on the higher 

heating value of the fuel). Thus for an energy requirement of one million Btu, the equivalent C02 

emission contribution of each fuel can be compared. Table 5·1 presents the results of this 

comparison for GWPs of 6.5 and 34. (A more detailed discussion is presented in Appendix B.) 

Table 5-l also shows the ratio of equivalent C02 emissions per MMBtu for coal and oil divided 

by the value for natural gas. Tiris "equivalent C02 ratio" shows that oil has 1.2 to 1.4 times the 

impact on global warming compared to natural gas, and coal contributes 50 to 60% more 

equivalent C02 emissions than natural gas. 

77 
TABLE 5-1. EQUIVALENT CO, EMISSIONS 

I lbs CO,IMMBtu 

Fuel Source ~ 

I Equivalent CO, Ratio 

__________ 

I I_GWP=6.5 GWP=34 1 G\\'}'=6.5_j __ <;WP=34 

Gas ' 132 !52 1.0 1.0 __ , _____ 

Oil 

------- !84 186 1.4 1.2 -----

Coal 

------+--------

212 228 1.6 1.5 

An analysis of the fuel switching strategy based on examining the equivalent C0

emissions 

2 

from each fuel supports the conclusion reached by evaluating the fuel switching 

strategy using the breakeven percentage. Based on the results of both approaches, fuel switching 

is a valid strategy for reducing global wanning. This conclusion is consistent with the 

Intergovernmental Panel on Climate Change (IPCC) reporr'3 on climate change. 

5.2 Comparison to Previous Estimates 

This project began in 1989 by posing the following questions: I) "What are the 

methane emissions from the U.S. natural gas industry from the wellhead to the customer meter?" 

and 2) "Based on this emission estimate, is it reasonable to recommend switching from oil or 

coal to natural gas as a strategy for reducing the U.S. contribution to global climate change?" 

The project sponsors agreed that it would not be prudent to attempt to answer the second 

question unless an accuracy goal for the emission estimate of± 0.5% of gas production could be 

achieved with 90% confidence. An emission estimate with this degree of accuracy, therefore, 

became the project objective. 

A literature survey conducted at the outset of this project verified that previous 

studies contained insufficient data, individually or collectively, to meet the accuracy goals of this 

project. The majority of studies that were found during the literature survey employed a method 

common at that time in which "unaccounted-for gas" was assumed to be equivalent to losses to 

78 
the atmosphere.44•

45•

46•

47 "Unaccounted-for gas" is simply an accounting tenn which includes 

numerous categories in addition to losses to the atmosphere and therefore could greatly overstate 

gas industry losses. 

These studies were followed by a report written by Pipeline System Incorporated 

(PSI) and funded by EPA-OAR and GRI in 1990.48 The purpose of the early GRIIEPA study 

was to initially guide the more comprehensive GRl/EPA efforts that are presented in this report. 

The early PSI study produced an estimate showing that methane emissions were 1% of gross gas 

production. However, this study was only an attempt to identify major sources, and no emission 

measurements were made. 

A Report to Congress (RTC) by EPA estimated that methane emissions from the 

natural gas industry were between 0.55 and !.07% of gross production for 1990. 3 This study 

provided a reasonable synthesis of existing data at that time but did not expand the database. The 

need remained for an extended field sampling program and a statistical framework within which 

the data could be analyzed and accuracy targets could be calculated. 

The 140 Bscf difference between the emission estimates from the RTC (110 to 

220 Bscf) and the GRIIEPA study (307 Bscf) result from recent data that were not available at 

the time the RTC was written. The GRIIEPA study used new data to refine many source 

categories. The single category with the most significant difference was fugitive emissions, 

which accounts for almost 90% of the difference between the RTC and the GRI!EPA reports. 

The fugitive differences result from two major sources of new data: I) compressor components 

(82 Bscf difference), and 2) distribution sources ( 60 Bscf difference), such as pipelines, meter 

and regulation (M&R) stations, and customer meters. 

Compressor components, which are very large sources of fugitive emissions, were 

measured as part of the GRIIEPA study, but no measurements were available at the time of the 

RTC. Compressor components in processing, transmission, and storage facilities resulted in 

GRI/EPA estimates of 82 Bscf; these components had not been accounted for by the RTC. 

79 
The GRIIEPA report also refined the estimates for leakage from distribution 

pipelines and M&R stations through additional data gathering efforts. When the RTC was 

prepared, the only data available on pipeline leakage were for two very tight distribution systems 

M&R 

that had very little cast iron pipe. In addition, no data were available on the number and type of 

stations used in the gas industry. These data were gathered duting the GRI/EPA study. 

Also, emissions from customer meters, which were not included in the RTC, were included in 

the GRI/EP A study and measured to be 6 Bscf. The new GR!/EPA data show that the total 

distribution segment emissions are approximately 60 Bscfhigher than estimated by the RTC. 

5.3 Current and Future lndustcy Emissions 

Since the 1992 base year, emissions from the natural gas industry have changed 

because the amount of gas produced has increased and because gas industry practices have 

changed. In 1993 a joint industry-government program was started to reduce emissions. The 

impact of increased production and changes in practices is discussed in more detail in the 

following subsections. 

5.3.1 Industry Practices to Reduce Methane Emissions 

The natural gas industry has always been concerned with reducing natural gas 

losses. Every year the industry's practices continue to evolve and many companies have policies 

to recover gas or reduce losses. Examp(es are company programs to reduce losses through 

fugitive leak detection and repair programs (LDAR) for underground piping and above-ground 

facilities. Also as a result of this study, a number of companies became aware of ways to reduce 

operating costs while reducing emissions, and many of these companies are implementing 

cost/emission reduction pro grams. 

In 1993, a joint industry-government effort began. The Envirorunental Protection 

Agency (EPA), in conjunction with the natural gas industry, created the Natural Gas STAR 

Program to help reduce methane emissions from its major sources. 2 The Natural Gas STAR 

Program was established as a flexible, voluntary partnership to reduce methane emissions using 

80 
cost-effective practices. The EPA 49 and industry identified several best management practices 

(BMPs) in each sector of the natural gas industry, including: 

Distribution Sector 

• Implement directed inspection and maintenance programs at surface 

facilities 

• Identify and rehabilitate leak-y distribution pipe 

Transmission Sector 

• Implement directed inspection and maintenance programs at compressor 

stations 

• Consider use of turbines at compressor stations in lieu of reciprocating 

engmes 

• Identify and replace high-bleed pneumatic devices 

· Production Sector 

• Identify and replace high-bleed pneumatic devices 

• Install flash tank separators on dehydrators 

The program also facilitates technology transfer among partners on other practices 

that cost -effectively reduce methane emissions. As of April 1996 the program included 54 

partners. representing over 60% of all transmission pipeline. 30% of all distribution pipeline and 

25% of all U.S. natural gas production. As the new Producers Program (launched in March, 

1995) gets under way and as new distribution and transmission companies join, the program is 

expected to continue to reduce emissions of methane by 35 Bcf through the year 2000. 

81 
The gas industry may also decrease methane emissions 

with maximum 

in the future as it complies 

achievable control technology (MACT) standards for hazardous air pollutants 

(HAPs). The MACT rule will result in a reduction of certain hydrocarbon emissions and may 

also reduce methane emissions. However, the actuai impact of the MACT is unclear at this point 

in time, due to questions on the language of the final rule, the compliance schedule, source 

applicability, and the required control technologies. 

Since the Oil and Gas MACT Rule is scheduled for promulgation in !997, the 

only information publicly available is from the preliminary Background Information Document 

(BID)." The effect of the Oil and Gas MACT on methane emissions cannot be easily determined 

because the language of the MACT does not specifically address these emissions. The BID 

suggests 

HAP 

that glycol dehydrators and some sources of fugitive emissions will require controls for 

emissions. Depending on the kind of controls implemented by the industry for these 

sources, methane emissions may be reduced as well. 

The preliminary draft MACT proposes that equipment leaks at major sources, 

including gas processing plants and offshore platforms, must be controlled by a LDAR program. 

If this requirement becomes part of the final rv!ACTrule, methane emissions from fugitive 

sources in the gas production and processing segments wili decrease. 

5.3.2 Incremental Increases in System Throughput 

As part of this program, a study was conducted to determine the percent increase 

in emissions caused by an incremental bcrease in natural gas production and sales. 18 The study 

found that increases in throughput did, in many cases, produce increases in emissions. However, 

the average increase in emissions was proportionally smaller than the increase in system 

throughput. 

82 
This study examined the consequences of increasing gas sales by 5, 15, and 30 

percent under three scenarios: uniform, winter peak, and summer peak load profiles. All 

segments of the gas industry were examined to determine the percent increase in equipment that 

would be needed in order to meet the increased demand. The percent increase in emissions was 

then estimated based on changes in the current system that would be required to accommodate 

the increase in gas sales. The GRI/EPA's emission estimates were used to calculate the percent 

increase in emissions that would result from an incremental increase in natural gas sales for 

several scenarios examined in the study. The most realistic scenario assumes that the system will 

be expanded using current technology, whereas the most conservative scenario asstunes that the 

expanded system mirrors the existing system. Generally, emissions would only increase 2% to 

21% for corresponding load increases of 5% to 30%. The incremental methane emission 

increases, when divided by the incremental production rate increases, result in emissions per 

production percentages of0.3 to 1%, which are only one-third to two-thirds of the base emission 

rate (1.42% for 1992). Thus, the incremental emission increases are proportionally less than the 

load increase for all scenarios examined. (Results are explained further in Appendix B.) 

5.4 Lessons Learned for Future Studies 

The project team learned some key lessons during this multi-year project that may 

benefit other similar studies. The key lessons learned are grouped below in two categories: 

sampling/statistical methods and measurement methods. 

5.4.1 Sampling/Statistical Methods 

Because of the complexity and diversity of the natural gas industry, a detailed 

plan was implemented to meet the goals of the program. 27 Some of the procedures used in 

sample selection and statistical methodology were developed/implemented specifically for this 

program but would have potential utility in other similar studies. These sampling/statistical 

methods include: 

83 
• Sampling technique that is dependent upon the source population; 

• Sampling techniques and statistical methods to minimize bias in a dataset; 

• Use of accuracy targets to plan the program and allocate resources; and 

• Statistical tests to handle small datasets that are highly variable. 

Sampling Technique/Bias Minimization 

Because of the complexity and often unknown equipment populations for a given 

source within the gas industry, the selection of a proper sampling approach was not 

straightforward. For some sources, such as production separators, even the population size was 

not knovm at the onset of the program. These factors made the selection of representative 

samples for measurement or observation difficult, and traditional sampling methods, such as 

random or stratified random sampling were not directly applicable in most cases. Therefore, an 

alternative approach, which is similar to disproportionate stratified random sampling, was used. 

The sampling approach included selecting sites from known lists of facilities in as 

random a fashion as possible. However, the companies contacted were not required to 

participate and a complete list of all sources in the United States was generally not available; 

therefore, site selection was not truly random. Companies that elected to participate were asked 

to identifY potential sites that were considered representative of company-wide operations. 

The limited data set collected was screened for bias by evaluating the relationship 

between the emission rate and parameters that may affect emissions. The data set was then 

stratified by the parameter(s) found to significantly influence emissions. Because the sample· set 

collected was not necessarily representative of the nationwide proportions of sites in each strata, 

an emission factor per strata was produced along with an activity factor per strata to eliminate 

bias in the disproportionate sample set. 

84 
Other techniques employed to minimize bias included evaluating regional 

differences in operating practices or gas composition. In many cases, regional differences were 

found and had to be accounted for in the emissions estimation approach. A group of industry 

experts was used to review the data and approach for estimating emissions, so that any additional 

biases could be identified and eliminated. Industry experts from each segment and other 

reviewers were called upon to regularly review the project sampling approach, extrapolation 

techniques, and preliminary estimates. These reviewers identified potential biases that were 

eliminated through changes to techniques or through additional data collection. 

Use of Accuracy Targets 

To effectively allocate resources within the budget constraints of the program, 

accuracy targets were established for each emissions source such that resource could be assigned 

to emission sources based on the impact of each source on accuracy. An overall target accuracy 

was set for the industry-"Wide methane emissions estimate, and individual source target 

accuracies were calculated based upon overall accuracy goal. Target accuracies were set so that if 

individual source accuracies were met, the overall accuracy for the project would be met. The 

individual source accuracy targets were calculated based on precision estimates of the activity 

and emission factors. After the individual source target accuracies were calculated, the required 

number of additional samples needed to meet the target was calculated. By setting accuracy 

targets for individual sources, small, highly uncertain sources of emissions could then be 

appropriately handled. This process was used continuously throughout the data collection phase 

of the program to help direct the most efficient use of resources required to meet the overall 

program goal. 

85 
5.4.2 Measurement Methods 

A number of unique measurement methods were developed and tested as a result 

of this program. Many of these methods are applicable to sources outside of the natural gas 

iniustry. The most noteworthy of these are listed and described below: 

• High flow device for fugitive emissions measurements; 

• Tracer gas measurement method for estimating emissions from meter and 

pressure regulating stations; 

• A cooperative effort between industry and GRJ/EPA in measuring 

emissions from underground pipeline leaks; and 

• A detailed mass balance approach for system-wide emissions from a 

sample transmission network. 

High Flow Fugitives Measurement Device 

At the beginning of the GRI/EPA methane emissions study, it was clear that new 

component emission factors would be needed to evaluate fugitive emissions from gas industry 

equipment. The factors developed by EPA in the 1970s for natural gas production facilities were 

no longer applicable because of the changes that took place in the industry over the past 15 to 20 

years. In addition, emission factors for gas processing, transmission and distribution equipment 

were needed since these had not been developed previously. 

The standard EPA approach for determining emission factors uses a combination 

of screening and enclosure methods. First, all components are screened using an organic vapor 

analyzer (OVA) to determine which pipefittings are leaking and to measure the maximum 

concentration at the point of the leak. This is done for thousands of components at sites 

throughout the country. The leak rate is measured using the enclosure method for hundreds of 

leaking fittings of each type. A correlation equation is developed that correlates the 

86 
concentration value measured with the OVA with the emission rate measured using the enclosure 

method. The correlation equation is then used to calculate the emission rate for all components 

based on OVA readings, and an average emission rate (i.e., emission factor) is calculated for 

each type of component. 

The problem is that the scatter in the concentration versus emission rate data is 3 

to 4 orders of magnitude. Because the correlation is poor, thousands of measurements are 

needed, and this is time consuming and expensive. Therefore, GRJ ftmded a study to develop a 

new instrument that could accurately measure the emission rate directly in about the time 

required to measure the concentration. Tbis method was used not only for developing emission 

factors for production equipment, but also for processing, transmission, and distribution. 

The new instrument, called the GRI Hi-Flow sampler, can also be used to reduce 

operating cost. Since it provides a quick accurate measurement of the leak rate, the operator can 

determine if it is cost effective to fix the leak. It also can be used to accurately measure the 

fugitive emissions from a facility and determine whether the facility is subject to regulations and 

costly control and reporting requirements. 

Tracer Gas Measurement Method 

Tracer techniques were developed to measure methane emissions from sources of 

widely varying sizes and types. These sources included single regulator installations (above 

groillld and below ground), city distribution M&PR stations, transmission tie-in points, 

transmission and production facilities, industrial gas users, municipal wastewater treatment 

facilities, landfills, and total city emissions. 

The principle for each of these emission measurements was the same, but the 

application varied depending on the scale of the measurement. In each case, the tracer was used 

to measure the dilution of the methane from the source as it was transported to the receptor where 

87 
concentration was measw-ed. For undergrotmd vaults and enclosures of single above-ground 

regulators, air was flushed through the enclosed volume. The methane emissions were measured 

by measuring the resulting dilution with a tracer released at a known rate while measuring both 

the tracer and methane concentrations. For larger sources such as M&PR stations, gas plants, 

and landfills, tracer was released at a known rate from an area inside the source boundaries, and 

the tracer and methane were measured at a dowmvind distance where the tracer and methane 

were well mixed. This again provided a measurement of the dilution of methane as it was 

transported from the source to receptors and allowed the calculation of the source strength from 

the ambient methane concentration. 

Several lessons were learned concerning 

work. 

the application of tracers during this 

Real time instruments were used to track both the methane and tracer plumes and helped 

to identify interfering sources, to determine appropriate sampling points, and to integrate the 

plumes from very large scale sources such as landfills and cities. Measurements were validated 

using teclmiques developed in past studies which included comparing results from samplers at 

different crosswind locations in the methane plume, comparing plume traverses at different 

downwind distances, and conducting replicate measurements with different tracer source 

configurations or under different meteorological conditions. 

Tracer emission measurement techniques have both advantages and disadvantages 

compared to techniques 

measurements 

that measure emissions from individual components or flux chamber 

made at landfills or treatment plants. The accuracy of the tracer technique is 

susceptible to some meteorological conditions and interferences from other sources. However, 

the tracer technique can provide the total site emission rate in a fraction of the time (a few hours 

under the appropriate conditions) that is required using individual component techniques or flux 

chambers. At a natural gas facility, this total emission rate will include non-fugitive sources such 

as compressor engine exhaust. Measuring total emissions proved to be an advantage in this 

study because it was used to detennine if any sources were missed by comparing the swn of all 

known fugitive vented and com busted emissions to the total value measured using the tracer 

88 
technique. It was found that leakage from the blowdown valve was overlooked by the component 

measurement method because it was directed to a roof vent system. 

Due to the inherent uncertainty of the component screening techniques originally 

used for the individual component measurements, the tracer method was the most accurate 

method available for determining total emissions from a facility. The development of the high 

flow sampler during this project now provides a component measurement method of the same or 

better accuracy than the tracer method. Consequently, the best measurement method will often 

depend on the goals of the measurement work. Tracer techniques do not provide any data on the 

location or magnitude of sources within a site. For a natural gas facility, effective emissions 

reductions cannot be accomplished without knowing which components are leaking and how 

much each is leaking. However, these individual component methods are more time· consuming, 

have the potential to miss significant sources, and are not applicable to many sources. When 

trying to obtain as much data on total facility emissions as possible in the shortest amoilllt of 

time, tracer techniques may provide the best method of emissions measurement. 

Cooperative Industry Measurement Effort 

Early in the program, leakage from underground pipelines in the distribution 

segment was targeted as a potentially large source. A measurement technique identified as being 

very accurate was proposed for the GRIIEPA program. However, this technique was extremely 

costly to implement on a per test basis, and due to the population size and uncertainty in 

emissions, the estimated sample size to reach the target accuracy was very large. Therefore, 

GRJ/EPA solicited participation in a cooperative program between industry and the program 

sponsors to share the cost of collecting data. The GRl/EP A program provided a detailed test 

protocol, specifications for the measurement device, and training/auditing/support to the industry 

participants. The actual measurements were performed and funded by the companies agreeing to 

participate in the program. This cooperative effort proved to be a successful means to meet the 

objectives within the budget constraints of the GRliEPA program. 

89 
Mass Balance Measurement Approach 

An extremely detailed mass balance was performed on a sample transmission 

system to determine if emissions to the atmosphere could be detennined by examining the 

differences in upstre1Itl!downstream meter readings. This effort did not prove successful due to 

the many uncertainties in mass balance measurements that could not be completely resolved and 

emissions could not be determined to meet the accuracy target. 

5.4.3 Significant Sources 

much 

Several significant sources of methane emissions were identified or found to be 

larger than anticipated. Compressor blowdown valve fugitives, M&PR stations, pnewnatic 

devices, dehydrators, and maintenance emissions all were detennined to be larger than estimated 

by previous studies. 

90 
6.0 

I. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

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from Natural Gas 

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Docket No. A-94-04, 1994. 

95 

APPENDIX A 

Summary Table of Emission Sources 

A-1 
METJ.fANE EMISSION A/>!D ACCURACY STIMATES 

Percenl Percent --- _ _M_ivi!Y_ --- ____ Emlssio'!_ __ [)pp;< Precision Conserva~ve Tarll"t 

ROCESS SEGMENT 

"" "" ol T<tat or Total Uppo!r ol A,.,ual Preci5ion Precision 

Emission Type Emissrons Emfssions Emluio"* Productton Vo"" Units &ooo Valu• Units &o"' Emissions Ql ,l,nnual 

"'' 

Source 

"" '''"' "" ,:, ., ., 'PRODUCTION 

Em I,~ ions (o( 

Normal Fu~Wves 

Gu WeHs (Eutem on shore) 

"""' """ 0.11 0""' 129.1S7 ~'" "' 7.11 '"'"'-" "" 27.49% ",. 1077 82 

Field Separation Equipment 

(Eastem on ohO!ot) 

Heatef10 00000 0.0013 0.00 

"""' "" hulers 

""" 14.21 sc!dll!eaw ,,. 217 ,6.(% 423.13% >"0000 

Separatofll 0"""' 0.0301 

"'' """' lii1,870 Sl!parators ,. 0., scfd!!.eP ,. 3601% 4274% """00 

Gathering Compres~ 

Small Ree<p Compr 00000 0"""' 000 o= 129 C<>mJ>f"S'<><S ,. 12.1 sddlwmp 

"' ~3-~ 53~S'llo "OOOO 

Me!<trs!Pipin-g 0.0048 0""' O.M 000) 78.282 melers 

'"" '"' ocl<llme!<tr 

- 106.83'!1. 189.02'!1. 124802 

Oeh)'df111or5 o= 000" 0.00 o= 1,0-47 dehydratora 

- 21.75 scl<lfdehv 

'" 401iJ1'!1o 41i183% 1500.00 

Gas Wells (Rest o1 US on ollofe) 00365 

'""' ""' '-""' 142,771 ~'" " 36.40 '"""-" ,.. 24~% 27.85'!1. 453.08 

Gull ol Me•lco {oll$ho,-e pnttms) 0.0223 11815 

"" O"" '·"" platform• ,,. "" Sddlplat 

"" 2892% 33.24% 571iJ01 

R""l of US (offsho•e ptalforms) 

"'""" 0- 000 0.000 

" platla<ms 

"'' 1178 Sddlpla! , .. 3754% 4486'!1. "0000 

Field Separation Equipment 

{Res! ol US on shOrfO) 

Healers 0.020!1 

'""' "'' O"" 50,740 

-- "" 57.7 sctdlhealer 

""' "'"'"' 171.56'!1. 

""" Separa!o<s 

""" ""' '"' O.Q15 74,074 S40poof11tor. ,,. 122.0 -KO ,,. ~- 93.05'!1. 342.20 

Oau.erln; Compreooo .. 

SmaiiReclp_ Compr. 0.0318 

"'" "'' ow 18,915 compreo-. ,. 267.8 

__ , 

'" 9262'!1. 137.08% 

"'" LarueReclp Compr 00102 0.5328 0.17 0002 98 compressors 

'"" 15205.0 llddlcomp ... 135.83% 22742% 

"""' lgrg:B Rec\p. Station• 0.0007 

""" OOl 0000 

" st&~ons 

'"" 82470 scldl&t&t<on 

'""' 175.52'!1. 319.62% """00 

Mfllers/Pip<ng 0.1118 5.8153 

"' 0.028 301,180 mete .. 

'"" "' scfd/meters 

""' 10663% 189.02'!1. 

"'"' Oeh)'drato!$ 0.0235 1.mt> 0.39 

"""' 3$,177 d&h)'d .. lors 

""' 91.1 scl<l/dehy ,. 32.41)% 37.64% 

"'" P1pe!ine leaks 

"'"' '"'"' 2.10 0.030 ~0,200 mile• 

""' "' scl<l/mile 107'!1. 106.00ll. 18772% 24289 

Vented and combuoted 

O.olllna and Well C..mpletion 

Completion Flarl"'f 00000 

'"""' 000 0.000 ... _., "'" '" soflcompl 

""" 20125% 382 35% "0000 

Nermal OptO<ations 

Pneumatic O...Oce Yen~ 0''" 31.3948 ... 0.142 249,111 

~-· ... '" Sddldw.i<:e 

""' ..... a7.10'!1o 111.37 

Chtlmicallnj PumJ>I 

'""' 1.5365 0.49 0.007 18,011 eel"" purnso-

""' '""' Sddlpump .,. 20353'!1. 

"'"" 50341 

KimrayPumps 0.2106 10.9616 

'" '-""' 1. 10SE+07 MMscflyr 

"" .... 00 BcliMMscl ,,. 11003% 171 90'!1. 166.47 

Deh)'dralor Yen~ 00657 l4171 

"" 0.015 1_240E+07 ..... , "" 27557 BcliMMsc! ,, .. 19190% 359.36% 33757 

Cr>mpreosor e:.l>aus! Veoled 

Gas Engines 0.1287 

'""' 2.10 

"''"' 27,480 MMHPIIr 

'""' "'"' &<:1/HP~r 

"' 20031% 

""''"" 24307 

Routine Ma1nte<>ance 

WaiiWorkwe"' 

GuWelJs oooo• '"'"' '"' 0.000 9,3~2 w.o/yr ,,. 2.454 ldylwo. 

·- ""'"'" 2746.84'!1. 1500.00 

Well Clean Ups (lP Gu Wds) 0.1068 5.657lil '-" 0""' 114,139 tPgu-'* ... 49570 ldyll.Pwell , ... 37990'!1. 634.58% 262.34 

Slowdowns 

Vest-eiBD 0"""' 00>00 

'"' 0.000 255,996 ves•els ,.. " ,.,.., - 21807% 57110% 1500.00 

Pipo!lme BD o= 0.1051 

"'" 0000 ,.,,000 m1l,..(ga!h) 

""' "" SctylmiiB 

"" 3366% 39.56% 1500.00 

Comp~»or90 00012 0""" 0"' 0000 17,112 comp,_rs 

'"' 3714 Scfylcomp 147% 173M% 315.14% 1500.00 

Conlpressor StJrts 0.0028 0.1445 

"" 0.001 17,112 CO<nPie5SOfS 

'"' "" Scfv/comp 157% 184.44% 3-41 16% "0000 

Upoeh; 

P<essur• Rella! Valve• 0000, 00180 0.01 ·= 520,44(J >RV ,,. " """"' '"" """"' ...... "0000 

"D '""" 0.2664 0"' 000) 1.115 platfotms 

""' "'"" Scfvlplat 

"""' 20125% 

"'"" 11~: Mosh~ s Oi -Ins 

"'"'" 02275 

""' 000) "0000 m1ln 

""' '" soflmilel_r; 1925'!1. 193.-.63% 376e6e% 

""' 

w Based on a Iota! g ross national p <oduction of 22132 9scf fa< 1992. 

(b) Pre<;,$>On l>asod on a 00% conMence inre~ 

(c) T~rg~!Preclslon = 100"(8_24/SQRT(ER)). where £R = eml$•tons 

Maximum Relallvl!r Catrg:ory TP 

in 9scf. Overall TPis +I· 110M 9sc:l' 

15 •I· 1500%. Mlnlmun Relative category TP Is +I· 75'11., where TP = targ8l p<eclslon 

{d) Con!.ervalive P""'lsion based on uppef lima of a 90'!1. confidence Interval. This conli<lence ln!erval is based on a lognormal assumpilon 

6SCF EMISSION R~PORT !(:11!6196 
Emission Type 

Sourct~ 

Val~ .. Units Units 

"' pl~nl5 

Reclp, Compressors '~ scfdlplanl 

4,092 compreosors 

Cenlr!l~;al Comp;enors 

11198 scld/comp 

"' COinp!ISSOf$ 

'""' Vented ~nd Com bulle<:! 

Wd/comp 

Normal OperalioM 

Comprt~ssor Elchaust 

GnEng,nes 

Gas Turbin~s 

27,760 MMHPhr 0240 WIHPhr 

AGRVun!s 

32,910 MMHPhr 0.0057 sc!IHPhr 

"' AGRunltt. .., 

.,,.., ocld/AGR 

··- sc!IMMocf 

8,630,000 MM5df"' wf/MMsd 

"' gas plants ocf)l/pl~nl 

BSCF EMISSION REPORT W!MIG 
Emission Type 

,.,~ 

Fug'ollves 

Pope/me L..ai<s 

Comp~essor S!afoons (TRANS) 

Station 

Recip_ Comp"'ssor 

~n~ifuy~l Compressor 

Comp"'UOl Stations (STOR) 

S!a~on 

Reclp Comp'fiSO< 

~nhituga! Compressor 

W<~Hs(STOR) 

M&R (rrano Co.lnteramned} 

M&R (Farm Upt. + Dired S.ln) 

Ve-nted am! Combusted 

Normal ()peor•tlons 

Dellydrator vents {TRANS) 

Dehydrator Vents (STOR) 

Compressor &h~usl 

!SCF EMISSION REPORT 10116.96 

Enginn (TRANS) 

TUrbines (TRANS} 

Engines {STOR) 

Turhlnes {STOR) 

Generators {Engi1l<l~ 

Genetalol'$ {Turb4""s) 

Pneu<rn~lic Devices 

"" '""' 

' ' 

Units Unfts 

.... 1541 scldlmilto 

1,700 ...... !778 &d<l/sllllicn 

'·"' comp_ 

""" llefdlcomp 

'" -· '"" llef<l/e<>mp 

"' sllllono 21507 scfdJstatk>n 

1,398 

-· ,, 

21118 scfdleomp 

-· "'" eddiC<Imp 

11.999 

-· 1145 

"""""" 2,533 station• 

"" llef<!lstation 

72.830 

'""""' "' scfdleta~on 

""""" 93.72 

MMW¥ """"w 117.18 6CIIMMscf 

~.,., MMHP!lr 0240 6CIIHPhr 

'·"' MMHPhr O.G057 

"""""' 4,922 

"""'"' ""' scfiHPhr 

"" MMHPII< 

""'' scfiHPhr 

1,978 MMHPhr (l_2«) scfiHPhr 

23.3 

"""'" OJJ057 scf/HPhr 

87,208 "....__ 1C21i17 $Ciyld...;ce 

miles 

+/. 110_86 Bocf_ 

, where TP = ta:rg-ot predolon. 

lnloNIIIIs band on • lgg-oormal Hsumplion. 
Relative 

, 

Category 

100'(8 ;,>4/SQRT{ER)}, where ER,. emi•$ion~ In 81;(:!. CM>oall TP IS •I· 11086 8&ef 

{d) Ccn~eMt!i•e pree<•lon 

TP lo +/- 1~. Mlnlmun Relative Cat@GoryTPI• #· 75%. Mlere TP ~ ta'ltel preciSIO<l. 

b.as<>d on upper !lmlt of a 90% confidence ln!e,....al. Thlo ccn!.dtnct~ln!ervalll based on a logoorm•l assumption 

!lSCf EMISSION REPORT IOJ!$00 

APPENDIXB 

Effect of Methane Emissions on Global Warming 

B-1 
B.O EFFECT OF METHANE EMISSIONS ON GLOBAL WARMING 

Based on the recent climate change reports by the Intergovernmental Panel on 

Climate Change (IPCC), "switching from coal to oil or namra! gas, and from oil to namra! gas, 

can reduce (greenhouse gas) ernissions." 1 The GRIIEPA study to estimate methane emissions 

from natural gas operations was undertaken primarily because this information was needed to 

determine if it makes sense to promote the increased use of natural gas as a strategy for reducing 

greenhouse gas emissions. This appendix attempts to put the results into perspective by 

examining whether the current estimate of methane emissions from natural gas operations is 

likely to affect this fuel switching strategy. 

Carbon dioxide contributes as much to global wanning as all other greenhouse 

gases combined. Namra! gas emits substantially less C02 per unit of energy generated than 

either coal or oil. 1 However, methane, a more potent greenhouse gas than C02, is also emitted in 

the production, transmission and distribution of natural gas. The question raised was whether the 

fuel switching strategy is valid when emissions of all greenhouse gases are considered over the 

complete fuel cycle (production through end use combustion). To address this question, it is 

necessary to account for emissions of all greenhouse gases throughout the fuel cycle and to 

determine the impact of these gases on global wanning. 

Fortunately, in evaluating fossil fuel emissions, emissions of greenhouse gases 

other than methane and C02 are negligible and do not need to be considered. In addition, most 

of the C02 emissions result from fuel combustion and are accurately known. The uncertainty in 

estimating C02 emissions from production and transportation of the fuel is higher, but this is a 

relatively small value and does not have a large effect on the overall accuracy of the analysis. 

Estimates of methane emissions from natural gas operations prior to the GRJ/EPA study 

generally ranged from 2 to 5% of production.2

.3·4

,s The uncertainties in methane emissions from 

coal and oil production were equally as large. Although the uncertainty in emissions is still 

relatively large, the largest uncertainty in addressing the validity of the fuel switching strategy is 

B-2 
in determining the relative impacts of C02 and methane emissions on global warming. In order 

to simplify a comparison of the impact of one greenhouse gas with another, a global wanning 

potential (G\VP) has been defined.6 The G\VP is an index that relates the impact of a given 

greenhouse gas to an equal amount (by mass) of C02• The projected effect on global warming of 

a greenhouse gas over a chosen time horizon can be estimated by multiplying the appropriate 

GWP by the amount of gas emitted. Considerable work has been done in this area by the 

Intergovernmental Panel on Climate Change (IPCC). However, as discussed below, the 

uncertainty in the GWP is still very large. 

B. I Global Warming Potential 

Although a trace gas can have a strong radiative forcing per molecule, its 

greenhouse heating potential depends on its lifetime and the rate at which it is injected into the 

atmosphere. The G\VP for a trace gas addresses the net effect of the radiative forcing and the 

lifetime of the gas by calculating the time integrated radiative forcing of a mtit mass impulse to 

the atmosphere.6 The G\VP is defined as the impact on global wanning caused by an incremental 

amount of a given greenhouse gas divided by the impact of releasing an equivalent amount of 

C02• The GWP for methane can be approximated by the following equation: 

i:' ACH CCH dt 

• • GWPM (Bl) = 

t, 

A C dt 

t col C02 

0 

where A ~ radiative forcing per unit mass 

c ~ concentration 

CH, ~ subscript designating methane 

co, ~ subscript designating C02 

t., ~ time of release 

(t,-t.,) ~ time period over which the GWP is evaluated 

B-3 
where 

The concentration is often approximated by the expression: 

t 

;. 

time; and 

!/lifetime 

C = e-lt 

(B2) 

In addition to the direct effect of methane on global warnring (the radiative 

forcing due to methane itself, as given above), methane can also contribute to the fonnation of 

other greenhouse gases such as tropospheric ozone and water vapor in the stratosphere. These 

indirect effects of methane must be added to the direct effect to detennine the total contribution 

of methane. 

IPCC has published the results of studies to evaluate the GWP for the various 

greenhouse gases. Their findings in 1990, 1992, and 1994 are shown in Table B-1 for the direct 

effects of methane for different integration time pericxls (t -tJ. ~·9 The GWPs for methane, 

including both the direct and indirect effects, are also presented in Table B-1 for 1990, 1994, and 

1995. Because the IPCC believed that the uncertainties in the indirect effects were very large, 

they decided not to publish a total GWP for methane in 1992. The change in values from 1994 

to 1995 reflects a change in the lifetimes of gases that react primarily with tropospheric hydroxyl 

radical (OH) concentration, based on a revised estimate in the mean global OH concentration.6 

B-4 
TABLE B-1. GLOBAL WARMING POTENTIAL OF METHANE 

Integration Interyal (years) 

Direet Effects Direet and Indirect Effects 

Year 20 100 500 20 100 

1990 35* 11 4 63 21 

1992 35 II 4 

1994 43-52 12-21 5-6 62 ±20 24.5 ± 7.5 

1995 56±20 21 ± 7.4 

"'A value of35 indicates that one pound of methane has the same effect. as 35 pounds of C0

-Data not available 2 

500 

9 

7.5 ± 2.5 

6.5 ± 2.3 

As implied by the variations in the values shown in Table B-1, there are 

significant uncertainties in the GWP for methane. Some of these uncertainties result from 

differences in the models and mode! limitations. In 1990 and 1992 the lifetime of methane was 

determined by calculating the decay rate while the composition of the atmosphere was held 

constant. In the 1994 and 1995 calculations, the atmosphere was allowed to respond to the 

change in methane by coupling the methane chemistry to the calculation of the radiative forcing. 

This resulted in a reduction in the OH concentration. Since OH is primarily responsible for the 

oxidation of methane, the lifetime of methane in the atmosphere increased. The effect of 

including the chemistry was initially thought to be small, but as shown in Table B-1, the 1994 

GWPs increased by approximately 35 to 50%. The change in GWP from 1994 to 1995 includes 

a decrease of about l 0% based on an improved estimate in the concentration of methyl 

chloroform which is used as a reference compound in determining the mean global OH 

concentrations. 

Other issues could also have significant effects on the calculated GWP when they 

are eventually addressed. Some examples are: 

B-5 
• The size of the incremental 

methane 

increase in methane. A relatively large pulse of 

is used in the models to evaluate the GWP. Because the chemistry 

is highly nonlinear, a large pulse can generate a nonlinear change in the 

lifetime of methane that would produce a much larger GWP than using a 

small pulse. 

• Grid size. Emissions ofNO" and other gases are smeared over large grid 

cells and are artificially diluted. Because NO/methane/ozone chemistry is 

highly nonlinear, this could have a significant effect on the tropospheric 

ozone calculation and the evaluation ofindirect effects of methane on GWP. 

• Nonmethane hydrocarbons (NMHCs). NMHCs are not included in the 

current models. Since most NMHCs are more reactive than methane, the 

impact of increased methane emissions on tropospheric ozone could be 

overstated. This would cause an erroneously high value for the indirect 

contribution to GWP for methane. 

Of all the parameters discussed, however, the parameter that has the largest effect 

on GWP is the time interval (t1-tJ used in evaluating GWP. There is not a consensus on the 

proper value, particularly between policy analysts and scientists. Some policy analysts use a 

time interval as short as 50 years. For methane, the time interval is an important question 

because there is a large difference in the lifetime of methane (approximately 12.2 years± 25%) 

and the effective lifetime of C02 (200 to 250 years). If a time period of 50 years is selected, the 

GWP calculated by the IPCC would be approximately 34. The implication is that one pound of 

methane released into the atmosphere would have the same impact on global wanning as 

34 pounds of C02• The problem is that this is only true for the ftrst 50 years. The amount and 

percentage of methane and C02 in the atmosphere based on releasing 34 poWlds of C02 for each 

pound of methane (i.e., a GWP of34) is presented in Table B-2 as a function oftime after 

release. At the end of 50 years, the methane concentration would have decreased to a negligible 

level, but approximately 80% of the C02 would remain in the atmosphere and stili contribute to 

global warming. 

B-6 
TABLE B-2. AMOUNT OF CO, AND METHANE REMAINING IN 

ATMOSPHERE WITH TIME 

Greenhouse . Time (Yrs.)' Gas. . 20 50 100 

%CH

%C02 90 78 61 

4 19 1.6 0.03 

lbs. C02 b 31 26 21 

lbs. CH4 0.19 0.02 --

a Lifetime of methane and C02 used were 12.2 and 200 years, respectively. 

b Assumed GWPM- 34. 

500 

8 

--

3 

--

If a 50-year time interval is used to develop emission trading policies, then 

I pound of methane emissions could be traded for 34 pounds of C02• The problem is that after 

50 years the 1 pound of methane would have decayed to less than 0.02 pounds, but there would 

stili be 26 pounds of C02 remaining in the atmosphere. A century later, 21 pounds of the 

original34 pounds of CO, released would still be contributing to global warming. These 

contributions of C02 are neglected by choosing a time period of 50 years. 

In considering the impact of using different types of fuels, the time interval should 

be chosen so that both gases (in this case methane and C02) would have time to decay to 

negligible values. This suggests that the time interval for evaluating the GWP for methane 

should be in the range of 500 to 1 000 years. 

There currently is not a consensus on the integration interval. Because the GWP 

could be as low as 6.5 for a 500-year integration interval and as high as 34 for a 50-year interval 

(over five times larger), two approaches were taken in this analysis to examine the validity of the 

fuel switching strategy. In the frrst approach, a breakeven percentage is calculated. The 

break even percentage is the amount of methane that would have to be released during the natural 

gas fuel cycle to eliminate the advantage that natural gas has over coal and oil because of its 

lower C02 emissions. The breakeven percentage can be compared to the 1992 emission 

inventory for the natural gas industry to evaluate the relative advantage that natural gas has over 

B-7 
coal and oil. This approach is presented in Section B.2. In addition, to deterntine the validity of 

the fuel switching strategy, the break:even percentage can be compared to the percentage of gas 

leaked due to the incremental increase in gas use that results from fuel switching from coal or oil 

to natural gas. This is presented in Section B.3. The second approach, presented in Section B.4, 

is to evaluate the amount of equivalent C02 emissions for each fossil fuel over the fuel cycle by 

converting total greenhouse gas emissions to "equivalent C02." 

B.2 Breakeven Percentage. 

The first approach for evaluating the fuel switching analysis requires comparing 

the breakeven percentages of the various fuels. The breakeven percentage (BP) is the amount of 

methane that would have to be released in the production, distribution, and end use of natural gas 

for it to have the same impact on global wanning that the fuel cycle of coal or oil would have. 

The breakeven percentage can be calculated knowing the GWP for the different greenhouse 

gases and the amount of each greenhouse gas released per unit of energy from the fuel cycle of 

natural gas, coal. and oil. The equation used is given below. along with the parameters used in 

the calculation. 

BP 

(Bll) 

where E = pounds of C02 emitted from the fuel cycle for !06 Btu of fuel 

G = pounds of methane in 106 Btu of natural gas 

EM; = pounds of methane emitted from the fuel cycle for I 06 Btu's of fuel 

"i" 

GWP = global wamting potential calculated on a mass basis 

= subscript denoting type of fossil fuel ( c for coal, o for oil) 

NG = subscript denoting natural gas 

B-8 
M subscript denOTing methane 

The results for coal are presented in Figure B-1 as a function of the GWP. Table 

B-3 presents the breakeven percentage for oil and coal based on IPCC's GWPs calculated for 

various time intervals, using the following values. 

G = 38 pounds per MMBtu, based on an HHV of I ,031 for natural gas 

and a methane composition of93.4% 

E, = 208 pounds per MMBtu 

E,;G = 127 pounds per MMBtu 

Eo = 184 pounds perMMBtu 

EM, = 0.6 pounds per MMBtu 

EMo = 0.06 pounds per MMBtu 

TABLE B-3. BREAKEVEN PERCENTAGE (BP) FOR COAL AND OIL FOR 

VARIOUS GWP INTEGRATION INTERVALS 

Integration Interval G\VP BP BP ·,·:·(for t:oal) (for oil) 

50 34 8 5 

!00 21 12 7 

500 6.5 34 23 

As shown for a GWP of 6.5, approximately 34% of the natural gas produced 

would have to be leaked for natural gas to have the same impact on global warming as coal, or 

for oil, 23% of natural gas would have to be leaked to have the same impact. For a G\VP of 34, 

the percentage is approximately 8% for coal and 5% for oil. 

All the breakeven percentages are substantially larger than the percent of methane 

emitted from natural gas operations (1.42% of production for 1992). Tills indicates that natural 

gas has an inherent advantage over the other fuels for the 1992 base case. 

B-9 
30,---,-,----------------------------------------, 

25 

" 

.. 20 ,--

-

" 

c 

" 

" 

... 

~ 15 f- c 

" 

~ 

" 

"" 

" 

~ 

"' IO fSfGWP 

Figure B-1. Breakeven Percentage- Natural Gas Compared with Coal 

B-10 
For the fuel switching strategy, where natural gas consumption could replace 

some of the energy supplied by coal or oil, the breakeven percentage needs to be compared with 

the emissions that would result from an incremental increase in gas use. As will be shown in the 

next section, the incremental increase in emissions (above the 1992 baseline) are between 0.3% 

and 1.0% of the incremental increase in gas production, which is approximately one-third to twothirds of the base year methane emissions (1.42% of the total gas production rate). 

B.3 Emissions from Increased Gas Sales 

As part of the GRJ/EPA project, a separate study was conducted to detennine the 

percent increase in emissions caused by an incremental increase in natural gas production and 

sales. w This study examined the consequences of increasing gas sales by 5, 15 and 30% under 

three scenarios: unifonn, winter peak, and swnmer peak load profiles. 

All segments of the gas industty were examined to determine the percent increase 

in equipment that would be needed to meet the increased demand. The percent increase in 

emissions was then estimated based on changes in the current system that would be required to 

accommodate the increase in gas sales. GRIIEPA' s emission estimates were used to calculate 

the percent increase in emissions that would result from an incremental increase in natural gas 

sales for seven scenarios. The results ·are presented in Tables B-4 and B-5 for two cases: 

expected and upper limit, respectively. The assumption for the values listed Wlder "expected" 

was that the system will be expanded using the latest technologies. The assumption for the 

values listed under "upper limit" was that the expanded system mirrors the existing system (i.e., 

new equipment or technologies for reducing emissions are not utilized). 

For most components, facility and operating changes are not linearly related to 

increased gas throughput due to excess capacity or practices such as pipeline looping. Therefore, 

the study showed that an increase in gas use for either a system mirroring current technology or a 

system utilizing the latest technology would increase emissions by an amount less than the 

B-!1 
1;0 

' 

-

"' 

.· 

Total Emissions, Bscf 

% Increase over Base Case 

Total Emissions/ 

Total Gas Production Rate 

TABLE B-4. INCREMENTAL CHANGES IN EMISSIONS 

RESULTING FROM INCREASED GAS SALES- EXPECTED CASE 

Increased System Throughput (%) 

Uniform Load . Winter Peak 

Base Case 5 15 30. . 5 15 

314 319 328 343 320 333 

-- !.37 4.43 9.20 !.90 5.84 

1.42% 1.37% 1.29% 1.19% 1.38% 1.31% 

ll Emissions/A Production Rate -- 0.39% 0.42% 0.44% 0.54% 0.55% 

Total Emissions, Bscf 

% Increase over Base Case 

Total Emissions/ 

Total Gas Production Rate 

TABLE B-5. INCREMENTAL CHANGES IN EMISSIONS 

RESULTING FROM INCREASED GAS SALES- UPPER LIMIT CASE 

·.··. Incre•sed System Throughput (%) 

.. 

Uniform Load Winter Peak 

Base Case 5 15 30 5 15 

314 319 336 361 321 346 

-- !.37 6.98 15.0 2.12 9.98 

1.42% 1.37% 1.32% 1.26% 1.38% 1.36% 

A Emissions/D. Production Rate -- 0.39% 0.66% 0.71% 0.60% 0.95% 

. 

Summer 

Peak 

30 15 

352 324 

12.0 2.98 

1.22% 1.27% 

0.57% 0.28% 

Sbmnter 

Peak 

30 15 

380 331 

21.0 5.42 

1.32% 1.30% 

0.99% 0.51% 
percent load increase. For the expected system, total emissions (Bscfy of methane) increase by 

1.4% to 12% over the load scenarios examined for corresponding increases in gas sales of 5% to 

30%. The incremental methane emission increase (5 to 38 Bscfy), when divided by the 

incremental production rate increase (I, 110 to 6,640 Bscf natural gas), results in emissions per 

production percentages of 0.3 to 0.6%. For the upper limit case, total emissions increase by 

1.4% to 21% for the same scenarios. The incremental methane emission increase for these 

scenarios (5 to 66 Bscfy), when divided by the incremental production rate increase, results in 

emissions per production percentages of 0.4 to 1.0%. Compared to the base year emissions per 

production percentage of 1.42 %, the incremental emission rates ( .6.. methane emissions per .6. 

production volume) are only one-third to two-thirds of the base emission rate. The incremental 

emission percentages are much lower than the breakeven percentages of either coal (8 to 34%) or 

oil (5 to 23%) based on a GWP time interval of 50 or 500 years, respectively. Therefore, this 

analysis supports the validity of the fuel switching strategy. 

B.4 Equivalent C02 Emissions 

The second approach used to examine the validity of the fuel switching strategy is 

based on quantifYing the emissions of methane and C02 for each fuel over the fuel cycle and then 

converting the methane emissions to equivalent C02 by multiplying by the GWP. The GWP 

relates the radiative forcing of other greenhouse gases, such as methane, to the radiative forcing 

of C02 over a period of time, accounting for the changing concentration of the greenhouse gases 

over time. For a given fuel, the equivalent C02 emissions are calculated using the following 

equation: 

(B4) 

where: 

B-!3 
J 

Ea,, 

GWP, 

E ) 

= subscript that denotes the various fuel cycle operations 

(production, transportation, processing, and combustion) 

= 

= 

= 

subscript to denote the various greenhouse gases (GHGs) 

mass of C02 emissions (lb) per energy input 

global wanning potential used to convert emissions ofGHG, "j," 

to equivalent C02 emissions 

mass of other greenhouse gas emissions (Ib) per energy input 

This equation results in the total fuel cycle emissions by accounting for: 

1) End use C02 emissions from fuel combustion; 

2) C02 emissions by the industry resulting from the production, processing, 

and transportation of the fuel; and 

3) C02 equivalent emissions that result from industry methane emissions. 

For the purpose of the fuel switching analysis, equivalent C02 emission factors of 

the various energy sources are reported as the mass of equivalent C02 emissions per unit of 

energy. Therefore, for an energy requirement of one million B~ the relative contribution of 

equivalent C02 emissions of the various fuels can be compared. 

The energy content of the fuel can be expressed in terms of either the lower 

heating value (LHV) or the higher heating value (HHV). The difference between lower (or net) 

and higher (or gross) heating value is the heat of vaporization (lift) from the moisture produced 

during combustion, where the higher heating value includes this amount: 

llliV = LHV + nl>ft (H,O) (BS) 

where: 

n moles of water produced 

B-14 
heat of vaporization of water at 25 oc 

The difference between the higher and lower heating values can be significant 

when comparing the combustion efficiency from various end use equipment, since the latent heat 

is recovered by some end-use equipment, but not by all end-use equipment. For this study, the 

efficiencies of end use equipment are not considered. The fuels are compared on a higher 

heating value basis, which is the convention commonly U5ed in the U.S. and is also the 

convention used by IPCC. 1

•

11 The general methodology is shown in the following equation: 

Emissions (mass/yr) x HHV (mass) 

Marketed Fuel Production (mass/yr) fuel (MMBtu) 

Emissions (mass)(B6

) 

MMBtu 

C02 and methane are the only greenhouse gases, related to fuel use, that make a 

substantial contribution to global warming. 12 (Fuel combustion also contributes to N20 

emissions, but these emissions result primarily from mobile source combustion which is not 

considered in this analysis. 12) Methane emissions resulting from the production of gas, oil, and 

coal must be considered, as well as emissions from the transportation and distribution of natural 

gas. Methane emissions from the transportation of crude/refined product and coal are small, and 

methane emissions from the end use combustion of natural gas, oil, and coal are negligible. 

The results of the equivalent C02 emissions analysis are presented in Table B-6, 

which summarizes the data sources used to develop each equivalent C02 emission estimate and 

the values that resulted for a GWP of 34. As stated earlier, the equivalent C02 emissions for 

each type of fuel were developed from three basic parts: 1) combustion end use emissions of 

C02, 2) C02 emissions from production through transport, and 3) methane emissions converted 

to equivalent C02• 

As the table shows, combustion end use emissions are the largest contributor for 

all fuel types. Approximately 76% (for GWP of 34) of the C02 equivalent emissions per 

MMBtu from natural gas are from end use combustion. For fuel oil and coal, nearly 90% of total 

B-15 
TABLE B-6. SOURCES OF C02 EQUIVALENTS FOR EACH FUEL TYPE 

Natural Gas Fuel Oil Coal 

. ·· ·. lbEq. lb Eq. lb Eq . 

CO, per .C0

Emission 2 per CO, per 

Type!Souree MMBtu Data: Sourc~ MMBtu Data Source .· MMBtu • . Data Source 

Combustion of fuel in end 115.6 Based on fuel 164.4 ABB/Combustion 

use 

205.8 EPA Greenhouse Gas 

(direct C02) content and HHV Engineeringn Report 10 

(this study) 

Methane emissions from 24.5 GRJIEPA Methane 2.0 API Study14 20.4 EPA Reports 12•

1s 

production, processing, Emissions (this 

refining, transportation study) 

(methane converted to C02 

"' ' based on a GWP of 34) 

-

0> 

C02 emissions during 11.7 AP-42 Emission 19.6 API Study1

production, 

• 2.1 Energy lntemationaJD 

processing, Factors, Activity 

refining, transportation Factors from this 

study (direct C02) 

TOTAL 152 186 228 

Ib Equivalent CO,IMMBtu 
C02 emissions per 1\1MBtu are attributable to end-use combustion. The C02 emissions from end 

use combustion are well defmed, since they depend primarily upon the carbon content of the 

fuels. Therefore, the uncertainty associated with the largest portion of the equivalent C02 

estimate is relatively smalL 

The C02 emissions from production through transport and the methane emissions 

from coal and oil operations play a much smaller role in the overall comparison. 

Methane emissions comprise only 16% of the equivalent C02 emission estimate 

for natural gas, 1.1% for oil, and 9% for coal. Therefore the impact of the methane emission 

estimate is far less than that of the end use component. Methane emissions for natural gas are 

well kno\\tll (± 33 %), while the estimates for oil and coal may have much wider confidence 

bounds (possibly with an upper bound larger than 1 00%). Therefore the equivalent C02 emission 

comparison for natural gas is conservative, since the emissions from coal and oil may be much 

higher. 

The following sections on natural gas, coal, and oil describe the methods and 

assumptions used to determine the equivalent C02 emissions for each fuel type that were 

presented in Table B-6. 

Natural Gas 

Approximately 116 lbs of C02/MMBtu is emitted from the combustion of natural 

gas. This emission rate was calculated assuming the complete combustion of marketed natural 

gas (17.84 x 106 scffor 1990)" with a gross energy content of I 031 Btu/scf 12 and the 

corresponding composition of93.4% methane, 4.0% ethane, 0.5% propane, and 2.1% inerts. 

(Note: the mole percents of ethane, propane, and inerts were determined by weighting the 

respective higher heating values to achieve the desired methane composition and energy content 

of the gas mixture.) 12•

17 

B-17 
Carbon dioxide is also emitted through combustion in compressors, burners, and 

flares. Emissions from gas~ fired compressor engines used to transport natural gas from 

production to market were determined using a C02 emission factor of0.89 lb C02/hp·hr18 and the 

total hp-hr for production, transmission, and processing of 145 x 109 hp·hr. 19 This results in 7.0 

lbs CO/MMBtu emi~ions. Similarly, carbon dioxide emissions result from burning natural gas 

for other plant, lease, or pipeline fuel requirements. The amount of natural gas used for fuel 

purposes other than compressors was estimated in the Vented and Combustion Source Summary 

to be approximately 558 BscfY. 17 This results in an additional 3.6 lb C02/MMBtu, based on the 

C02 emission factor from natural gas combustion of 120 Ib CO/lv.lscf 20 It should be noted that 

this estimate is conservatively high since a portion of the fuel gas is used by the petroleum 

industry to operate equipment such as gas~lift compressors and heater~treaters. Finally, a small 

amount of C02 is generated from flaring natural gas. The Vented and Combustion Source 

Summary estimates 15.1 BscfY of methane is flared from production through distribution." 

Based on a 98% to 99% combustion efficiency, where ali of the methane com busted is assumed 

to form C02 , 0.1 1b C02/MMBtu result from flaring. 

Methane emissions from the production, transmission, gas processing, and 

distribution of natural gas are approximately 314 Bscfor 6.04 Tg/yr (methane emissions from 

end uses are negligible). Based on the marketed gas volume of 17.84 x IO' scfand the natural 

gas HHV of 1,031 Btu!scf, 1

'.1' the methane emissions equate to 0.72lbs CH,IMMBtu. 

Converting the methane emissions to equivalent C02 emissions requires a GWP, which for 

methane is 34 for an integration interval of 50 years and is 6.5 for an integration interval of 500 

years.6

•

7

•

8

•

9 Applying these conversion factors. the equivalent C02 emissions for methane are then 

24.5 lbs CO,IMMBtu for a GWP of34, and 4.7lbs CO,IMMBtu for a GWP of6.5. 

Natural gas results in a total of 132 lbs CO,IMMBtu for a GWP of6.5, and 152 

1bs C02/MMBtu for a GWP of34. Table B-7 summarizes the various components that 

contribute equivalent C02 emissions from the natural gas fuel cycle. 

B-18 
TABLE B-7. C02 EQUIVALENT EMISSIONS FROM NATURAL GAS 

. . • lb CO, Equivalent!MMBtu .. 

Emission Source GWP=6.5 GWP=34 

End-use Combustion C02 Emissions 115.6 115.6 

Compressor C02 Emissions 7.0 7.0 

Industry Burner C02 Emissions 4.6 4.6 

Flare C02 Emissions 0.1 

Methane 

0.1 

Emissions 4.7 24.5 

TOTAL 132.0 151.8 

Coal 

Methane emissions result primarily from coal mining; emissions of methane from 

the transport or end uses of coal are negligible. EPA's Inventory of Greenhouse Gas Emissions 

and Sinks reports methane emissions from coal mining activities ranging between 3.2 and 5.0 

million metric tonnes of methane for the year 1992.12 Based on the 1992 coal production of 

997.5 million short tons," and the coal higher heating value of 10,395 Btullb," methane 

emissions from this source equate to 0.44 Ibs rnethane!M:MBtu. In comparison, another EPA 

report shows 30 to 50 million metric tonnes of methane emitted globally corresponding to coal 

production of 5 billion tonnes. 13 For the same heating value, these values result in 0. 77 lbs 

methane/MMBtu. An average of the two sources (0.60 lbs methaneiMMBtu) was used to 

estimate equivalent C02 emissions of3.9 lbs C02/MMBtu for a GWP of 6.5 and approximately 

20.4 lbs C02/MMBtu for a GWP of 34. 

The primary source of C01 emissions from coal results from combustion. EPA 

reported that C01 emissions from energy production were 430.4 million metric tonnes of carbon 

equivalent (MMTCE) for 1992. 12 The energy generated from coal consumption for that year was 

16,910 trillion Btu. 12 Based on these values, C02 emissionsare approximately 206 lbs 

CO/Mlvffitu. In addition. C02 emissions from production and transportation equipment and the 

B-19 
loss of coal during transport are estimated to result in an additional increase in C02 emissions of 

approximately 1%, or 2.1 lbs CO/r..1MBtu. 14 

Table B-8 summarizes greenhouse emissions from the coal fuel cycle. The result 

is an equivalent C02 emission rate of 212 to 228lbs C01/MMBtu, depending on the GWP for 

methane. 

TABLE B-8. CO, EQUIVALENT EMISSIONS FROM COAL 

. lb CO, Equivalent!MMBtu 

Emission Source . GWP-'-6.5 GWP=34 

End Use C02 Combustion Emissions 

205.8 205.8 (Electric Utilities) 

lndusl:!y Other C02 Emissions 2.06 

Methane 

2.06 

Emissions 3.9 20.4 

TOTAL 212.3 228.3 

Oil 

A study was conducted by the American Petroleum Institute (API) for the 

petroleum industry to quantify methane and C02 emissions resulting from petroleum operations 

(production through transportation of refinery products) for the base year 1990.21 End use 

emissions were not included in the API study. Emission estimates for production, crude 

transportation, refining and product transportation are presented in Table B-9. 

B-20 
TABLE B-9. 1990 METHANE AND CO, EMISSIONS FROM CRUDE 

PRODUCTION THROUGH REFINED PRODUCT TRANSPORTATION 

Methane Emissions C02 Emissions, 

Industry Segment tons Methane Million tons CO/yr 

Production 823,609 95.16 

Crude Transport 11,192 8.87 

Refining 13.845 171.24 

Product Transport 0 8.77 

TOTAL 848,646 284.04 

For the fuel switching analysis, estimating equivalent C02 emissions from the oil 

industry on a basis comparable to emissions from natural gas and coal is complicated by the 

many different products generated from crude oil. Starting in refining, emissions from individual 

fuel products are directly related to the emission sources associated with those products; before 

the refining segment, a direct relation is not possible. Some portion of emissions generated from 

crude production and transport must be assumed to be associated with individual fuel products. 

For the purpose of this study, the fuels of interest (i.e., those comparable with the primary uses of 

natural gas and coal-residential heating and generating electricity) are distillate and residual 

fuel oils. Emissions associated with these fuel oils are assumed to be proportional to the ratio of 

the mass of distillate and residual fuel produced in refining to the mass of the total refinery crude 

charge: 

Fuel oil produced (mass) z Total fuel oil emissions (mass) 

Refinery crude charge (mass) Total crude emissions (mass) (B7) 

Therefore, the total emissions reported in Table B~ 7 wiU be scaled according to the following 

equation to estimate emissions associated with distillate and residual fuel oil only: 

EP ~ p/t (masslyr) x 

Refinery crude charge (mass) 

Fuel oil produced (mass) 

(B8) 

B-21 
where: 

Emissions of C02 or methane from production through product 

transportation 

The mass of fuel oil produced for market in 1992 is 2.215x 108 tons. This is based 

on !.09x I O' bbls of distillate" with a specific gravity of 0.8654,24 resulting in I.65x 108 tons 

distillate produced in 1992. In addition, residual production of 5.64x I 07 tons is based on 

326xi08 bbls ofresidual23 with a specific gravity of0.982 (which is estimated from the specific 

gravities of fuel oils Nos. 2, 4, 5, and 6 weighted by the relative volumes of each produced).24 

The mass ofrefmery crude charge for !992 is 7.53 x !08 tons (based on 4.91 xJ09 bbls of crude 

and an average crude specific gravity of0.876).23" The resulting ratio of fuel oil to crude charge 

is approximately 0.294. 

The general methodology for estimating emissions from the fuel cycle of distillate 

and residual oils is then: 

E~ _ ~If (mass/yr} x 0.29 X HHV (mass) + 

Marketed Fuel Oil Production (mass/yr) Fod oil (MMBtu) 

E..,~"" (mass) 

MMBTUODd,... 

E (mass) 

MMBtu 

(B9) 

which includes the addition of end use emissions from distillate and residual fuels (not included 

in the API study). The combined higher heating value for distillate and residual fuel oil is 19,194 

Btu/lb based on the individual HHVs (19,524 Btu/lb for distillate and 18,228 Btu/lb for 

residual)25 weighted by the relative production rate of each fuel (presented above). 

The resulting C02 emissions from production through product transport are 19.6 

lb CO,IMMBtu. Methane emissions equate to 0.059 lb methane!MMBtu. When converted to 

equivalent C02 emissions, this results in 0.38 lb equivalent C021Mlv1Btu for a G\VP of 6.5 and 

2.0 Jb equivalent C02/MMBtu for a GWP of34. 

B-22 
End use emissions of methane, from the combustion of petroleum products in 

turbines or boilers, are negligible. However, C02 end use emissions from these sources are 

significant. A Combustion Engineering report provided fuel oil properties,24 which were used to 

calculate combustion emissions based on the following equation: 

lb fuel x lb C x 44 Ib C02 x gal fuel = lb C02 

gal fuel Ib fuel 12 Ib C MMBtu MMBtu (BIO) 

This assumes all of the carbon present in the fuel oil is combusted to fonn C02• The properties 

of distillate and residual fuel oils and the corresponding C02 combustion emissions are sho\\tll in 

Table B-10. 

Property• 

Density, lb/ga! 

%Carbon 

HHV, MMBtu/ga! 

lb C02/MMBtu 

TABLE B-10. PROPERTIES OF FUEL OILS 

Distillate Fuel Oil 

7.206 

86.4 

0.141 

161.9 

Residual Fuel Oil 

8.212 

85.7 

0.150 

172.0 

These values were combined to generate one end use emission estimate for fuel 

oils based on a weighted average with respect to the production rate of each fuel oil type 

(1.65x 108 tons distillate and 5.64x 107 tons residual, as discussed previously). The resulting C02 

end use emissions from fuel oils used in residential heating and electricity generation are 164.4 lb 

C02/MMBtu. 

Table B-11 summarizes the emission estimates for the fuel cycle of residual and 

distillate fuel oils. 

B-23 
TABLE B-11. C02 EQUIVALENT EMISSIONS FROM FUEL OIL 

. Ib CO, EquivalentiMMBtu 

Emission SQurce . GW1'=65 GW1'=34 -

End Use Fuel Combustion C02 Emissions 164.4 164.4 

Industry Prod. through Product Transport CO, Emissions 19.6 19.6 

Prod. through Product Transport CH, Emissions 0.38 2.0 

TOTAL 184.4 186.0 

B.S Global Warming Conclusions 

Table B-12 lists the greenhouse gas emissions, expressed as pounds of equivalent 

CO, per MMBtu for natural gas, coal, and oil. To quantify the relative impacts on global 

warming of coal and oil compared to natural gas, the equivalent C02 emissions per unit of energy 

for coal and oii are divided by the value for natural gas. This "equivalent C02 ratio" is listed in 

Table B-12 for GWPs of6.5 and 34. 

. • 

TABLE B-12. EQUIVALENT CO, EMISSIONS FOR NATURAL GAS, 

OIL, AND COAL 

.. Fuel Source Ibs CO,JMMBtu . Equivalent CO, Ratio 

GWP=6.3 GWP_::-34 GW1'=6;S GW1'=34 

Gas 132 152 !.0 !.0 

Oil 184 186 1.4 1.2 

Coal 212 228 !.6 !.5 

Using oil has between 1.2 and 1.4 times the impact on global wanning emissions 

than the use of natural gas. Similarly, coal contributes 50 to 60% more equivalent C02 emissions 

than natural gas, resulting in 1.5 to 1.6 times the impact on global wanning. These results are in 

basic agreement with IPCC's conclusions on fuel switching to reduce greenhouse gas emissions: 

B-24 
Switching from coal to oil or natural gas would reduce carbon emissions in 

proportion to the carbon intensity of the fuel. For example, sv.ri.tching from coal 

to natural gas would reduce emissions by 40%. In addition, the higher energy 

efficiency available with natural gas would reduce emissions further-for 

example, a shift from coal to natural gas in power generation by 20%. 1 

The net result is that switching from other fuels to natural gas can help the United States reach its 

goals on limiting greenhouse gas emissions a:J.d their potential impact on global wanning. 

B-25 
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B-26 
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Energy International. Energy Utilization and Greenhouse Gas Emissions: EndUse Analysis, Final Report, GRI-93/0335, Gas Research Institute, June 1994. 

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Environmental Protection Agency, June 1996. 

U.S. Environmental Protection Agency, Compilation of Air Pollution Emission 

Factors: Volume I Stationary Point and Area Sources, AP-42 (GPO 055-000-005-

001), Table 3.2-2, U.S. EPA Office of Air Quality Planning and Standards, 5th 

Edition, January 1995. 

Stapper, C.J. Methane Emissions from the Natural Gas Industry, Volume 11: 

Compressor Driver Exhaust, Final Report, GRI-94/0257.28 and EPA-600/R-96-

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

1996. 

U.S. Environmental Protection Agency, Compilation of Air Pollution Emission 

Factors: Volume I Stationary Point and Area Sources, AP-42 (GPO 055-000-005-

001), Table 1.4-3, U.S. EPA Office of Air Qnality Planning and Standards, 5th 

Edition, January 1995. 

Energy Infonnation Administration. Cost and Quality of Fuels for Electric Utility 

Plants 1993, Department ofEnergy, DOE/EIA-0191(93), Washington, DC, July 

1994. 

B-27 
22. 

23. 

24. 

25. 

Radian 

US. 

International LLC. Methane and Carbon Dioxide Emission Estimates from 

Petroleum Sources, Draft Report, American Petroleum Institute, January 

1996. 

Department 

Energy Information Administration. Petroleum Supply Annual199 3, Volume !. 

of Energy, DOE/EIA-0340(93)/1, Washington, DC, June 1994. 

Combustion Engineering. Combustion Fossil Power, ABB/Combustion 

Engineering, Windsor,CT, 1991. 

Baumeister, T., E.A. Avallone, and T. Baumeister Ill. Mark's Standard 

Handbook/or Mechanical Engineers, Eighth Edition, McGraw-Hill Book 

Company, New York, NY, 1978, p. 7-14. 

B-28 
APPENDIXC 

Conversion Table 

C-1 
Unit Conversion Table 

English to Metric Conversions 

1 scf methane = 19.23 g methane 

1 Bscf methane = 0.01923 T g methane 

1 Bscf methane = 19,230 metric tonnes methane 

1 Bscf = 28.32 million standard cubic meters 

1 short ton (ton) = 907.2 kg 

1 lb = 0.4536 kg 

lft' = 0.02832 m3 

1 ft3 

= 28.32 liters 

1 gallon = 3. 785 liters 

1 barrel (bbl) = !58.97!iters 

1 inch = 2.540 em 

1 ft = 0.3048m 

I mile = 1.609 km 

1 hp = 0.7457 kW 

1 hp-hr = 0.7457 kW-hr 

lBtu = 1055 joules 

lMMBtu = 293 kW-hr 

llb/MMBtu = 430 g/GJ 

T ('F) = 1.8 T ('C)+ 32 

1 psi = 51.71 mm Hg 

Global Warming Conversions 

Calculating carbon equivalents of any gas: 

( 

MMTCE = (MMT of MW carbon) gas) x ' x (GWP) MW, gas 

C-2 
Calculating C02 equivalents for methane: 

( 

MMT of C0 Mw, co,) 2 equiv. = (MMT CH,) x x (GWP) MW, CH, 

where MW (molecular weight) of CO, =44, MW carbon= 12, and MW CH,= 16. 

N!!i§ 

scf 

Bscf 

MMscf 

Mscf 

Tg 

Giga (G) 

Metric tonnes 

psig 

psi a 

GWP 

MMT 

MMTCE 

= 

= 

= 

= 

= 

= 

= 

= 

= 

= 

Standard cubic feet. Standard conditions are at 14.73 psia and 60°F. 

Billion standard cubic feet (10' set). 

Million standard cubic feet. 

Thousand standard cubic feet. 

T eragrarn (! O" g). 

Same as billion (I 0'). 

!000 kg. 

Gauge pressure. 

Absolute pressure (note psia = psig +atmospheric pressure). 

Global Warming Potential of a particular greenhouse gas for a given. 

time period. 

= Million metric tonnes of a gas. 

= Million metric tonnes, carbon equivalent. 

MMT ofC02 eq. = Million metric tonnes, carbon dioxide equivalent. 

C-3 

APPENDIXD 

Project Reviewers 

D-1 
PROJECT REVIEWERS* 

Name 

Ackell, 

Company 

John Oil Heat Task Fo~e 

Ammirato, Vincent Columbia Gas 

Ball, Richard H. U.S. Department of Energy 

Benjey, Bill PA 

Bjerklie, John Consolidated Natural Gas 

Boss, Terry INGAA 

Bradford, Ray biUips 66 

Brasseur, Guy 

Busch, William 

National Center for Atmospheric Research 

NOAA 

Carter, Doug DOE 

Chai, Eric Shell Development 

Childress, P.O. Colorado Interstate Gas 

Ching, Jason EPA 

Cohen, Jonathan ICF Kaiser 

Cook. Tracy SoC a I 

Cormier, Michael Amoco Production Co. 

Cuig, Bruce ~atural Gas Supply Assoc. 

Derkowski, CaJTie Coastal 

Doyle, Terry . 

;Enron Corp 

Doyle, William J. Marathon Oil Company 

Eberle, Art Columbia Gas 

Enright, Jeffrey ICF Kaiser 

Erickson, John American Gas Assot:iation 

Farrand, David Williams Natural Gas 

Fisher, Diane Environmental Defense Fund 

Fitzgibbon, Timothy ICF 

Fritz, Eric Natural Gas Pipeline 

Fung, Inez 

Gibbs, Michael 

NASA Goddard Institute for Space Studies 

ICF 

Godec, Michael ICF 

Goens, Dick Union Gas Ltd. 

Haines, Deanna SoCaJGas 

Hansen, Anne NGL 

Hansford, James E. Enrcn Gas Pipeline 

Hare, Marik.a Consumers Gas 

Hay, Nelson Americ:an Gas Association 

Hogan, 

(A.G.A.) 

Kathleen EPA-OAR 

lnnerarity, Mike Tenneco Energy 

Isaacson, Ron GRI 

.Johnson, Donald 

rgonne National Laboratory 

Kalkstein, Larry EPA 

Kirchgessner, Dave EPA 

Klein, Gary API, Oil Heat Task Force 

Kni2ht, Bruce Marathon Oil 

D-2 (Continued) 
PROJECT REVIEWERS* (Cont'd) 

•• Name Company 

Konecki, Mark AMOCO 

Kothari, Kiran GRI 

Lajiness, Vincent D. ANR Pipeline 

Lashof, Dan Natural Resources Defense Council 

Lawrence, Steve PG&E 

Loft, Bob GRI 

Magid, Hillel Allied-8ignal 

Malarkey, Patrick Phillips 66 

Martino, Paul API 

Matthews, Neil Southern Natural Gas 

Magid, Hillel !lied Signal Corp. 

Mathis, Michael J. Niagara Mohawk Power Corporation 

Mercado, Donna American Gas Ass~iation 

Meshkati, Shabed SoCal 

Minotti, Marcello Tenneco 

Mize, Ed Williams Natural Gas 

Mobley, David J. EPA 

Morse, William Columbia Gas 

Mroz.Gene Los Alamos National Lab 

Mussio, Peter Union Gas 

Newsom, Vick Amoco 

Nunn, William Texas Gas Transmission 

Ollison, W,W. American Petroleum Institute 

Orfeo, Robert Allied Signal Corp. 

Osborne, Andrea EPA 

Parrotta, Daniel Con Edison 

Perhac, Ralph EPRI 

Philips, Marc En ron 

Prather, Michael NASA Goddard Institute for Space Studies 

Preusser Brooklyn Union Gas Company 

Primus, Frank Chevron 

Reilly, Mike CNG 

Reiquam, Howard GRI 

Resch, Rhone EPA OAR 

Riordan, Mike Brooklyn Union Gas Company 

Roose, Tom GRI 

Schievelbein, Vernon Texaco 

Shah, Andy Conoco 

Shervill, Paul Union Gas 

Stern.. Richard EPA 

Swenson, Paul Consolidated Natural Gas Service Corp. 

Tate, Jack Texaco 

Tie, Xuexi Los Alamos National Lab 

D-3 (Continued) 
PROJECT REVIEWERS* (Coot' d) 

Nam~ Company 

Tixier, Charles 

-

iS hell 

Traweek, Lori American Gas Association 

VanWyck, Robert Con Edison 

VanDerZanden, Daniel lcbevron 

Warner, John Amoco 

Weynand, Gordon EPA 

Woodbury, Jonathan ICF 

Yundt, Paul Gas Technology Canada 

Zinkham, Jeffrey Amow 

*Project reviewers have participated 

time period !990-1996. 

in one or more review meetings for this project over the 

D-4 
I 

' 

' ------

' ' 

DCN 96-263-081-17 

Box 201088 

Texas 78720-1088 

EPA, Office of Research and Development 

Air Pollution Prevention and Control Division 

Research Triangle Park, NC 277ll 

program 

. p.a_tll;:z::_91 gas industry for the base 

d~t<:cnl;"n,e_qr4 __ ~P~.i''-~i. p_•,.~ __ Jn>m .1-U_~ .. w~l1,4~a9 and __ e_nding 

. ~<;q_J.!:racy goal was to determine these 

production for a 90% confidence interval. 

_ _ _. ..W.e JJ.~ S .•. Patural gas industry was 314 

This is equivalent to J.!_'f +/-. Q.~~% _qf gross natural .. .... .. .. ···- ·- ... - -- . (per the voluntary Amerinor increases (due to increased 

~f~f~~~~fJ:~~~~~~~~~1J~I- - _recently -~-:c~--y~\~<?:~~~i:tJI~f;~---~~[.~-~~~~~~--~~~~a~e published by the Intergovernmental Panel g;l~~~o;:~- on Climate 

c.!"e __ e-'};>_'X'"-'~ .. _s_h?~~9-.. ~Q~_t !.!atll!'.~ gas contributes less to potential 

, ~:S~~-i].!..,rY.:h!,£q,_,~9.PPOrts -~~- fu_el switching strategy suggested 

p.9,ditioz:l,. _ s_tudy results are being used by the natural gas '"- --~"-- _, _.,- . 

Stationary Sources 

Global Warming 
U.S. ENVIRONMENTAL PROTECTION AGENCY 

Office of Research and Development 

National Risk Management Research Laboratory 

Technology Transfer and Support Division 

Cincinnati, Ohio 45268 

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