- -- -

# \



# \ 

# ' 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 pro

### blems 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 orrecommendation for use. This dOa.Jment is available to the publicthrough the National Tec/lnicallnfonnation Service, Springfield, Virginia 22161.EPA-600/R-96-CSOb June 

### 1996 METHANE EMISSIONS FROM 

## TiiE NATURAL GAS INDUSTRY VOLUME2: 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 Avenue 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 LEGAL NOTICE: This report 

### was prepared by 

### Radian International LLC as an account of work sponsored by Gas Research Institute (GR1) and the U.S. Environmental ProtectionAgency (EPA). NeitherEPA, 

### GRl, membersof

### GRl, norany person acting on behalfofeither: a. Makes any warranty orrepresentation, express or implied, 

### with respect to the accuracy, 

### completeness, or usefulness ofthe 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 anyliabilitywithrespect to the use of, orfor damages resultingfrom the use of, 

### any information, apparatus, method, or process disclosed in this report. NOTE: EPA's Office ofResearch and Developmentquality 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 subjectto EP NORD's 

### QAIQC policies. Inall cases, data and results were reviewed bythe panel ofexperts listed inAppendix D ofVolume 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 ofa studyto quantify the annual methane 

### emissions from the natural gas industry. The increased use ofnatural gas has been suggested as a strategy for reducing thepotential for global warming. During combustion, natural gas 

### generates less carbon dioxide

**(CO~** 

### per 

### unit ofenergy produced than either coal or oil. On the basis ofthe amount ofC02 

### emitted, the potential for global warming couldbe reduced by substituting natural gas for coal oroil. 

### However, since natural gas is primarily methane, a potent greenhouse gas, losses ofnatural gas duringproduction, processing, transmission, and distribution could reduce the inherent advantage ofits lower C02 emissions. 

### To investigate this, Gas Research Institute (GRI) and the U.S. Environmental Protection Agency's Office ofResearch and Development (EPAIORD) cofunded a major study to quantify methane emissions from 

### U.S. natural gas operations for the 

### 1992 base year. The purpose ofthis study was toprovide emissions data that could be used to construct global methanebudgets and to detenninethe relative impact ofnatural gas onglobal warming versus the impact from coal and oil. Titis summaryreport is volume 

### 2 ofa **multi-~olume** set ofreports that fully describe the project.

Ill

### Results

Technical Approach

Project Implications The national emissions forthe base year are 314 ± 

### 105 Bscf(±33%), which is equivalent to 1.4 ± 

### 0.5% ofgross natural gasproduction. The overall program also showed that the percentage ofmethane emitted for an incremental increase in natural gas sales would be 

### significantly lowerthan the baseline case. On an industry segment basis, the production segment emits 84.4 Bscf, gas processing plantsemit 36.4 Bscf, transmission and storage facilities emit 

### 116.5 Bscf, and distribution systems emit 77.0 Bscf. The report also shows that the largest type ofmethane emissions is fugitives, which accounts for 

### 195.2 Bscffrom all segments combined. Theprogram reached its 

### accuracy goal and provides an accurate estimate of methane emissions that can be used to construct U.S. methane inventories and analyze fuel switching strategies. The techniques used to determine methane emissions were developed to be 

### representative ofannual emissions from the natural

### gas industry. However, it is impractical to measure every source continuouslyfor a year. Therefore, emissionrates for various sources were determined by developing annual emission factors for sources in

### each industry 

### segment and extrapolating these data

### based on activity factors to 

### develop a national estimate, where the national emission estimate is the product ofthe emission factor and activity factor. The development ofspecific emissionfactors and activity factors for each industry segment are presented 

### in a separate report. Forthe !992 base yearthe annual 

### methane emissions estimate forthe 

### U.S. natural gas industry is 314 Bscf± 105 Bscf(±33%). This is equivalent to 1.4% ± 

### 0.5% ofgross natural gas production. Results from this program were used to compare greenhouse gas emissions from the fuel 

### cycle for natural gas, oil, and coal using the global wanningpotentials (GWPs) recentlypublished by the Intergovernmental Pane! on Climate Change (IPCC). 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 !PCC and others. In addition, results from this study are being used by the natural gas industry to reduce both operating costs and emissions. Some companies are also participating in the Natural Gas-Starprogram, a vohmtary program sponsored by

### EPA's Office ofAir and Radiation in 

### cooperation with 

### the American Gas Association 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 ..................................... 9 

### 3

### .l.l General Industry Description .................................. 9 3. 1.2 Operating Mode ........................................... 17 3.1.3 Emission Types ........................................... 19 3.2 Emission Estimation Technique ..................................... 20 3.2.1 Measurement Techniques for Steady Emissions .................. 20 3.2.2 Calculation Approach for Unsteady Emissions .................. 23 3.3 General Extrapolation Methodology .................................. 24 3.3.1 Sampling Approach ........................................ 25 3.3.2 Redefining the Emission Factor .............................. 26 3.4 Accuracy .......................................................27 3.4.1 Precision .................................· ................27 3.4.2 Bias ..................................................... 28 3.5 Quality Assurance and Quality Control Approach ....................... 28 3.5.1 Overview ................................................ 29 3.5.2 Definitions ...............................................30 3.5.3 Quality Control ............................................31 3.5.4 Quality Assurance ......................................... 33 4.0 DETAILED RESULTS .................................................. 37 4.1 Emission Type Summary ........................................... 37 42 

### Fugitive Emissions ................................................39 4.2.1 Equipment Leaks .......................................... 41 4.2.2 Underground Pipelioe Leaks ................................. 50 4.3 Vented Emissions . ................................................ 52 4.3.1 Pneumatic Devices ......................................... 52 

### 4.3.2 Blowand Purge ........................................... 55 4.3.3 DehydratorGlycol Pumps ................................... 56 4.3.4 DehydratorVents .......................................... 57 4.3.5 Chemical Injection Pumps ................................... 58 4.4 Combusted Emissions .............................................59 4.5 Largest Sources by 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 ofEmissions Sources ....................... A-1 APPENDIX B -Effect ofMethane Emissions on Global Warming ...............B-1 APPENDIX C - Conversion Table ........................................ C-1 APPENDIX D - Project Reviewers . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . D-1

v:r

## LIST OFFIGURES Page 3-1 Gas Industry FlowChart ................................................. 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 FugitiveEmissions from the Natural Gas Industry ........... 39 

### 4-3 MajorContributors to Fugitive Emissions-By Segment Facilities ................40 4-4 Contributions to Vented Emissions .........................................52 4-5 Summary ofMethaneEmissions ........................................... 61 4-6 Production SegmentLargest Sources ....................................... 64 4-7 GasProcessing Segment Largest Sources .................................... 65 4-8 Transmission and Storage Largest Sources ................................... 66 4-9 Distribution Largest Sources .............................................. 67 5-l Contribution ofMajorMethaneSourcesto 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 ofNational Emissions Estimation for Gas Storage Facilities ............. 43 

### 4-3 Summary ofMethane 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 ofMethane .....................................B-5 B-2 Amount ofC02 

### and Methane Remaining in

### Atmosphere with Time ..............B-7 B-3 Breakeven Percentage (BP) for Coal and Oil for Various GWP IntegrationIntervals
. B-9 B-4 Incremental Changes in Emissions Resulting from Increased Gas Sales



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

lX

### LIST OFTABLES (Continued)
B-5 Incremental Changes in Emissions Resulting from Increased Gas Sales
- Page Upper Limit Case ..................................................... B-12 B-6 Sources of

### C0 2 Equivalents for Each Fue!Type ............................. B-16 B-7 C02 Equivalent Emissions from Natural Gas ............................... B-19 B-8 C02Equivalent Emissions from Coal ..................................... B-20 B-9 1990 Methane and 

### C02 Emissions from Crude Production Through Refined Product Transportation ................................................. B-2I B-10 Properties ofFuel Oils ................................................. B-23 B-11 

### C0 2 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 ofa project sponsored by Gas Research 

### Institute (GRl) and U.S. Environmental Protection Agency's Office ofResearch and Development (EPA/ORD) to quantify methane emissions from the natural gas industty. The project was initiated to evaluate whetherthe suggested strategy ofincreasing the use ofnatural gas to reduce global warming was valid in light ofmethane emitted from the industry. It also had the purpose ofdetermining the gas industry's contribution ofmethane to the global inventory of greenhouse gas emissions. During combustion, natural gas generates less carbon dioxide (C02) perunit of energy produced than either coal oroil. On the basis ofthe amount ofC02 emitted, thepotential for global warming could be reduced by substituting natural gas for coal oroil. However, since natural gas is primarilymethane, a potent greenhouse gas, losses ofnatural gas during production, processing, transmission, and distribution could reduce the inherent advantage ofits 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 ofthis study can be used to construct global methane budgets and to detennine the relative impact on global warming ofnatural gas versus coal and oil. Forthe 1992 base year the annual methane emissions estimate for the U.S. natural gas industry is 314 Bscf± 105 Bscf(± 33%)." This is equivalentto 1.4%± 0.5% of 1992 gross natural gas production. The project reached it accuracy goal ofdetermining emissions within ± 0.5% ofproduction, and provides an accurate methane emissions estimate that can be used in fuel switching analyses. The program also showed that the percentage ofmethane 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 oroil, which supports the fuel 

### switching strategy suggested by the IPCC and others. Even across awide range ofassumptions 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 reducingemissions. This has led to the development ofavoluntary program, the Gas-Starprogram, sponsored by EPA incooperation with the American Gas Association (A.G.A.).' As part 

### ofthisvoluntary program, participating companies implement 

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

2

### 2.0 INTRODUCTION The increased use ofnatural 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 ofenergy produced than eithercoal oroil. On the basis ofthe 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 ofnatural gas during production, transmission, and distribution could reduce the inherent advantage ofits lower C02 emissions. For this reason, GRI and EPAjointly 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 comprehensiveprogram was to quantify methane emissions from the gas industry starting at the wellhead and ending immediately dovmstream ofthe customer's meter. The accuracy goal of the project was to determine these emissions to 

### within 0.5% ofnatural gas production based on a 90%level ofconfidence. This is equivalent to an accuracy goal of±Ill billion standard cubic feet (Bscf) peryearforthe 1992 base year. The methane emissions program was conducted in three phases: scopmg, methods development, and implementationphase. During the scopingphase ofthe program, the methane emissions from each source inthe gas industry were quantified on the basis ofavailable data and engineeringjudgement. These initial estimates were used to set priorities for data collection according to the relative importance oftheir contributionto emissions orthe Wlcertainty in emissions. In the second phase ofthe program, methods were developed to measure and/or calculate methane emissions from the variety ofsources that make up the gas industry. These methods were validated through tests designed to quantify the accuracy ofthe measurement approach (i.e., proofofconcept tests), and through industry review ofthe analytical methods. However, emissions could not be measured or calculated from each piece ofequipment (e.g., every glycol dehydrator, compressor engine, etc.) in the industrybecause ofthe vast amount of 3

### equipment. Therefore, amajortask in 

### the second phase was to develop defensible techniques for extrapolating a limited amount ofdata

### collected for each source category to other sotrrees 

### in the category in orderto develop a national emissions estimate. The tlli:dphase ofthe 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 ofthe program concentrated on hlgh priority sources (i.e., sources with 

### large emissions and/or large uncertainties). An

### Advisory Committee consisting ofindustryrepresentatives,project sponsors, and otherinterestedparties including scientists, governmentpolicy analysts, and environmentalists provided guidance and peerreview for all phases ofthe program. In addition, Gas Industry Review Panels for each segment ofthe gas industryprovided more detailed technical review ofthe project to ensure that the methodologies and assumptions used in 

### the stUdy were consistent with industry practices. The final 

### analysis ofthe 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 ofeach 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) orfrom GRI. The remaining reports represent field data, proofofconcept 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 presentthe executive summary, the technical report, the general methodology, the statistical methodology, and the activity factors. These first five volumes are the most important source ofoverall information on the project. Volumes 6 through 15 present the details ofthe test program 

### and calculationprocedures for determining specific emission and activity factors.

4

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

### ReportName Report Numberor 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 GasIndustry, 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: Blowand 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: CompressorDriver 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.EcSta_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 

### Methane Emissions from the Natural Gas Industry, Volume 13: Chemical Injection Pumps 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 from the Natural Gas Industry, Volume 15: Gas-Assisted Glycol Pumps 17 AnEngineeringEstimateoftheIncremental Change in MethaneEmissionswithIncreasing 

### Jhr~~-p~~n **~ ~od~l~atura~**  **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 from Natural Gas System GRI-94/0257.43 Facilities, Final Report 19
Evaluation ofMethane Emissions from Natural Gas Production Operations Using Tracer Methodologies 20 Fugitive Hydrocarbon Emissions from Oil and Gas Production Operations21 GRI-92/0102 API4589 Fugitive Hydrocarbon Emission: Eastern Gas Wells (Final Reportf 2 GRI-95/0II? D. Myers and 

### M.R. Harrison ColumbiaGas

Aerodyne, Washington 

### State University, University ofNew

**~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 Reportf 6 GRI-95/0204 Phase 3 Program Plan- Implementation Plan 27 Mass Balance ofa Natural Gas Transmission System for Improved Estimates ofMethane 

### Emissions 28

---- 

# -- Soil Consumption ofMethane from Natural Gas Pipeline Leaks29
Sampler Enables Measurement ofLeaks on Site-Specific Basis 30 RadianDCN 92-263-081-02 SwRI 04-4447 GRI-94/0257.35 ---

American OiIand Gas Reporter, March 1995 STAR Environmental Radian Corporation Southwest Research Institute Aerodyne, Washington State University, University ofNew Hampshire Lott, Webb,

Howard

### This technical report is organized as follows: Section 2 presents background information; Section 3 provides anoverview ofthe methodologies developed and followed 

### in the study which includes methods for characterizingthe industry, measuring and calculating emission factors, collecting activity factor data 

### (equipment andcomponent counts), and extrapolatingthe data toderive anannuai. methane emissions estimate for the U.S. natural gas industry. Section 4provides summaries ofthelargest methane emission sources. Section 5 provides an overviewofthe majorconclusions 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 withinthe industry, so that all significant 

### sources are included. To fully 

### characterize the industry. 

### sources were defined by 

### equipment type, mode ofoperation, andtype ofemissions. "While this section draws a general picture ofthe industry, it is not intended to be a definitive picture ofany companyorofthe industry regarding specific operational practices and procedures. Rather, 

### it is intended to define thegeneral industry equipment practices and 

### procedures used in 1992, the base year ofthe p:-ogram, that could lead to measurable emissions ofmethane. 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, andtrar1sports the gas to the customer. Transportation and distribution ofnatural gas involve interstate and intrastate pipeline transportation, storage, and fmally distribution ofthe gas by local distribution pipeline networks.



### 9The generally accepted segments ofthe natural gas industry are: !) 

### Production 2) Processing 3) Transmission/storage 

### 4) Distribution Each ofthese 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. Thisproject set specific boundaries for each segment ofthe industry that specify what equipment is included in the study. The guideline used for setting the boundaries wasto include only the equipment 

### in each segmentthat is required for marketing natural gas. For example, oil productionequipment isexcluded ifitis used to produceoil and not natural gas. Similarly, gas processing equipmentassociated 

### with the fractionation ofpropane, butane, and natural gas liquids are excluded from consideration. Indistribution, all equipment up to and including the customer's meter are included. End-useremissions are not included inthis estimate. Each industry segment is described inmore detail in the following subsections: Production Segment Description The production segment is comprised ofgas 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-**----r-~~l~i ~_i~--~~a-~**  L-J 

## c
**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, 

# ICompressor Stations,

,Meter and Pressure Regulating Stations I 

### ,Underground Injection/Withdrawal 

## ' ' 

# iFacilities, and Liquefied Natural Gas 

### '(LNG) Facilities 

### ' i

### Main and Service Pipeline Networks, ' 

### :Meter and Pressure Regulating Stations 

## '

12 

# I Equipmentatthe 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 

# IRegulators, Pneumatic Devices, :CustomerMetersThe definition for gas industryproduction equipment excludes equipment associated with oil production. Also, unmarketed natural gas, such as that produced by oil wells that vent gas orthat reinject gas for gas 

### lift circulation only, are not considered part ofthe 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 emissionrate production equipment associated 

### with oil production. Anaccounting oftotalproduction segment emissions, orjust oil industry emissions, 

### 'Wi11 haveto 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) ofthe 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 oftheproduct stream. The back end ofthe 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 endofthe gas planthas negligible methane emissions since the liquids handled have little methane content. The front end ofthe 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 ofthe 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 PetrokumIndustry

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



# ------

Sa!rWattt

**T~k ~** 



## ~ Vapor Recovery

**~** Comp"'ssor Pe1rokum Industry


### Figure3-2. Gas Industry Boundaries 14

### Transmission and Storage Segment Description The transmission segment moves the natural gas from the gasplant ordirectly from field production to local distribution companies (LDCs). Gas is often transported across many states, such as from the GulfCoast to the Eastern seaboard ofthe United States. The transmission segmentconsists oflarge diameter pipeline, compressor stations, and metering facilities. All ofthese facilities and all ofthe equipmentthey contain are considered part ofthe natural gas industry. Transmission compressor stations usually consist ofpiping manifolds, reciprocating engines orgas turbines, reciprocating orcentrifugal compressors, and generators, as shown in Figure 3-3. Dehydrators may be included but are nottypically present because of upstream gas drying. Sometransmission compressor stations may also include metering facilities. Transmission companies also have metering and regulating stations (M&PR) where they exchange gas with othertransmission companies, orwherethey 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 storingthe liquid phase methane in above ground, heavily insulated storage tanks. Below-grotmd facilities compress and store the gas (in vaporphase) in one of several fonnations: I) spent gas production fields, 2) aquifers,·or 3) salt caverns. Below-ground storage is the predominantmeans ofgas storage. 

### !5Gas from Pipeline 

### TRANSMISSION ABOVE GROUND STORAGE COMPRESSOR STATION 

# g Cooling

**~** LNG Compressors 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 StationsMost storage stations consist ofa 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 ofthe natural gas industry defined by 

### this project.Distribution Segment Definition The distribution segment receives highpressure gas from transmissionpipelines, reduces the pressure, and delivers the gas to residential, commercial, and industrial consumers. Tills segment includespipelines (mains and services), 

### M&PR stations and customermeters. 

### All ofthese facilities are considered to be an integral 

### part ofthe gas industry. Figure 3-4 shows a schematic ofthe distribution segment and the equipment that it includes. 

### 3.1.2 OperatingMode After identifying the majorequipment (sourcetypes) in each industry segment, emissions from each source were identified by examining the operatingmodes ofthe equipment that may lead to emissions, and by associating one of

### three possible types ofemissions from the source: fugitive emissions, vented emissions, or combustion emissions. The cause ofemissions is directly related to the operating mode ofthe equipment. Since more 

### than one cause ofemissions 

### can be associated

### with 

### aparticularpiece 

### ofequipment, 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. 

### 17Regulating (M&PR) Station Pressure-Reducing Station Meter and Pressure

**Main~** (Pipeline)



# ~ !'?. 

## -"""


# - M 00 @ 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 aspurging a newly constructed plant orpipeline, 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 orundergrmmd pipeline leaks, and emissions from gas-operated pneumatic devices. Maintenance operations involve blowing down equipment, such as compressors,pipelines, or vessels, before equipmentmaintenance. Process upsets usually involve releasing natural gas to the atmosphere orto a combustion device, such as a flare, as the result ofoverpressure or emergency shutdown conditions. Mishaps are intended to include accidental occurrences that result in emissions, such as third-partydamageto pipelines (dig-ins). 

### 3.13 Emission Types Emissions from eachpiece ofequipment in the natural gas industry can be classified in one ofthree 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 oroperational practice. Examples ofvented emissions include emissions from continuous process vents, suchas dehydratorreboiler vents; maintenancepractices, 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 ofthe industry were identified. Each source (i.e., piece ofequipment) was then examined for different emissions during different operating modes. Emissions from each source were also categorized as eithercombustion, vented, orfugitive. 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).
193.2 

### Emission Estimation Technique Afterall potential sources ofmethane emissions in the industry were identified and characterized, the annual emissionswere estimated. Because it would be impractical to 

### measure emissions all 

### year for every source, 

### it is important that ameasurement be representative ofthe annual emissions. Some emissions from natural gas industry sources are continuous and nearly "steady" and a single measurement is representative ofannual emissions. ("Steady" is a relative tenn and to some extent is dependent on the timeperiod ofdataneeded for the study. 

### Forthis study, the annual 

### value ofmethane emissions is needed.) The measurementtechniques used in this studydepended on the variability ofthe 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 yearfor each source, emissions from these sources were calculatedratherthan measured. Table 3-2 shows examples ofemission sources characterized by operating modeemission type and whether the emissions are steady orunsteady. 

### 3.2.1 MeasurementTechniques for SteadyEmissions Steady emissions result 

### from unintentional leaks 

### from sealed surfaces such 

### as pipe connectors, valve packing, flange gaskets at surfacefacilities, 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. Othersurface facility methods include the tracergas method. Measuring emissions from buriedpipelines is done through a leak statistics method. Eachofthese methods is described inthefollowing subsections.



### 20

### Emission Type Fugitive

Vented

Combusted 

### TABLE 3-2. EMISSION CHARACTERIZATIONS Specific SourceExamples 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 ISteady Dehydrator Vents : Nannal Operations Steady I Pipeline Purge/Blowdown !Maintenance Unsteady ' ·Pneumatic Devices 1 Normal Operations Unsteady Equipment Blowdown INormal Operations I IUnsteady 

# iMaintenance :Unsteady ' **~** Compressor Starts

Chemical Injection Pump Vents
.Normal Operations Unsteady I 

# I Upsets Unsteady ·1 Normal Operations, :Unsteady Pressure ReliefValve Lift I ICompressor Driver Exhaust

.Flaring \Upsets/Maintenance ' Unsteady IBurners 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 ofthis 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 ofrandomly selected components and to determine the average emission rate (i.e.,


### 21

### emission factor) for each type 

### ofcomponent. Afterthe components were screened to determine ifthey were leaking, the average emission rate was measured using one ofseveral test methods: • Ahigh flow organic vaporanalyzerthat captures the entire leak and measures the methane concentration and flow rate. The emission rate is detennined from the product ofthe concentration and flow rate. This method was developed as part ofthis natural gas industry program to provide a more accurate and cost-effective technique for measuring a methane emission rate directly. • Atotal enclosure technique called bagging. Uncontaminated air 

### is blown through an enclosure surrounding the component; the flow rate and outlet concentration are then measured. The leak rate is detennined from the product ofthe concentration and 

### flow rate. • A screening technique in which the methane concentration is measured by passing a standard organic vaporanalyzeraround the sealed surface. The 

### concentration is related to an emissionrate by 

### acorrelation equationthat relates bagged emissions to measured screening values. TracerGas Method 

### The tracer gas 

### method ofmeasuring methane emjssions consists ofreleasing tracer gas (at a known constant rate) near the emission source and measuring the downwind concentrations oftracer and methane. Assuming complete mixing ofthe methane and tracergas, and assuming identical dispersion, the ratio ofthe downwind concentrations is equal to the ratio ofthe release rates. Based upon the do\vnw:ind concentrations ofmethane and tracergas and the known release rate ofthe tracer, the emission rate ofmethane can then be 

### determined. This method was used primarily to measure emissions from M&PR stations.l2
·19



### 22LeakStatistics 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 ofpipe material, age, pressure, and soil characteristics. The measurementprogram was conducted as a cooperative effort betweenEPAIGRJ and industry. The industry participants used specially designed equipmentto 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 perleak by the estimatedtotal nwnber ofleaks in the distribution segment. 

### 3.2.2 Calculation Approach for Unsteady Emissions For some methane emission sources, such as releases during maintenance, detailed companyrecords are available for multiple years. However, many other sources of unsteady emissions are nottracked by companies and, therefore, mustbe calculated. Each unsteady source ofemissions requires data gathering and a unique setof equations to quantify the average annual emissions. In general, all unsteady sources ofemissions require the following infonnation to quantif)r annual emissions:

• Detailed technical characterization ofthe source and identification of the important parameters affecting emissions. (1bis information is docwnented for individual source types 

### in the reports for eachmajor source category.)
• Data from multiple sites that allow the methane emitted peremission event to be calculated from the governing equations. 

### 23• Data on the frequency ofreleases. The estimate ofemissions from a vessel blowdown for routine maintenance is an example ofemissions calculated for an unsteady source . In this case, the volume, pressure, and temperature ofgas contained 

### in the vessel before blowdown is used to calculate losses from a blowdown event. Additionally, anaverage frequency ofthese vessel blowdown events is necessary to detennine the annual loss. In some cases, emissionsperevent from some unsteady sources were measured. These emissions data were combined with site data collected 

### in this studyto quantity the annual emissions from these sources. Examples ofsources where emissionmeasurements perevent were used include emissions from compressor driver exhaust, gas-operated pneumatic devices, glycol dehydratorregenerator overheadvents, and gas-operated chemical injectionpwnps. 

### 3.3 General Extrapolation Method<!logy Bynecessity, data in this project were collected for a relatively small percentage ofsources 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 ofprecision(given thenature ofthis study) and negligible bias. (See Section 3.4 for definitions ofprecision and bias.) The extrapolation approach is a method to scale-up the average emissions from a limited number ofsources to represent the 

### entirepopulation ofsimilar sources in the gas industry. The extrapolation approach uses the concept ofemission and activity factors to estimate emissions based on a limited number ofsamples. These factors are defmed in such a way that the product ofemission and activity factors equalsthe annual national emissions from the source category.
24Emission 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 industrypopulation ofthe source category. 

### 3.3.1 Sampling Approach Even ifthe overall precision ofan estimate is acceptable because the variability in the data is relatively low, the overall accuracy may still be poor ifthe data are biased. Several approaches can be applied to avoid bias. Because ofvarious practical limitations, neitherrandom sampling nor stratified random sampling 

### was feasible inthis study. Forthis reason, an alternate approach was used. \Vhile this approach is not a textbook samplingmethod, itis believed to bevery effectiveforthe specific needs ofthis project. This approach is similarto 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 ifa given source was a major contributorto methane emissions. Foreach source category, an initial estimate ofthe number of datapoints needed was calculated based on an estimate ofthe target precision and the estimated standard deviation for the source category. The accuracy targets for precision are based on the need to estimatethe 1992 national emissions to within 0.5% ofU.S. natural gas production with a 90% confidence limit. Sites were selected in a random fashion from known lists offacilities, such as GRI or A.G.A. member companies. However, the companies contacted were not required to participate, and a complete list ofall sources in the United States was generally not available. Therefore, the final set ofcompanies selected for sampling was not truly random. Eachcompany that agreed to participate in the program was asked to selectrepresentative sites for sampling, rather than one-of-a-kind facilities. 

### 25

### After alimited set ofdata 

### was collected, the data were screened for bias by evaluating the relationship between emissionrate and parameters thatmay affect emissions. It

### is important to realize thatjust becausea parameteror set ofstrata is 

### identified that 

### has a large effect on emissions from agiven source category, it does not mean thatthere is bias in the data. A second condition is necessary, namely, that the sampling procedure would have to produce a disproportionate number ofsamples in the strata. To determine whether

### this has occurred, infonnation is needed on the ratio ofthe total number ofsources in 

### agiven stratum to the total 

### number ofsources throughoutthe country. Ifthls 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 ofthe emission rate extrapolated to a national basis was evaluated and compared to the accuracy target. Where necessary, additional data 

### were collected in various stratato improve the precision ofthe national estimate of emissions from the source. The nwnber ofadditional data points needed to meetthe newly calculated accuracy target was computed based on the standard deviation and a 90% confidence interval. In some cases, variability ofthe emissions datafrom source to source is very 

### large. Forsource types ofthis nature, it

### is·norma11ypossible to reduce variability by redefining the emission factor orby stratification. This is important because reducing variability reduces the number ofdata points needed to achieve the accuracy target. 3.3.2 Redefining the Emission Factor 

### Forafew types ofsources, emissions can 

### be more accurately estimated when the emission factor is defined not as a simple average ofthe data but is expressed in terms ofakey parameterthat influences the emissions from the source. Since this would significantly reduce the variability, fewer data points are required to achievethe desired level ofaccuracy. For example, the internal combustion engines that drive compressors in the gas industry vary in size 

### 26(i.e., horsepowerrating). Ifdata were collected on individual engines in the industry, and an average emission rate perengine was established,thevariability from engineto engine would be very large because ofsize differences. However, ifthe emission factor for the engines is defined by horsepower ofthe engine (i.e., annual emissions perhorsepower), then the variability from engine to engine and therefore the number ofsamples required to reach an acceptable accuracy are both significantly reduced. As discussed previously, thenumber ofdata points required also may be reduced by stratifying on thebasis ofparameters that affect emissions. A source type can be stratified into categories withdifferent emission characteristics; the objective is to produce stratawith much less variability than thetotal data set. The sampling isperformed within the strata and because the variability within the strata is smaller, fewertotal data points are **require~** to achieve targetprecision. 

### 3.4 Accuracy A keypart ofthis project is the estimation ofthe accuracy ofthe annual national enusstons. Accuracy is dependent onprecision and bias, as discussed in Volume 4 on statistical methodology.6 Precision, the random variability in the measurement, is calculated rigorously 

### by propagating errorfrom each individual group ofmeasurements into the final numbers. However, bias, a systematic error 

### in the measurements must 

### be prevented ordiscovered and eliminated, rather than identified and calculated. 

### 3.4.1 Precision Most source activity factors and emission factors are made up ofan average of multiple measurements orcalculations. Therefore, assuming a nonnal distribution around a mean and error independence, standard deviations and 90% confidence limits can be calculated directly for each group ofmeasurements in an activity oremission factor.


### 27

### The confidence intervals or error bounds can be propagated through the addition ofmultiple 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 ofrevealing some bias, there are no tests nor group oftests that wi!l reveal all possiblebiases. Assuming that a data 

### set has no bias is only a hypothesis, even after extensivetesting. 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: peerreview by experts, subdivision ofthe data into strata,. and extrapolation by different parameters. Some ofthese 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 ofthe study to examine the data 

### "With industry representatives and otherexperts 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 ifit existed. One example ofthe success ofthis review process is the identification ofregional 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 ControlApproach 

### As defined during the 1980s quality initiatives, quality is conformance to requirements. 31 

### The programmatic quality assurance requirement ofthis project was to develop a 

### 28national emission estimate ofdefined 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 ofthe datacollected and the resultant conclusions. Other 

### QAJQC activities associated withthe 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 ofproject phases that had clear QC goals andthat outlined QAreview steps. This allowed the nature and breadth ofdata collectionto be modified to ensure consistent data collection with minimal bias. The

### three phases ofthis study, and their inherent QA/QC goals were: Scopingphase--The sCoping phase included defining the boundaries ofthe natural gas industry and a comprehensive characterization ofall equipment in the natural gas industry that could 

### be a source ofmethane emissions. This process minimized the potential bias ofmissing sources ordoublecounting sources in other industries, such as the oil production industry. Steps takenduring this planning process ensured that all sources ofemissions were examined and that the accuracy and bias goals ofthe 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 

### 29calculate each emission factor. Measurement methods were validated through controlled experiments (laboratory), tests inthe field, and proofofconcept tests designed to quantify the accuracy inthe 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 werepeerreviewed beforethey were implemented. Implementation phase--The implementationphase focused on collecting the final field data required for emission factors and activity factors based on the developed methodologies. QC steps were used for datacollection, and QA was performed on the datacollected. Data were screened for bias and fwther stratified ifa relationshipbetween the emission rate and a parameteraffecting emissions 

### was identified. Uncertainty bounds were calcuiated to 

### quantifY precision and results were compared to the targetprecision. Where necessary, additional data were collected to improve the precision ofthe 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 designedto control the data collection and datahandling efforts to ensure consistency and reliability throughout the process. The QC activities incorporated throughout theproject included:

• Proofofconcept tests; • Protocols for test methods and datacollection; • Methodology fordatahandling, and extrapolation; and 30• Established documentation, reporting, and filing systems. Quality assurance activities are generally considered those that are independent ofthe data gathering effort, per se. The QA activities incorporated throughout theproject included:
• Quality audits; • Industry peerreview; • 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 andprotocols for data collection and handling. The most significant QC step was the development and weofgeneral methodologies that ensured consistent results. During the methods development phase, a sampling plan and data gathering protocol were developed. Most ofthe plans and protocols are outlined in the Volume 3 Methodology Report,5 or inthe Phase 3 Program Plan. 27 Emission factor measurementprograms 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 collectionduring representative operations, Instrument calibration, Analysis ofblank samples, 

### 31

### Analysis ofknown standards, and Analysis ofreplicate samples. In addition, where new measurementtechnologies were being applied, proofof concept tests were performed and documented. For example, for the 

### new distribution tracer measurements ofmeter 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, proofof concept tests were performed and are reported in

### a separate volume.20 

### Similar QC efforts and proofofconcept tests exist for underground pipeline leak measurements: QC plans were documented in

### the Phase 3Program 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 otherfugitive emission efforts, are outlined 

### inthe 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 ofactivity 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 ofdata

**entry~** 

### • Comparison among site entries to identify unusual data; 

### and • Verification ofWlUSual 

### 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 ofthis program and for which no published field reports exist. Forexample, one production company provided their compressordatabase which was used in the productionactivity factor estimate of 32horsepowerhours. 13 In these cases, QC efforts performed bythis project were limited, and QA efforts were therefore intensified, as is described in thefollowing section on QA. Data on emission and activitymeasurements were collected and condensed electronically, so that auditable electronicfiles contain all oftht.: major datapoints, calculations, and·extrapolations. Manyofthese 

### data are also printed inthe field reports, and in the reports comprising the 15 volumes ofthis 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 Factorreport7 and the Statistical Methods report. 6 3,5.4 

### Quality Assurance The main goal ofthe QAprogram was to ensure the validity ofthe estimate through data audits, resultreviews, and statistical analysis. As with the QC steps, one ofthe main goals ofQA was to identify and eliminatebias. The main QA steps were audits, statistical analysis, technical review, and comparisonto other studies. Each ofthese are described in the following paragraphs. Quality audits ofthe databases and calculations were conducted to verify accuracy ofthe mathematical applications. Audits included the follo\Ving:

• Checks ofthe calculations made by spreadsheets. These were provided by hand checking the results using theequations 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 ofconformance to known technical relations and first principles. Forexample, in the QC checks ofactivity factor data provided on annual operating hours for compressors, data were rejected ifoperatinghours exceeded 8760,the maximum number ofhours in a year. 

### 33

### QA audits were also performed on industry databases provided byparticipant companies. In a few cases, specific company data were provided to a particularemission estimationprocess, such as compressorHP-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 letterto the particular company. These data were checked for completeness 

### by the project team, using follow-up questions to the supplier ofthe 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. Datathat were gathered 

### inviolation oftypical 

### QC controls such as consistently following a generallyaccepted measurement method. Forexample, pneumatic device emission rate data that did not follow the QC protocol ofa single measurement for a single device were rejected from the dataset. 

### (Some measurements were emissions from multiple devices; this rejected only 2 datapoints 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 6through !5• 17 

### in Table 2-1). Another QA stepwas 

### theuse ofstatistical analysis, using errorpropagation 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. Narrowconfidence bounds were assigned to well-known, often published values, where the confidence bounds were notpublished and the supportingdata 

### were not available to calculate a confidence bound (e.g., thenatural gas productionrate published 

### in GasFacfi33). 

### 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 sourcethat had 

### an insignificantcontribution to the end result. The method for the confidence bound is carefully documented for each value in the applicable emission characterization reports.

34In all cases,theresulting confidence limits on the emission rate (the product ofthe 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 ofpotential correlation between the data, andpotential bias effects. In addition, separate tests ofthe input data sets were performed. For example, outliertests were performed on input datasets. {See the 

### StatisticalMethods6report for further details.) Any anomalies were verified and documented orcorrected. Anothervery important and unique QA step was the extensive technical review process. All stages ofthis project received detailed review by an advisorypanel comprised of 

### gas industry experts and representatives from otherrelated industries, such as coal and oiL The panel approved the goals and scope ofthe project and verified that the general results ofthe project were acceptable. The advisory panel rr:.et six times during the 5-yearduration ofthe project to review and approve the methods and protocols. 

### In addition, the advisory panel reviewed the draft and final versions ofthe projectreports. Otherindustry reviewers were involved in the frnal stages ofthe 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 ofexpertise. The involvement ofthese reviewers served as a QA measure by ensuring that all emission sources were accounted for and that all data handling methods were representative ofthe natural gas industry. A list ofthe advisors and reviewers is included in Appendix D ofthis report. The reviewers met four times to examine the detailed results and review the project team's OMl QA efforts that checked for:
• Representativeness-Datawere analyzed to determined ifthe sample set wasproperly stratified with respect to pertinent emission affecting parameters and representative ofthe 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 ofnational equipment cotm.ts. 34 

### EPA's Office ofAir and Radiation (OAR) worked with 

### an independent team ofindustry experts to estimateproduction activity factors using 

### a consensus approach. Although 

### the EPA-OAR 

### results were not based onmeasured data, they

### provided an alternate method 

### for estimating 

### equipment counts and provided another check forpotential bias. The EPA-OAR results compared well to the results ofthis GRIIEPA-ORD project.



### 36

### 4.0 DETAILED RESULTS 

### The natural gas indus!Iy's total methane emissions are 314 Bscfforthe 1992 baseline year with a 90% confidence bound of± 

### lOS Bscf. (See Section 4.7 for further explanation ofthe confidence bound.) The total emissionscanbe expressed as a percent of 

### production: 314 Bscfis !.4%ofgross 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 

### 42through 4.4. The largest sources 

### within each segment are discussed in Section4.5. The emissions are also presented for different types ofequipment 

### in Section 4.6. 4.1 

### Emission Type Summaor 

### This section presents a summary ofannual 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 ofmethane 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 ofemissions by type for the gas industry. The major contributors to each emission type are discussed 

### in more detail in the following subsections.



### 37

### TABLE4-1. UNITED STATES NATURALGAS INDUSTRY LARGESTMETHANE 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) Blowand 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 CompressorExhaust ( 4.4)
"Includes wells at storage facilities. 

### TOTAL! Annual Methane o/o ofTotal Emissions (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.and fugitive emissions. Since 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 showthe major contributors to fugitive emissions. Total fugitive emissions for the natural gas industry are 195.2 Bscf Undergrmilld 

### pipeline leaks account for 48.4 Bscfoferniss1ons, and include leaks from production gathering lines, transmission pipelines, and distributionpipe systems. Equipment leaks account for 146.9 Bscf, and are typicaiiy low-level emissions ofprocess fluid (gas or liquid) from the sealed surfaces on above-ground process equipment. Specific fugitive emission sourcetypes include various fittings such as valves, flanges, pump seals, compressorseals, orsamplingconnections. These components represent mechanicaljoints, seals, and rotating surfaces, which in time tend to wear and develop leaks. Facilities and equipmentthat are significant contributors toequipment leak emissions include: production facilities, gas processing plants, compressor stations/facilities in transmission and storage, and meterand pressure regulating stations in transmission and distribution". The following subsections describe each ofthe majorfugitive emission sources in more detail.
Production Facilities 9"/o Gas P1ants 13%

M&PR Stations 16% EQUIPMENTLEAKS 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)



### Figure4-3. MajorContributors to Fugitive Emissions- By 

### Segment Facilities

### 4.2.1 EquipmentLeaks Fugitive emissions from equipment leaks in the natural gas industry were estimated to be 146.9 Bscf. Ofthis 

### 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 ofproduction 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 componentmethod. Tracertests are conducted 

### by releasing a tracer gas such as SF6 

### at 

### akno'"'n constant rate near the methane emissions source. The concentration ofmethane and tracer are then measured downwind. Themethane emissions 

### are calculated based on the relationship that the ratio ofemissions 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 8on 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 ofthe basic components, such as valves, flanges, seals, and other connectors that 

### comprise a facility. The average emission rate for each type 

### ofcomponent is determined by 

### measuring the emission rate from a large number ofrandomly selected components from similar types offacilities throughout the country. By 

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

### the average number ofcomponents 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 ofthat 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 ofdifferences 

### 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 ofcompressor-related components and station (non-compressor related) components. Table 4-2 presents an example ofthe 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 ofthe 

### flow rate ofinert 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 42Storage Facility (noncompressor related compone!lfs)

Injection/Withdrawal Wellhead TABLE 4-2 EXAMPLE OFNATIONAL 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 ofa 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 ofthe facility types that were significant contributors to total national emissions. 

### Compressor Stations (Transmission and Storage) Compressor stations in

### transmission and storage are one ofthe largest sources offugitive emissions. Equipment leaks from transmission compressor stations were separated into 

### two distinct categories because ofdifferences in 

### leakage characteristics:
• Station components including all sources associated with the station inlet and outlet pipelines, meter runs, dehydrators, and 

### other piping located outside ofthe 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 reliefvalves, 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 ofthe 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 bedepressurized when idle, and typically leak when the compressor is operating or idle. There are two primary modes ofoperation 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 ofthe much larger suction and discharge valves. Separate component emission factors were developed for the two operating modes ofthe compressor blowdown open-ended line. An 

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

45

### determining the fraction oftime transmission compressors operate 

### in each mode (i.e., pressurized and depressurized). The majority ofcompressor fugitive emissions result from the transmission and storage segments, where a high 

### number ofvery large compressors exist. Since compressors are also a part ofproduction 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 GulfofMexico 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 ofthe 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 GulfofMexico; 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 Bscfto 

### national annual methane emissions. The majority offugitive 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 of8 gas processing plants were measured using EPA protocol approach.



### 47Meterand Pressure Regulating Stations Fugitive emissions from meter and pressure regulating stations (M&PR stations) contribute 3I.8 Bscftototal annual methane emissions. Emissions from this category ofsurface equipment were measured using the tracer measurement approach, and therefore were reported separately from othercategories ofsurface equipment fugitives. A total of95 M&PRfacilities were measured using the tracertechnique. 12 The primary losses from M&PR stations include both fugitive emissions and, in some cases, emissions from pneumatic devices. Since the tracermeasurement 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 positionthe pressure regulators. These gas-operated pneumatic devices bleed to the atmosphere continuously and/or when the regulator is activated for some system designs. Otherdesigns bleed the gas downstream into the lowerpressurepipeline and, therefore, have no losses associated with thepneumatic devices. Tracermeasurements were used to derive theemission factors for estimating emissions from M&PR stations in both the transmission

### and distribution segments ofthe gas industry. The total emissions are a product ofthe emission factor and activity factor, which were stratified into inlet pressure and location (above ground versus in a vault) categories to improve the precision ofthe emissions estimate. Metering/pressure regulating stations 

### inthe distribution segment include both transmission-to-distribution custodytransferpoints 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 ofthe 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. 

### CustomerMeter Sets Fugitive emissions from commercial/industrial and residential customer meter sets contribute 5.8 Bscfto 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 itselfand 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 ofthe GRI/EPA study, only about 20% ofthe meter sets screened were found to 

### be leaking at low levels. For the majority ofcustomer 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 ofoutdoor customer meters in

### the United States. The activity factor was based on published statistics including abreakdown ofresidential customer meters by region in 

### order to estimate the number ofmeter sets located indoors. Data were obtained from 22 individual gas companies within different regions ofthe United States to estimate the number ofindoor 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, andjoint and fitting defects/failures. Based-on limited leak measurement data from two distribution companies, leakage from underground distribution mains and services was targeted as apotentially large source ofmethane emissions from the gas industry. A leak measurementtechnique 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 aproduct ofthe emission factor and activity factor, and are stratified by

### pipe use (mains versus services) and pipe material categories to improve the precision ofthe estimate. The total annual methane emissions from underground pipeline leaks in all segments are 48.4 Bscf. 

### 50The soil oxidation rates ofmethane were experimentallydetennined to be a function ofthe methane emissions rate, pipe depth, and soil temperature. The methane leakage rate for underground pipelines 

### was detennined to be a function ofthe 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 ofthe type ofpipelines in service in the distribution segment, the overall leakage rateperpeak is lower. Therefore, the overall oxidationrates for distribution pipelines is higher than for transmission orgathering lines. Inthe 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 ofequivalent 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 dataproduced anoverall methane emissions estimate of41.6 Bscf, which includes an adjustment for soil oxidation. The largest contributor tothe overall annual emissions was cast iron mains, followed by unprotected steel services and mains. The average soil oxidation rate applicable 

### to distributionpiping was 18%, which primarily affects the emissions from cast iron mains, which have lowleak rates per leak. In the transmission and production segments, the estimated methane leakage was based on the emission factors derived from theleak rates measured on distribution mains and on activity factors derived from a nationally tracked database ofpipemileage/leak repairs. For transmission pipeline leakage, the estimated annua1 methane emissions were 0.2 Bscf, which includes an adjustment for soil oxidation.



### 51Forgathering pipeline inthe production segment, the estimated armual methane emissions were 6.6 Bscf. The estimated methaneemissions tothe 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 ofthe contributions to vented emissions. 

### Each ofthese are described in more detail in 

### the following sections.
Dehy. Glycol Pumps 12%

Blow andPurge 32% Dehy. Vents 5% Other 3%



### Figure 4-4. Contributions to Vented Emissions 

### 4.3.1 PneumaticDevices Pneumatics 48%

Pneumatic devices in the natural gas industry are valve actuators andcontrollers that use natural gas pressure as the force for valve movement. Gas from the valve actuatoris vented during every valve stroke, and gas may bleed continuously from the valve controller pilot 52as well. Pneumatic devices are a major source ofunsteady emissions and account for 45.7 Bscf ofmethane emissions. 14 Methane emissions from pneumatic devices were calculated based on field measurements, site data, and manufacturers' data. There are two primary types ofthese devices: I) control valves that regulate flow, and 2) isolation valves that block orisolate equipment andpipelines. Ofthe 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 ofequipment orsection ofpipeline. Alternatively, control valves typically move frequently to make adjustments for changes in process conditions, and some types ofcontrol valves bleed gas continuously. Emission factor estimates forpneumatic devices were based on a combination of site infonnation, manufacturers' data, and measured emissions from devices in the field. Each segment ofthe industry has very different practices regarding the use ofpneumatic devices. These differences and a summaryofthe data collected to characterize the different pneumatic devices are described below. 

### Production The production segment accounts for the majority ofthe pneumatic emissions: 31.4 Bscf, or 69% ofall pneumatic emissions. High pressure natural gas is used to operate most ofthese devices, since production facilities are usually located atremote sites. Natural gas is readily available and less expensive than compressed air or electricity at the remote sites. The majority ofdevices are used to regulate flow and can emit methane either ona continuousbasis oronly when the device actuates. Data were collected from 22 sites to detennine thefraction of continuous bleed devices versus intennittent bleed devices. A total of44 measurements of various device types 

### in field operation were used to estimate the emission factor. Inaddition, the four most common manufacturers ofthese devices were contacted for information regarding the 53

### characteristics ofthe devices that affect emissions. The total number ofpneumatic 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% ofall pneumatic emissions. Emissions were based on data collected 

### from nine gas processingplants and from the. four manufacturers ofthe devices observed. Ofthe gas processing plants surveyed, only one-half(56%) 

### use natural gas 

### to operate pneumatic controLlers and 

### isolation valves. (Other sites use compressed 

### airorelectric motors.) The 

### natural gas 

### powered isolation valves in this industry segment 

### are operated infrequently (once per month or onceperyear), 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% ofpneumatic emissions. In this industry segment, most ofthe pneumatics are gas-actuated isolation valves. Datafor these types ofdevices 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 ofoperating devices. Site data from 54 stations were also used to detennine the number ofdevices per station, which was extrapolated to a national number **ofpneumat~c** 

### devices in the transmission segment.

54Distribution Pnemnatic emissions for thedistribution segment are included in the "fugitive" emission factor for M&PR stations. The M&PRpnemnatics 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 ofunsteady emissions and accotmts for approximately 30.2 Bscfofmethane emissions.9 Blow(orblowdown) gas refers to intentional and unintentional venting ofgas for maintenance,routine operations, oremergency conditions. A piece ofprocess equipment oran entire siteis isolated from other gas containingequipment and depressured to the atmosphere. The gas is discharged to the atmosphere for one ofthe 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 enterthe equipment. 2) Emergency Slowdown- The gas is vented from a site to eliminate a potential fuel source. For example, ifanequipment fire begins at a compressor station, the station emergency shutdown and emergency blowdo'Wil system blocksthe 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 ofmethane blowdown released to the atmosphere are: frequency, vohune ofgas blowdovm perevent, and the disposition ofthe blowdown gas. Slowdown from maintenance releases were detennined by equipment category: compressor blowdown, compressor starts, pipeline blowdown, vessel blowdovm, gas wellbore 

### 55blowdown, and misceilaneous equipment blowdowns. Emergencyblowdowns refer to the unexpected release ofgas by a safety device, suchas a pressure reliefvalve (PRV), on a vessel or the automatic shutdown/emergency blowdown ofa transmission compressor station. Dig-ins, pipeline ruptures caused byunintentional damage, were also classified under emergency release ofgas and included in the blow andpurge estimates. Emission estimates for each industry segment were based on data from site visits orcompanytracked data. Blowand purge emissions from the production segment, accounting for approximately 6.5 Bscfofthe total blow and purge emissions, were based on data from 25 sites. Emissionsfor 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 Bscfand 2.9 Bscfofthe 

### total blow andpurge emissions, respectively. The distribution segment makes up about 2.2 Bscfofthe total blow andpurge emissions, and the emission estimate for this segment was based on detailed unaccounted-for gas studies from two distribution companies. 

### 4.3.3 DehydratorGlycol Pumps Glycol dehydrator circulationpumps are a major source ofunsteady emissions and account for I 1.1 Bscfofmethaneemissions. 17 These pumps use the high pressure ofthe rich glycol from the absorberto power pistonstbatpump the lowpressure, lean glycol from the regenerator. Thepump configurationpulls additional gas from the absorber along

### \\ith the rich glycol (more gas than would flow 

### with the rich glycol ifconventional 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 dehydratorequipment is often specified as a separate bid package, and the vendors most often use the Kimray gas pump 

### 56as their standardpumping unit. The pumps are an integral part ofthe glycol dehydrator unit and their emissions occurthrough the samepoint. However, the pumps are the cause for nearly half 

### ofthe methane emissions from dehydrators, so they are considered separately. Unlike chemical injection pumps which vent the driving gas directly to the atmosphere, dehydratorpumpspass the driving gas along with the rich (wet) glycol to the 

### reboiler. Therefore, methane emissions from the pump depend on the design ofthe 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 ofgas used by 

### these pumps. Gas-assisted glycol pumps were found almost exclusively in prod:.Iction dehydrators, with a few ingas processing. No active gas-assisted pumps were found during the site visits to transmission or storage facilities, which is consistent with thefact that largerfacilities tend to have electricity available. 

### 4.3.4 DehydratorVents Glycol dehydrator vents are a major source ofmethane emissions and account for 4.8 Bscfofmethane emissionsP The majority ofthe glycol dehydrators are located in production, butdehydrators are also used in 

### gas processing,transmission, and storage. Methane emissions are highest in the production segment; 71% ofthe total dehydrator vent emissions are attributed to dehydrators 

### in the production segment. ThiS is due to thehigh activity and emission factors for this segment. The absence offlash tanks 

### in most production dehydrators leads to an emissionrate pervolume ofgas dehydrated that is higher 

### in production than in the other segments. Glycol dehydrators remove water from the natural gasthrough continuous glycol absorption. The water-rich glycol is regenerated, orheated, which drives the waterback out of the glycol. The glycol also absorbs some othercompounds from the gas,including a small 57amount ofmethane. Themethane is driven offwiththe waterin the regenerator and vented to the atmosphere. The important emission-affecting variables for dehydrators are: gas throughput, use ofa flash tank, use ofstripping 

### gas, and use ofvent controls where the gas is routed to a burner. An emission factor perunit ofgas throughput was established for glycol dehydrator regenerator vents using three sources ofdata: I) computer simulations ofdehydratoroperations usingfirst 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 ofgas 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 ofunsteady emissions and account for 1.5 Bscfofmethane emissions solely in the production segment. 15 Emissionestimates for this source were based on data from 17 sites, 6 manufacturers, and emission measurements from a Canadian study. 39 The 

### total number ofchemical injectionpumpsnationally was extrapolated from data relating the number ofchemical injectionpumps to the number ofgas wells at 38 sites. Gas-driven chemical injection pumps use 

### gas pressure to move a piston which pumps the chemical on the opposite end ofthepiston shaft; thepowergas is then vented to the atmosphere at the end ofthe stroke. The powergasmay be natural gas or compressedair. Two types ofchemical injection pumps were observed: I) piston pumps, and2) diaphragm pumps. The larger diaphragm pumps emit more gas per stroke, and they are used to pwnpa higherflow rate ofchemical orto pump the chemical into

### highpressure equipment. Chemical injectionpumps are used to add chemicals such as corrosion inhibitors, scale inhibitors, biocides, demulsifiers, clarifiers, and hydrate inhibitors to operating equipment. 58These additives protect the equipment orhelp maintain the flow ofgas. 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 atthe well sites, so that the chemical can protect all ofthe downstream and downhole equipment. Most ofthe 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 injectionpumps inproduction 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 otherregions use the pumps frequently. Manypumps also have seasonal operation since they protect against hydrate formation, which wintertemperatures exacerbate. Onlya 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 CombustedEmissions Combusted emissions result from incomplete combustion ofmethane in burners, flares, and engines. Incomplete combustion ofmethane in compressor engine exhaust is the only significant source ofmethane in this category. Methane emitted to the atmosphere in compressor driver exhaust is a major source ofunsteady emissions and accounts for 24.9 Bscfofmethane emissions. 13 Methane emissions result from the incomplete combustion ofthe natural gas fuel, which allows some ofthe methane in the fuel to exit inthe exhaust stream. There are two primary types ofcompressor drivers: I) reciprocating gas engines, and 2) gas turbine drivers. A few compressors 

### in the industry are driven by othermeans such as electrical motors, but the majority are natural gas fueled. In 59addition to compressors, there are some natural gas drivers that run electrical generators at gas plants and compressor stations. Reciprocating engines emitapproximately 40 times more methane perhorsepower orperunit offuel consumedthan 

### gas turbine drivers. Reciprocating engines account for over

**two~**thirds ofall installed horsepowerinthe gas industry. Therefore, reciprocating engine compressordrivers account for over 98% ofthe methane emissions for this category. Emissions were determined by analyzing andcombining several databases to generate emission factors and activityfactors. A GRI database, the TRANSDATcompressor module,40 contains data from A.G.A. ontypes and models ofcompressors in use, as well asdata on compressordriver exhaust from the Southwest Research Institute (SwRI). A.G.A. gathers its data from government agencies, such

### as the U.S. Department ofEnergy (DOE) and the Federal Energy Regulatory Commission (FERC). and from surveys ofits member companies in transmission and distribution. SwRI data were generated through actual field testing. These data were combined to generate emission factors for thisproject 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., companydatabases, and site visits. GRI TRANSDAT includeshorsepower

### data for 7489 reciprocating engines and 793 gas turbines 

### in transmission. Transmission operating hours were based on FERC 

### datafor 1992 and one company's data for 524reciprocating engines and 89 gasturbines. Storage horsepower and operating hours were based on A.G.A. data and datafrom 11 storage stations, respectively. Since national totals for transmission 

### and storagehorsepowerwere available, no industry extrapolation was necessary for these activity factors. Productionhorsepower-hours were based on one company's data for 513 reciprocating engines and 6 gas turbines. Processing horsepower and operatinghours were based on 10 site visits and company data for II gas processingplants. 

### 60Activity factors for production and processing were extrapolatedto the industry using published data for national marketed gas production and gas processing, respectively. 4.5 I ,argest Sources byIndustry Segment This section summarizes the segment emissions andpresentsthe data by largest emission categories within each segment. Table 4-3 presents a summary ofemissions by gas industry sector. Figure 4-5 shows the same 

### data in a chart fonnat. 

### TABLE 4-3. SUMMARY OFMETHANEEMISSIONS Emissions as a Percentof 

### GasProduced (Gross Emissions (Bscf) Percent

**~fTotal** 

### Segment Eniissions (%) 

### NationalProduct) 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 ofnatural gas

**~** 22,132 Bscf(22.13 Tscf)41 (Accuracy Goal is± I!0.7 Bscfor± 0.5% ofproduction) 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 Figure4-5 are split into emission type in Table 4-4. The largest emissiontype forthe 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 inproduction because ofthe contribution from pneumatic devices. In tht• 

### other segments ofthe industry, fugitive emissions are the largest source. Segment emissions also can be broken down into the largestcategories that were presented in Table 4-I, U.S. Natural Gas Industry Largest Methane Emission Sources. These categories are actually a mixture ofemission types and 

### equipment types, since some measurementprograms were specific to a type 

### ofequipment (such as the buried pipeline leak statistics method), while others were not. Since the characteristics ofeach segment ofthe natural gas industry are quite unique, and since companies within each segment will want to know their segment's emissions, the data

### bave beenrecast 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 inchart 

### format. Table 4-5 shows thatthe largest sources inproduction 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. Table4-8 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 I0 Bscf, and four ofthese 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----

- 

### -- -

Combusted 

### 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 roundofferrors. 

### Natural Gas Industry 

### Emission Type as Emissions .. PercentofTotal (Bscl) (%) 

## 1-----------

------ ----------- -- --·-- 

### 195.2 62.1

- ----- ---- 

### -- - 

### 94.2 30.0

--- 

### --- -- - - --------- 

### 24.9 7.9 \-------- 

### -- ----- 

### -- --- 

### 314 100%)

### TABLE4-5. 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 DriverExhaust 8% 

### AnnualMethane 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% % ofSegmentTotal 

### 372 20.6 7.8 7.8 7.8 13.0 4.0 1.8 <0.1 

### 100

Fugitive Emissions 21%

Pneumatic Devices 37%


### Figure4-6. Production Segment Largest Sources 

### 64

### TABLE 4-6. GAS PROCESSING SEGMENTLARGEST SOURCES J 

### Annual Methane 

### Source Emissions (Bscf) '%ofSegment 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 DehydratorPumps 

### 0.2 

### 0.5 TOTAL* 

### I 36.4 

### 100 

### *Individual categories may not sum exactly to total shown due to rmmdofferrors.

Other Blow and Purge 6% Compressor Driver Exhaust

19% 8o/o **----~r---------_**



### Figure 4-7. Gas Processing Segment Largest Sources 

### 65 Fugitive Emissions 67%TABLE4-7. TRANSMISSION AND STORAGE SEGMENTLARGEST SOURCES 

### AnnualMethane Source Emissions (Bsc1) 

### Fugitive Emissions" 67.5 Blow and Purge 18.5 

### Pneumatic Devices 14.1 

### CompressorDriver 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 andPwge 1&'/o Exhaust 4% 10%

Pneumatic Devices 12% 

### o/o ofSegment Total 57.9 15.9 12.1 9.8 3.9 0.3 0.1 0.0 0.0 

### 100

I

Fu.o·u·,1eEmissions 58%

Figure 4-8. Transmission and Storage Largest Sources 66

### TABLE 4-8. 

### DISTRIBUTION SEGMENTLARGEST SOURCES Source Underground Pipeline Leaks Meter and Pressure Regulating Stations (includes fugitive and pneumatic device emissions) CustomerMeters Other 

### TOTAL*. Annual

**Metb~me** 

### Emissions (Bscl) 41.6 27.3 5.8 2.2 77.0 % 

### ofSegmentTotal 54.1 35.5 7.5 2.9 100 

### *Individual sources may not sum exactly to total shown due to roundofferrors.

CustomerMeters Other

Underground P/L Leaks 54% 7% 3%



### Figure 4-9. Distribution Largest Sources 

### 67 M/R. Stations 36%

### 4.6 EguipmentEmissions 

### The data presented in Sections 4.1 through 4.4 and in the 

### Sununary Table in Appendix A are grouped 

### by emission source oremission category. An alternate method for 

### grouping the emissions is by equipmenttype.

**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. Forexample, this grouping would allow a company to make a betterchoice 

### between turbine and 

### reciprocating compressors, if

### methane emissions from the compressors were important to the company. Instead ofusing onlythe difference in compressor exhaust emissions 

### between the two types, all ofthe compressor emissions should be used in

### the **comp~son.** 

### For example, all turbine compressoremissions would include: turbine compressorexhaust, turbine 

### compressorblow and purge, turbine compressor fugitives, and turbine compressorpneumatics. Unfortunately, recasting the data in 

### this fonn cannot be done with precision since many emission categories cannot 

### be accurately split into equipmenttypes. The methods used to estimate the emissions simply do notprovide 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 notprovide the data

### byenginetype, the data 

### cannot be accurately split into compressor start gas for turbines, compressor startgas for reciprocating engines, blowdovm gas for turbines, and blowdown gas for engines. The assumptions used to split emlssions into equipmenttypes 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 ofreciprocating compressors, combined with large emission rates from thefollowing: 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) EquipmentType 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. ·Gasprocessing 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 314tremendous mileage ofpipe 

### in the United States combined with relativelylarge dig-in and blow and purge emissions rates. Thethird highest equipment category isproduction separators (3 Bscf). Separators have a high emission rate duetothe large population, combined with high emission rates from associatedpneumatics, fugitives, and chemical injection pumps. There are four other equipment categories thateach exceed 10 Bscf: M&R stations, transmission station vessels and piping (i.e. everything but thecompressors), turbine compressors, andglycol dehydrators. Many ofthe categories in Table 4-9 have high emissionsdue to a highpopulation ofequipment, ratherthan due to a high emissionrate

### per equipment. Table4-10 recasts the

### total data 

### in Table 4-9 into equipmentemission factors by using aggregate activityfactors. Many of these aggregate factors are groupings ofmultiple categories, such as all types ofpipeline miles. They are therefore not as specific as the individual activity factors presented 

### inAppendix A, and should be used only for the purposes ofcomparison in this table. Table4-10 showsthat thehighest single sources onthe list are gasplants and transmission and storage stations. These are large facilities with largeequipment counts that result in relativelyhigh fugitive and blowandpurgeemissions. The highest emission factors for individual equipmenttypes are : I) compressors, 2) glycol dehydrators, 3) separators, and4) M&PR stations. Each ofthese are explained 

### in more detail below. While turbine compressors havethehighest emission rates percompressorunit (due to fugitives and blowdowns), reciprocatingengine-drivencompressors have higher methane emissions permillion horsepower hour. This makes sense because turbine drivencompressors have specific maintenancepracticesthat result 

### in higherblowdown and fugitive emissions on a per compressor basis, yethave far lowerdriver exhaust emissions on a perHP-hrbasis.

70

### TABLE 4-10. ESTIMATED EQUIPMENT EMISSION FACTORS Estimated Aetivity Estimated Emission Factor(Msef/equipment) EquipmentTypes Factor Fugitives 

### ! Vented Combusted i Total Reciprocating 29,000 compressors 2,327 222 832 3,381 Compressors 102,500 MMHp-hr 658* 62.3° 240* 960* Total Pipelines (Gathering 1,620,000 miles 29.9 7.1 37.0 Transmission, Distribution) 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 14,430 Vessels/Piping Turbine/Centrifugal 1,540 compressors 9,530 268 164 9,962 Compressors 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 Table4-8 Note: * Mscf/MMHp-hr, not perequipment



### 71Glycol dehydrators have high emission factors due to contributionsfrom multiple 

### sources on the dehydrator: the glycol vent, the glycol pwnp, fugitives, and pneumatics. The separatoralso has high emissions, mostly due to the

### high numberofpneumatic 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% ofnatural gasproduction. This goal 

### was established based on theaccuracy needed for constructing emission inventories for use in global climate change models and-for assessing the validity ofthe fuel switching strategy. Accuracy, which is made upofprecision and bias, 

### has been rigorouslypropagated through the calculations usingtechniques described 

### in Volume 4 on statistical methodology. 6 Thepropagation oferrorresulted 

### in a calculated uncertainty of± 89.6 Bscf(0.4% ofgross production). However, this assumes that the errors arenormally distributed and that there is no correlation between sourcecategories. Sincethere are some correlated errors among categories, and since some categories might have lognormal distributions, the uncertainty estimate for thetotal emissions was modified. The effectofinter-category correlations 

### was calculated, and the additional uncertainty was added to the tmcertainty total. In addition, the effect oflognonnal distribution assumptions was also calculated. A pointmidway between the result for normal and lognormal errors 

### was used as a more reasonable conservative casethan is the result basedon the nonnal assumption. The midwaypointrepresents the possibility thatthere is asymmetry inthe distribution ofthe errorinthe industry emission rate. \Vhile the selectionofthe midwaypoint is arbitrary, it is considered a reasonablepostulated conservative case, given the various issues discussed in the Volume 4 on statistical methodo!ogy. 6



### 72Therefore, with asstunptions ofinter-category correlations and some lognormality, 

### the uncertainty is calculated to be ± 

### 104.6 Bscf, which is slightly under 0.5% ofnational production. The conclusion is that, under assumptions that are not unrealistically conservative, the target precision was achieved. Theproject has reached its accuracy goal for the annual emissions. The objective ofthe 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 tobe representative ofany company's individual emissions or operations. Also, although the project 

### has reached its accuracy goal for the total emissions, the percent accuracy ofan emissions estimate for a specific category will likelyhave a much wider confidence bound 

### than the national estimate.



### 73

### 5.0 ANALYSIS AND CONCLUSIONS 

### Aspresented 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% ofgross natural gasproduction (i.e., 1992 gross production was 22,130 Bscf). 

### As part 

### ofthis program, arigorous calculation ofthe lUlcertainty 

### in emissions from the significant sources 

### was made to help plan the program. 

### An overall accuracy target of 0.5% ofnatural gas production(± Ill Bscf) was set as a benchmark to addressthe fuel switching 

### issue. The overall accuracy ofthe total methane emissions estimate generated from this program is± I06 

### Bscf, or 0.5% ofnatural gas production. Therefore, the accuracy goal originally set forth for the program has been met (see Section4.7). 

### 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 gas industry (based upon the new GRJ/EPA estimate) accounts for !9%to 21% oftotal U.S. methane emissions. According to the RTC, landfills (421 to 6!4Bscf) and livestock (328 to 546 Bscf), each has higheremissions of methane (Figure 5-1). Natural Gas Systems 200.4

15% LivestockManure 9% Other 6% Landfills 31%



### ----~Domesticated Livestock 19% 

### Figure 5-L Contribution ofMajor Methane Sources to Total U.S. Anthropogenic Emissions 74

### The following sections analyze the results ofthe GRIIEPA study in

### various contexts. Section 5.1 uses the results to examine the validity ofthe fuel switching strategy. Section 5.2 compares the results to previous estimates. Section 5.3 discusses trends in the natural gas industry thathave changed total emissions since the base year of 1992. Finally, Section 5.4 summarizes some ofthe key lessons learned during this study. 5.1 

### Impact ofNatural Gas Use on Global Warming 

### The primary purpose ofthe GRJ/EPA methane emissions study 

### was to help answer the question ofwhetherthe strategy ofswitching from otherfossil 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 ofthese gases on the atmosphere are needed. For fossil fuels, only emissions ofcarbon dioxide (C02 ) and methane play a significantrole. Formethane emissions, it is important to account for emissions from the production ofgas, oil, and coal and also from thetransmission and distribution of natural gas. Methane emissions from the transportation anddistribution ofcoal and oil are negligible, as are methane emissions from end-use combustion. Nearly all the C02 emitted results from end-use combustion ofthe fossil fuels. 31 Only 7 to 9% ofthe 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 throughproduct transport. Approximately 1% ofthe C02 emitted from coal is associated with production, processing and transportation.42 After determining the emissions ofC02 andmethane overthe fuel cycle for each fossil fuel, the second step is to determine the impact ofthose emissions on global wanning. This is a difficult problem because C0 2 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 ofa given greenhouse gas on global warming compared to C02• The G\VP can then

### be used to convertemissions ofone greenhouse 

### 75gas, such as methane, into equivalent quantities ofC02• For example, 

### ifthe GWP ofmethane was seven, then one pound ofmethane would have the same impact onglobal wanning as seven pounds of

### C02• The impact ofgreenhouse gases such as C02 and methane is dependent on the amountofinfrared energy they absorb (referred to as theirradiative forcing) 

### and their concentration. Since the concentration is a function oftime, the GWP is calculated by integrating the ratio ofthe impact ofmethaneto theimpact ofC02 as the concentration ofthe gases decreases 

### with time. The value ofthe GWP is highly dependent on the timeperiod over which the integral is evaluated because the lifetime ofmethane 

### is significantly shorterthan the lifetime of C02• Some studies selecta period long enough for concentrations ofboth gases to decrease to the original value (approximately 

### 500 years), while others have chosen a shortertime period of 50 to 100 years. The GWP for methane is approximately 6.5 for an integration interval of500 years, while the value ofthe GWP using a 50-yearperiod 

### is 34. Faced with such a large difference, two approaches were takento examine the validity ofthe fuel switchingstrategy. The first approach is to determine the breakeven percentage. The breakeven percentage is the amount ofmethane 

### 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 ofmethane that would have to be leaked to eliminate the inherent advantages that gas has because ofits lower C02 emissions). Comparing the break:even percentage to the 1992 emission estimateprovides an indication ofthe advantage that natural gas has overcoal oroil. 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 ofthe fuel switching strategy. The analysis presented inAppendix B indicates that between 8 and 34% ofthe natural gas produced would have to be lost to the atmosphere for natural gas to havethe same 76impact on global warming that coal has, depending onwhether the GWP was evaluated over a 50- or 500-yeartime period. A similar comparison for oil indicates that methane emissions from natural gas operations would have to 

### be between 5 and 23%

### ofproduction 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 studyfound 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 eventhe upper limit ofthe percent 

### ofgas lost per gasproduced from an incremental increase in gas use (i.e., 1.38% compared to 1.42 forthe 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 overthe fuel cycle by

**con~erting** methane emissions to "equivalent" 

### C02 emissions. Since the GWP is a factor that relates the impact ofreleasing a potuld ofmethane on global warming to that ofreleasing a pound of

### C02, the GWP can be used to convert methane emissions into equivalent amounts of

### C02• Forthe fuel switching analysis, emissions are expressed as the mass ofequivalent 

### C02 emissions per unit ofenergy (based on the higher heating value ofthe fuel). Thus for an energy requirement ofone million Btu, the equivalent C0 2 emission contribution ofeach fuel can be compared. Table 5·1 presents the results ofthis comparison for GWPs of6.5 and 34. (A more detailed discussion is presented in Appendix B.) Table 5-l also showsthe ratio ofequivalent 

### 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 comparedto 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 

# I Equivalent CO,Ratio Fuel Source

**~** 

## 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 ofthe fuel switching strategy based on examining the equivalent C02 emissions from each fuel supports the conclusion reached 

### by evaluating the fuel switching strategy using the breakeven percentage. Based on the results ofboth 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 

### itreasonable to recommend switching from oil or coal to natural gas as a strategy for reducing the U.S. contribution to global climate change?" Theproject sponsors agreed that it would not beprudent to attempt to answerthe second question unless an accuracy goal for the emission estimate of± 0.5% ofgas production could be achieved with 90% confidence. Anemission estimate with this degree ofaccuracy, therefore, became the project objective. A literature survey conducted at the outset ofthis project verified thatprevious studies contained insufficient data, individually orcollectively, to meet the accuracy goals ofthis project. The majority ofstudies that were found during the literature survey employed a method common at that time in which "unaccounted-forgas" was assumed to be equivalent to losses to 

### 78the atmosphere.44• 45•

46•

47 "Unaccounted-forgas" 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 writtenbyPipeline System Incorporated (PSI) and funded by EPA-OAR and GRI in 1990.48 Thepurpose ofthe early GRIIEPA study was to initially guide the more comprehensive GRl/EPA efforts that are presented in this report. The early PSI study produced anestimate showingthat methane emissions were 1% ofgross 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 estimatedthat methane emissions from the natural gas industry were between 0.55 and !.07% ofgrossproduction for 1990. 3 This study provided a reasonable synthesis ofexistingdata atthat timebutdid notexpand the database. The needremained for anextendedfield sampling program and a statistical framework within which the datacould be analyzed and accuracy targets could be calculated. The 140 Bscfdifference between the emission estimates from theRTC (110 to 220 Bscf) andthe GRIIEPA study (307 Bscf) result from recent datathat were not available at the timethe RTC 

### was written. The GRIIEPA study used new data torefine many source categories. The single category withthemost significant difference was fugitive emissions, which accounts for almost 90% ofthe difference between the RTC and the GRI!EPA reports. The fugitive differences result from two major sources ofnew

### data: I) compressorcomponents (82 Bscfdifference), and 2) distribution sources (60 Bscfdifference), such as pipelines, meter and regulation (M&R) stations, and customer meters. Compressor components, which are very large sources offugitive emissions, were measured as part ofthe GRIIEPA study, but no measurements were available atthetime ofthe RTC. Compressorcomponents in processing, transmission, and storage facilities resulted in GRI/EPA estimates of82 Bscf; these components had not been accounted for by the RTC.

79

### The GRIIEPA reportalso refined the estimates for leakage from distribution pipelines and M&R stationsthrough additional data gathering efforts. When the RTC was prepared, the onlydata available on pipeline leakage were for two very tight distribution systems 

### that had very little cast iron pipe. In addition, no data were 

### available on the number and 

### type of M&R stations used in the gas industry. These data were gathered duting the GRI/EPA study. Also, emissions from customermeters, which were not included in the RTC, were included in the GRI/EPA study 

### and measured tobe 6 Bscf. The new GR!/EPA data show that the total distribution segment emissions are approximately 60 Bscfhigherthan 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 ofgas producedhas increased and because gas industry 

### practices have changed. In 

### 1993 ajoint industry-governmentprogram was started to reduce emissions. The 

### impact ofincreased production and changes 

### inpractices is discussed in

### more detail in the following subsections. 

### 5.3.1 IndustryPractices to Reduce Methane Emissions The natural gas industry has always been concerned with reducing natural gas losses. Every year the industry'spractices continue to evolve and many companies have policies to recover gas orreduce losses. Examp(es are company programs to reduce losses through fugitive leak detection and repairprograms (LDAR) for underground piping and above-ground facilities. Also as a result ofthis study, a number ofcompanies became aware ofways to reduce operating costs while reducing emissions, and many ofthese companies are implementing cost/emission reduction programs. In 1993, ajointindustry-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 

### 80cost-effective practices. The EPA49 and industry identified several best management practices 

### (BMPs) in each sector ofthe 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 ofturbines at compressor stations 

### in lieu ofreciprocating 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 otherpractices that cost-effectively reduce methane emissions. As ofApril 1996 the program included 54 partners. representing over 60%ofall transmission pipeline. 30%ofall distribution pipeline and 25% ofall U.S. natural gas production. Asthe new Producers Program (launched in March, 1995) gets under way and as newdistribution and transmission companiesjoin, the program is expected to continue to reduce emissions ofmethane by 35 Bcf through the year 2000.


### 81

### The gas industry may also decrease methane emissions in 

### the future as 

### it complies with maximum achievable control technology (MACT) standards forhazardous airpollutants (HAPs). The MACTrule will result in 

### areduction ofcertainhydrocarbon emissions and may also reduce methane emissions. However, the actuai impact ofthe MACT is unclear at this point 

### in time, due to questions on the language ofthe final rule,the compliance schedule, source applicability, and the required control technologies. Sincethe Oil and Gas MACT Rule is scheduled forpromulgation in !997, the only information publicly available is from the preliminary Background Information Document (BID)." The effect ofthe Oil and Gas MACT on methane emissions cannot be easily determined because the language of theMACT does not specifically address these emissions. The BID suggests that glycol dehydrators and some sources offugitive emissions will require controls for HAP emissions. Depending on the kind ofcontrols implemented by the industry forthese sources, methane emissions may bereduced 

### as well. The preliminary draft 

### MACT proposes that equipment leaks at major sources, including gas processingplants and offshoreplatforms, must 

### be controlled by a LDARprogram. Ifthis requirement becomes part ofthe final 

### rv!ACTrule, methane emissions from fugitive sources in the gas production andprocessing segments wili 

### decrease. 5.3.2 IncrementalIncreases in System Throughput 

### As part ofthis program, astudy 

### 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 smallerthan the increase in system throughput.



### 82This study examined the consequences ofincreasing gas sales by 5, 15, and 30 percent underthree scenarios: uniform, winterpeak, and summerpeak load profiles. All segments ofthe gas industry were examinedto determine the percent increase in equipment that would 

### be needed in order to meet the increased demand. Thepercent increase inemissions 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. Themost realistic scenario assumes that the system will be expanded using currenttechnology, 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 of5% 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 ofthe 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/StatisticalMethods Because ofthe complexity and diversity ofthe natural gas industry, a detailed plan was implementedto meet the goals ofthe program.27 Some ofthe 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 dependentupon the source population; • Samplingtechniques and statistical methods to minimize bias in

### a dataset; • Use ofaccuracy targets to planthe program and allocate resources; and • Statistical tests to handle small datasets that are highly variable. Sampling Technique/Bias Minimization 

### Because ofthe complexity and often unknown equipment populations for a given source within 

### the gas industry, the selection ofaproper sampling approach 

### was not straightforward. For some sources, such as production separators, even the population size was not knovm at the onset ofthe program. These factors made the selection ofrepresentative 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 similarto disproportionate stratified random sampling, was used. The sampling approach included selecting sites from known lists offacilities in 

### as random a fashion as possible. However, the companies contacted were not required to participate and a completelist ofall 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 ofcompany-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 bythe parameter(s) found to significantly influence emissions. Because the sample· set collected was not necessarily representative ofthe nationwide proportions ofsites 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.



### 84Othertechniques employed to minimize bias included evaluating regional differences in operating practices orgas composition. In many cases, regional differences were found and hadto be accounted for in the emissions estimation approach. A group ofindustry 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 identifiedpotential biasesthat were eliminated through changes to techniques orthrough additional datacollection. Use ofAccuracy Targets To effectively allocateresources within the budget constraints ofthe program, accuracy targets were established for each emissions source such that resource could beassigned to emission sources based on the impact ofeach source on accuracy. An overall target accuracy was set forthe industry-"Wide methane emissionsestimate, 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 precisionestimates ofthe activity and emission factors. Afterthe individual source target accuracies were calculated, the required number ofadditional samplesneeded to meetthe target 

### was calculated. By setting accuracy targets for individual sources, small, highly uncertain sources ofemissions could then be appropriately handled. This process was used continuously throughout the datacollection phase ofthe program to help direct the most efficient use ofresources required to meet the overall program goal.



### 85

### 5.4.2 Measurement Methods 

### A number ofunique measurement methods were developed and tested as aresult ofthis program. Many ofthese methods are applicable to sources outside ofthe natural gas iniustry. The most noteworthy ofthese are listed and described below:
• High flow device for fugitive emissions measurements; • Tracergas measurement method for estimating emissions from meter and pressure regulating stations; • Acooperative 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 MeasurementDevice 

### At the beginning ofthe GRI/EPA methane emissions study, it was clearthat 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 ofthe changes thattook place in 

### the industry overthe past 15 to 20 years. In addition, emission factors forgas processing, transmission and distribution equipment were needed since these had not been developed previously. The standard EPA approach for determining emission factors uses acombination ofscreening 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 ofthe leak. This is done for thousands ofcomponents at sites throughout the country. The leakrate is measured using the enclosure method for hundreds of leaking fittings ofeach type. 

### A correlation equation is developed that correlates the 

### 86concentration 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 anaverage emission rate (i.e., emission factor) is calculated for each type ofcomponent. The problem is that the scatter in the concentration versus emissionrate data is 3 to 4 orders ofmagnitude. Because the correlation is poor, thousands ofmeasurements 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 forproduction equipment, but also forprocessing, 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 ofthe leak rate, the operator can determine ifit is cost effective to fix the leak. 

### It also can be used to accurately measure the fugitive emissions from a facility and determine whetherthe facility is subject to regulations and costly control and reporting requirements. 

### TracerGas Measurement Method Tracertechniques 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 ofthese emission measurements was the same, but the application varied depending on the scale ofthe measurement. In each case, the tracer was used to measure the dilution ofthe methane from the source as it was transported to the receptor where 

### 87

### concentration

### was measw-ed. Forundergrotmd vaults and enclosures ofsingle above-ground regulators, air was flushed through the enclosed volume. The methane emissions were measured by measuring theresulting dilution with 

### a tracerreleased at a known rate while measuring both the tracer and methane concentrations. Forlarger sources such as M&PR stations,gas plants, and landfills, tracer was released at aknownrate 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 ofthe dilution ofmethane as it 

### was transported from the source to receptors and allowed the calculation ofthe source strength from the ambient methane concentration. Several lessons were learnedconcerning the application oftracers during this work. Real time instruments were used to track both the methane and tracerplumes 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 comparingresults 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 orunder differentmeteorological conditions. Traceremission measurement techniques have both advantages and disadvantages compared to techniques 

### that measure emissions from individual components or flux chamber measurements made at landfills ortreatmentplants. The accuracy ofthe tracertechnique is susceptible 

### to some meteorological conditions and interferences from other sources. However, the tracertechnique can provide the total site emission rate in a fraction ofthetime (a few hours underthe appropriate conditions) that is required using individual component techniques or flux chambers. At a natural gas facility, thistotal emission rate will include non-fugitive sources such as compressorengine 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 ofall known fugitive vented and combusted emissions to the total value measured using the tracer 

### 88technique. Itwas found that leakage from the blowdown valve 

### was overlooked by the component measurement method because 

### it was directed to a roofvent system. Dueto the inherent uncertainty ofthe component screening techniques originally used for the individual componentmeasurements, thetracer method was the most accurate method available for determining total emissions from a facility. The development ofthe high flow sampler during this project nowprovides a component measurement method ofthe same or better accuracy than the tracer method. Consequently, the best measurement method will often depend on the goals ofthe measurement work. Tracertechniques do not provide any data on the location ormagnitude ofsources within a site. Fora 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 tomiss 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 providethe best method ofemissions measurement. CooperativeIndustry Measurement Effort Early intheprogram, 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 forthe GRIIEPA program. However, this technique 

### was extremely costly to implement on a pertest basis, and dueto 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 ofcollecting data. The GRl/EP A program provided a detailed test protocol, specifications forthe measurement device, and training/auditing/support to the industry participants. The actual measurements were performed and funded by the companies agreeing to participate intheprogram. This cooperative effort proved to be a successful means to meet the objectives within the budget constraints ofthe GRliEPA program. 

### 89

### Mass BalanceMeasurementApproach 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!downstreammeterreadings. This effort did notprove successful due to 

### the many uncertainties in 

### mass balance measurements that could not be completelyresolved and emissions could not be determined to meet the accuracy target. 5.4.3 

### Significant Sources 

### Several significant sources ofmethane emissions were identified orfound to be much larger than anticipated. Compressor blowdown valve fugitives, M&PR stations, pnewnatic devices, dehydrators, and maintenance emissions all were detennined to belargerthan estimated by

### previous studies.



### 90

### 6.0 I. 2. 3.

4.

5.



### 6.

7.


### 8.

9. 

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### Radiation, Washington, DC, Aprill993. Harrrison, M.R., T.M. Shires, J.K. Wessels, and R.M. Cowgill. Methane Emission from the Natural Gas Industry, Volume 1: Executive Summary, Final Report,



### GRI·94/0257 and EPA·60Q/R.96·080a. Gas Research Institute and U.S. Environmental Protection Agency, June 1996. 

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### Stapper, C.J. Methane Emissions from theNatural GasIndustry, Volume 11: CompressorDriverExhaust, Final Report, GRJ-94/0257. 28 and EPA-600/R-96- 0SOk. Gas Research Institute and U.S. Environmental Protection Agency, June 1996. Shires, T.M. and M.R. Harrison. Methane Emissions from theNatural Gas Industry, Volume 12: PneumaticDevices, Final Report, GRI-94/0257. 29 and EPA-600/R-96-0801. Gas Research Institute and U.S. Environmental Protection Agency, June 1996. Shires, 

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### D. Methane Emissions from theNatural GasIndustry, Volume 14: GlycolDehydrators, Final Report, GRJ-94/0257.31 and EPA-600/R-96-0SOn. Gas Research Institute and U.S. Environmental Protection Agency, June 1996. Myers, 

### D.B. and 

### M.R. Harrison. Methane Emissions from the Natural Gas Industry, Volume 15: Gas-AssistedGlycolPumps, Final Report, GRJ-94/0257. 33 and EPA-600/R-96-080o. Gas Research Institute and U.S. Environmental Protection Agency, June 1996. Columbia Gas. AnEngineeringEstimate of the Incremental Change inMethane Emissions with Increasing Throughput in a ModelNatural Gas System, GRI94/0257.32, Columbus, OH, March I993. 9219.

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95

### APPENDIXA Summary TableofEmission Sources

A-1METJ.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 

# "" '''"' 

# "" ,:, 

# ., 

# ., Em

**I,~** ions (o( 'PRODUCTION Normal
**Fu~Wves** Gu WeHs (Eutemon 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 GasWells (Rest o1 US on ollofe) 00365 

## '""' 

# ""' 

# '-""' 142,771

**~'"** 

# " 36.40 '"""-" 

# ,..
**24~%** 27.85'!1. 453.08 GullolMe•lco {oll$ho,-e pnttms) 0.0223 11815 

# "" O"" 

# '·"" platform• 

# ,,. "" Sddlplat 

# "" 2892% 33.24% 571iJ01 R""l ofUS (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!ineleaks 

# "'"' '"'"' 2.10 0.030

**~0,200** mile• 

# ""' 

# "' scl<l/mile 107'!1. 106.00ll. 18772% 24289 Vented andcombuoted

O.olllna andWell 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 GasEngines 0.1287 

## '""' 2.10 

# "''"' 27,480 MMHPIIr 

# '""' 

# "'"'
**&<:1/HP~r** 

# "' 20031% 

# ""''"" 24307 RoutineMa1nte<>ance

WaiiWorkwe"' GuWelJs 

## oooo• 

# '"'"' 

# '"' 0.000

**9,3~2** w.o/yr 

# ,,. 2.454 ldylwo. 

# ·- ""'"'" 2746.84'!1. 1500.00 WellClean Ups (lPGuWds) 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 ConlpressorStJrts 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% 

# ""' Based on a Iota! ross national 

### w g p<oduction of 221329scffa< 1992. (b) Pre<;,$>On l>asod on a 00% conMence

**inre~** (c) **T~rg~!Preclslon** =100"(8_24/SQRT(ER)). where £R= eml$•tons in 9scf. Overall TPis +I· 110M9sc:l' Maximum Relallvl!r Catrg:ory TP 15 •I· 1500%. Mlnlmun Relativecategory TPIs +I· 75'11., where TP=targ8l p<eclslon {d) Con!.ervaliveP""'lsion based on uppeflimaofa 90'!1. confidence Interval. Thisconli<lence ln!erval is based on a lognormalassumpilon 6SCF EMISSION
**R~PORT** !(:11!6196Emission Type

**Val~**.. Units Units
**Sourct~** 

# "'

**pl~nl5**

**'~** scfdlplanl Reclp, Compressors 4,092 compreosors 11198 scld/comp **Cenlr!l~;al** Comp;enors 

# "' COinp!ISSOf$ 

# '""' Wd/comp Vented

**~nd** Combulle<:!

Normal OperalioM

**Comprt~ssor** Elchaust GnEng,nes 27,760 MMHPhr 0240 WIHPhr Gas

**Turbin~s** 32,910 MMHPhr 0.0057 sc!IHPhr AGRVun!s 

## "' AGRunltt. 

# .., ocld/AGR 

## .,,.., 

# ··- sc!IMMocf 8,630,000 MM5df"' wf/MMsd 

# "' gas plants

**ocf)l/pl~nl**

BSCF EMISSION REPORT W!MIGEmission 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) DehydratorVents (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 

## """"w MMW¥ 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_

, whereTP=ta:rg-ot predolon. lnloNIIIIs bandon • lgg-oormal Hsumplion., 100'(8 ;,>4/SQRT{ER)}, where ER,.
**emi•$ion~** In 81;(:!. CM>oall TP IS •I· 11086 8&ef Relative Category TP lo +/-

**1~.** Mlnlmun Relative Cat@GoryTPI• #· 75%. Mlere TP

**~** ta'ltel preciSIO<l. {d) **Ccn~eMt!i•e** pree<•lon b.as<>d on upper !lmltof a 90% confidence ln!e,....al. Thlo **ccn!.dtnct~ln!ervalll** basedon a logoorm•l assumption

!lSCf EMISSION REPORT IOJ!$00

### APPENDIXB Effect ofMethaneEmissions on GlobalWarming

B-1

### B.O EFFECT OFMETHANE 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 gasoperations was undertaken primarily because this information was needed to 

### determine ifit 

### makes sense to promote the increased use ofnatural gas as a strategy for reducing greenhouse gas emissions. This appendix attempts to

### putthe results into perspective by 

### examining whetherthe current estimate ofmethane 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

### perunit ofenergy generated

### than either coal 

### or oil. 1 

### However, methane, amore potent greenhouse gas than C02, 

### is also emitted in 

### the production, transmission and distribution ofnatural gas. The question raised was whether the fuel switching strategy is valid when emissions ofall 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 ofall greenhouse gases throughout the fuel cycle and to determine the impact ofthese gases on global wanning. Fortunately, in evaluating fossil fuel emissions, emissions ofgreenhouse gases other than methane and C02 

### are negligible and do not need to be considered. In addition, most ofthe C02 

### emissions result from fuel combustion and are accurately known. The uncertainty in estimating C02 

### emissions from production and transportation ofthe fuel is higher, but this is a relatively small value and does not have a large effect on the overall accuracy ofthe analysis. Estimates ofmethane emissions from natural gas operations priorto the GRJ/EPA study generally ranged from 2 to 5%ofproduction.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 ofthe fuel switching strategy is B-2in determining the relative impacts ofC02 and methane emissions on global warming. In order to simplify a comparison ofthe impact ofone greenhouse gas with another, a global wanning potential (G\VP) has been defined.6 The G\VP is an indexthatrelates the impact ofa given greenhouse gas to an equal amount (by mass) ofC02• Theprojected effect on global warming of a greenhouse gas over a chosentime horizon can be estimated bymultiplying the appropriate GWP by the amount ofgas 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 greenhouseheating potential depends on its lifetime andthe rate atwhich it is injected into the atmosphere. The G\VP for a trace gas addresses the neteffect ofthe radiative forcing and the lifetime ofthe gas bycalculatingthe time integrated radiative forcing ofa mtit mass impulse to the atmosphere.6 The G\VP is defined as the impact on global wanning caused by an incremental amount ofa given greenhouse gas divided by the impact ofreleasing an equivalent amount of C02• The GWP for methane can be approximated by the following equation: 

# i:' ACH CCH dt 

## • 

## • (Bl) GWPM = 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 ofrelease 

### (t,-t.,)

**~** timeperiod overwhich 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 ofmethane 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 ofmethane. IPCC haspublished theresults ofstudies to evaluatethe GWP for the various greenhouse gases. Their findings in 1990, 1992, and 1994 are shown inTable B-1 for thedirect 

### effects ofmethane for different integration time pericxls

**(t -tJ.** 
**~· 9**  

### The GWPs for methane, includingboth the direct and indirecteffects, are alsopresented in Table B-1 for 1990, 1994, and 1995. Because the IPCC believedthat the uncertainties in the indirect effects were very large, they decided notto publish a total GWP formethane in 1992. The change in values from 1994 to 1995 reflects a change in the lifetimes ofgases thatreactprimarily with tropospherichydroxyl 

### radical (OH) concentration, based on arevised estimate in the mean global OH concentration.6

B-4TABLE B-1. GLOBAL WARMING POTENTIAL OFMETHANE 

### Integration Interyal (years) DireetEffects Direetand IndirectEffects 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 ofmethane has the same effect.as 35 pounds ofC0 2 -Data notavailable 

### 500 9 7.5 ± 2.5 6.5 ± 2.3

As implied bythe variations inthe values shown 

### in Table B-1,there are 

### significant uncertainties in

### the GWP for methane. Some ofthese uncertainties result from differences in the models and mode! limitations. In 1990 and 1992 the lifetime ofmethane was determined by calculating the decay rate while the composition ofthe atmosphere 

### was held constant. Inthe 1994 and 1995 calculations,the atmosphere 

### was allowed to respond to the change 

### in methane 

### by coupling the methane chemistryto the calculation ofthe radiative forcing. This resulted in a reduction 

### in the OH concentration. Since OH is primarilyresponsible for the 

### oxidation ofmethane, the lifetime ofmethane 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 ofabout l0% based on an improved estimate in

### the concentration ofmethyl 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 ofthe incremental increase in methane. A relatively largepulse of methane is used 

### in the models to evaluate the GWP. Because the chemistry ishighly nonlinear, a largepulse can generate a nonlinearchange 

### in the lifetimeofmethane that would produce a much larger GWP than using a small pulse. • Grid size. Emissions ofNO" and othergases are smeared over large grid cellsand 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. • Nonmethanehydrocarbons (NMHCs). NMHCs are not included inthe currentmodels. Since mostNMHCs are more reactive than methane, the impactofincreased methane emissions on tropospheric ozone could be overstated. This would cause an erroneouslyhigh value for the indirect contribution to GWP for methane. Ofall the parameters discussed, however, the parameterthathas the largest effect on GWP is the time interval (t1-tJused 

### in evaluating GWP. There is not a consensus on the proper value, particularly between policy analysts and scientists. Somepolicy analysts use a time interval as shortas 50years. Formethane, the time interval is an importantquestion because there is a large difference inthe lifetime ofmethane (approximately 12.2 years± 25%) and the effective lifetime ofC0 2 (200to 250 years). Ifa timeperiod of50 years is selected, the GWP calculated bythe 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 ofC0 2• Theproblem isthatthis is onlytrue for the ftrst 50years. The amount and percentage ofmethane and 

### C02 in the atmosphere based on releasing 34 poWlds of

### C02for each pound ofmethane (i.e., a GWP of34) is presented in TableB-2 as a function oftime after release. At the end of50 years, the methane concentration would have decreased to a negligible level, but approximately 80% ofthe 

### C02 would remain 

### in the atmosphere and stili contribute to global warming.

B-6

### TABLE B-2. AMOUNT OFCO, AND METHANE REMAINING IN ATMOSPHEREWITH TIME

. 

### Time (Yrs.)' Greenhouse Gas.

. 

### 20 50 

### 100 %C02 90 

### 78 61 

### %CH 4 19 1.6 0.03 lbs. C02 b 31 26 21 lbs. CH4 0.19 0.02 

## --
a Lifetime ofmethane and C02 used were 12.2 and 200 years, respectively. b Assumed GWPM- 34. 

### 500 8



## -- 3



## --

If

### a 50-yeartime interval is used todevelop emission trading policies, then I pound ofmethane emissions could be traded for 34pounds ofC02• Theproblem is that after 50 

### years the 1poundofmethane would havedecayed to less than 0.02 pounds, but there would stili be 26 pounds ofC02 remaining 

### in the atmosphere. A century later, 21 pounds ofthe original34 pounds of

### CO, released would still be contributing to global warming. These contributions ofC02 are neglected by choosing a timeperiod of50 years. In considering the impact ofusing different types offuels, the time interval should be chosen so that both gases (inthis case methane and C02 ) would have time to decayto negligible values. This suggests that the time interval for evaluating the GWP for methane should be in the range of500to 1 000 years. Therecurrently is not a consensus onthe integration interval. Because the GWP could be as low as 6.5 fora 500-year integration interval and as high as 34for a 50-year interval (over five times larger), two approaches were taken inthis analysis to examine the validity ofthe fuel switching strategy. In the frrst approach, a breakeven percentage is calculated. The breakevenpercentage 

### is the amount ofmethanethat would haveto be released during the natural gas fuel cycle to eliminate the advantage thatnatural gas 

### has over coal and oil becauseof

### 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 thatnatural gas has over B-7coal 

### 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 ofgas 

### 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 ofequivalent 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 ofthe various fuels. The breakeven percentage (BP) is the amount of methane that would have to be released in 

### the production, distribution, and end use ofnatural gas for 

### it to have the same impact on global wanning that the fuel cycle ofcoal oroil would have. 

### The breakevenpercentage can be calculated knowing the GWP for the different greenhouse gases and the amount ofeach greenhouse gas released 

### perunit ofenergy 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 ofC0 2

### emitted from the fuel cycle for !06 

### Btu offuel G 

## = pounds of methane in 

### 106 

### Btu ofnatural gas 

### EM; 

## = pounds ofmethane emitted from the fuel cycle for I06

### Btu's offuel "i" 

### GWP 

## = global wamting potential calculated on amass basis 

## = subscriptdenoting type offossil fuel ( c for coal, 

### o for oil) NG 

## = subscript denoting natural gas 

### B-8M 

### subscript denOTing methane The results for coal are presented in 

### Figure B-1 as a function ofthe 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 perMMBtu, based on an HHV ofI,031 for natural gas and amethane composition of93.4% 

### E, 

## = 208 pounds perMMBtu 

## E,;G 

## = 127 pounds perMMBtu 

### Eo 

## = 184 pounds perMMBtu 

### EM, 

## = 0.6 pounds perMMBtu 

### EMo 

## = 0.06 pounds

### perMMBtu TABLE B-3. BREAKEVENPERCENTAGE (BP) FOR COAL AND OILFOR 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 of6.5, approximately 34% ofthe 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% ofnatural gas would have to be leaked to have the same impact. For aG\VP of34, 

### the percentage is approximately 8% for coal and 5% for oil. 

### All the breakeven percentages are substantially larger than the percent ofmethane emitted from natural gas operations (1.42% ofproduction 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 f
### Sf

### GWP

FigureB-1. Breakeven Percentage- Natural Gas Compared with Coal B-10Forthe fuel switching strategy, where natural 

### gas consumption could replace some ofthe energy supplied by coal oroil, 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 (abovethe 1992 baseline) are between 0.3% and 1.0%ofthe incremental increase ingas production, which is approximately one-third to twothirds ofthebase yearmethane emissions (1.42% ofthe total gasproduction rate). B.3 

### Emissions from Increased Gas Sales Aspart ofthe GRJ/EPAproject, a separate study 

### was conducted to detennine the percent increase 

### in emissions causedby an incremental increase in natural gasproduction and sales.w This study examinedthe consequences ofincreasing gas sales by 5, 15 and 30% under three scenarios: unifonn, winter

### peak, and swnmerpeak load profiles. All segments ofthe gas industty were examinedto determinethe percent increase in equipmentthat would be needed to meet the increased demand. Thepercent increase in emissions was then estimated based on changes in the current system thatwould 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 upperlimit, respectively. The assumption for the values listed Wlder "expected" was that the system will be expanded using thelatest technologies. The assumption for the values listed under "upper limit" was that the expanded system mirrors the existing system (i.e., newequipment ortechnologies for reducing emissions are notutilized). For most components, facility and operating changes are not linearly related to increased gas throughput dueto excess capacity orpractices suchaspipeline looping. Therefore, the study showedthat an increase ingas use for either a system mirroring current technology ora system utilizing the latest technology would increase emissions byan amount less than the B-!11;0 ' 

# - "' .· Total Emissions, Bscf % Increase over Base Case Total Emissions/ Total Gas Production Rate 

### TABLE B-4. INCREMENTAL CHANGES IN EMISSIONS RESULTING FROMINCREASED GAS SALES- EXPECTED CASE Increased System Throughput (%) Uniform Load

. WinterPeak 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 INEMISSIONS RESULTING FROM INCREASED GAS SALES- UPPER LIMIT CASE ·.··. Incre•sed System Throughput (%)

.. Uniform Load WinterPeak 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. Forthe expected system, total emissions (Bscfy ofmethane) increase by 1.4% to 12% overthe load scenarios examined for corresponding increases in gas sales of5% to 30%. The incremental methane emission increase (5 to 38 Bscfy), when divided by the incremental productionrate increase (I,110 to 6,640 Bscfnatural gas),results in emissions per productionpercentages of 0.3 to 0.6%. For the upperlimitcase, total emissions increase by 1.4% to 21% for 

### the same scenarios. The incremental methane emission increase for these scenarios (5 to 66 Bscfy), whendivided by the incremental production rate increase, results in emissions perproduction percentages of 0.4 to 1.0%. Compared to the base year emissions per productionpercentage of 1.42 

### %, the incremental emissionrates (

### .6.. methane emissions per 

### .6. productionvolume) are only one-third to two-thirds ofthe base emission rate. The incremental emissionpercentages 

### are much lower

### than the breakevenpercentages ofeithercoal (8 to 34%) or oil (5 to 23%) based on a GWP time interval of50 or 500 years, respectively. Therefore, this analysis supportsthe validity ofthe fuel switching strategy. 

### B.4 Equivalent C0 2 

### Emissions 

### The second approachused to examinethe validity ofthe fuel switching strategy is based on quantifYing the emissions ofmethane and C0 2 for eachfuel overthe fuel cycle and then converting the methaneemissions to equivalent C02 bymultiplying 

### by the 

### GWP. The GWP relates the radiative forcing ofothergreenhouse gases, such 

### as methane, to the radiative forcing of

### C02 over 

### aperiod oftime, accounting for the changing concentration ofthe greenhouse gases overtime. For

### a given fuel, the equivalent C0 2 emissions are calculated using the following equation: (B4)
where:


### B-!3J 

### Ea,, 

### GWP, E

) = 

### subscript that denotes the various fuel cycle operations (production, transportation, processing, and combustion) 

## = = = subscriptto denote the various greenhouse gases (GHGs) mass ofC02 

### emissions (lb)

### perenergy input global wanning potential used to convert emissions ofGHG, "j," 

### to equivalent C02 

### emissions mass ofothergreenhouse gas emissions (Ib)

### perenergy 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 ofthe fuel; and 

### 3) 

### C02 

### equivalent emissions that result from industry methane emissions. Forthe purpose ofthe fuel switching analysis, equivalent C02 

### emission factors of the 

### various energy sources are 

### reported as 

### the mass ofequivalent C02 

### emissions per

### unit of energy. Therefore, for an energy requirement ofone million

**B~** 

### the relative contribution of equivalent C02 

### emissions ofthe various fuels can be 

### compared. The energy content ofthe fuel can be expressed in terms ofeitherthe lower heating value (LHV) 

### or the higherheating value (HHV). 

### The difference between lower (or net) and higher (orgross) heating value is the heat ofvaporization (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 ofwaterproduced B-14heat ofvaporization ofwater at 25 

# oc The difference betweenthe higher and lowerheating 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 byall end-use equipment. Forthis study, the efficiencies ofend use equipment are not considered. The fuels are compared on a higher heating value basis, which is the conventioncommonly 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 contributionto global warming. 12 (Fuel combustion also contributes toN2 0 emissions, butthese emissions result primarily from mobile source combustion which is not considered 

### in this analysis. 12) Methane emissions resulting from the production ofgas, oil, and coal must be considered, as well as emissions from the transportation and distribution ofnatural gas. Methane emissions from the transportation ofcrude/refined product and coal are small, and methane emissions from the end use combustion ofnatural gas, oil, and coal are negligible. The results ofthe equivalent C0 2 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 of34. As stated earlier, the equivalent C02 emissions for each type offuel 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 of34) ofthe C02 equivalent emissions per MMBtu from natural gas are from end use combustion. Forfuel oil and coal, nearly 90% oftotal 

### B-15TABLE B-6. SOURCES OF C02 EQUIVALENTS FOREACH FUEL TYPE NaturalGas Fuel Oil Coal

. ·· ·. lbEq. lb Eq. lb Eq. CO, per .C02per CO, per Emission Type!Souree MMBtu 

### Data:

**Sourc~** MMBtu Data Source .· MMBtu • .Data Source Combustion offuel in end 115.6 Based on fuel 164.4 ABB/Combustion 205.8 EPA Greenhouse Gas use (direct C02) content and HHV Engineeringn Report 10 (this study) Methaneemissions from 24.5 GRJIEPA Methane 2.0 API Study 14 20.4 EPA Reports 12•1s production, processing, Emissions (this refining, transportation study) (methane converted to C0 2 

# "' ' based on a GWP of34) 

# - 0> C02 emissions during 11.7 AP-42 Emission 19.6 API Study 1• 2.1 Energy lntemationaJD production, 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, sincethey depend primarily uponthe carbon content ofthe fuels. Therefore, the uncertainty associated with thelargestportion ofthe equivalent 

### C02 estimate is relatively smalL The 

### C02 emissions from production through transport and the methane emissions from coal and oil operationsplay a much smallerrole in the overall comparison. Methane emissions comprise only 

### 16% ofthe equivalent 

### C02emission estimate for natural gas, 

### 1.1% for oil, 

### and 9% for coal. Thereforethe impact ofthe methane emission estimate is far lessthan that ofthe end use component. Methane emissions for natural gas are well kno\\tll (± 33 

### %), while the estimates for oil and coalmay havemuch wider confidence bounds (possibly with an upperbound larger

### than 1 00%). Therefore the equivalent 

### C02emission comparison fornatural gas is conservative, since the emissions from coal 

### and oil maybe much higher. The following sections on natural gas, 

### coal, andoil 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 ofnatural gas. This emission rate was calculated assuming the complete combustion ofmarketed natural gas (17.84 x 106 scffor 1990)"with a gross energy content of I031 Btu/scf12 and the corresponding composition of93.4% methane, 4.0%ethane, 0.5%propane, and 2.1% inerts. (Note: the molepercents ofethane, propane,

### and inerts were determined by weighting the respective higherheating values to achievethe desired methane composition and energy content ofthe gas mixture.) 12•17 B-17Carbondioxide is also emitted through combustion 

### in compressors, burners, and flares. Emissions from

**gas~**fired compressorengines used to transport natural gas from production to market were determined using a C0 2 emission factor of0.89 lb C02/hp·hr18 and the total hp-hr forproduction, transmission, andprocessing 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 otherplant, lease, orpipeline fuel requirements. Theamount ofnatural gas used for fuel purposes otherthan compressors was estimated in the VentedandCombustion Source Summary tobe approximately 558 BscfY. 17 This results 

### in an additional 3.6 lb C02 /MMBtu, based on the 

### C0 2 emission factor from natural gas combustion of 120 Ib CO/lv.lscf20 It should be noted that this estimate is conservatively

### high since a portion ofthe fuel gas is used by the petroleum industry to operate equipment such as
**gas~lift** compressors and **heater~treaters.** Finally, a small amount ofC02 is generated from flaring natural gas. 

### The VentedandCombustionSource 

### Summary estimates 15.1 BscfY ofmethane is flared from productionthrough distribution." Based ona 98% to 99% combustionefficiency, where ali ofthe methanecom busted is assumed to form C02, 0.1 1b C02 /MMBtu result from flaring. Methane emissions from the production, transmission, gas processing, and distribution ofnatural gas are approximately 314 Bscfor 6.04 Tg/yr (methane emissions from end uses are negligible). Based onthemarketed 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 

### C0 2 emissions requires a GWP, which for methane is 34for an integration interval of50 years and is 6.5 for an integrationinterval of500 years. 6• 7 • 8•

9 Applying these conversion factors. theequivalent C02 emissions formethane 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 summarizesthevarious components that contribute equivalent C02 emissions from the natural gas fuel cycle.
B-18TABLE 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 C0 2 

### Emissions 7.0 7.0 Industry BurnerC02 Emissions 4.6 4.6 Flare C02 Emissions 0.1 0.1 

### Methane Emissions 4.7 24.5

TOTAL 132.0 151.8
Coal Methane emissions result primarily from coal mining; emissions ofmethane from the transport or end uses ofcoal are negligible. EPA's

### Inventory of Greenhouse Gas Emissions andSinks 

### reports methane emissions from coal mining activities ranging between 3.2 

### and 5.0 million metric tonnes ofmethane for the year 1992. 12 Based on the 1992 coal production of 997.5 million shorttons," and the coal higherheating value of 10,395 Btullb," methane 

### emissions from this source equate to 0.44 

### Ibs rnethane!M:MBtu. In comparison, another EPA report shows 30to50 million metric tonnes ofmethane emitted globally corresponding to coal production 

### of 5 billion tonnes. 13 Forthe same heating value, these values result 

### in 0.77 lbs methane/MMBtu. An average ofthe two sources (0.60 lbs methaneiMMBtu) 

### was used to estimate equivalent 

### C02 emissions of3.9 lbs 

### C02 /MMBtu for a GWP of6.5 and approximately 20.4 lbs 

### C02 /MMBtu for a GWP of34. The 

### primary source ofC01 emissions from coal results from combustion. EPA reported that C01 emissions from energy production were 430.4 million metric tonnes ofcarbon 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 ofcoal during transport are estimated to result in 

### an additional increase in C02 

### emissions of approximately 1%, 

### or2.1 

### 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

. 

### lbCO,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 2.06 

### Methane 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 C0 2 

### emissions resulting from petroleum operations (production through transportation ofrefinery 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 PRODUCTIONTHROUGH REFINED PRODUCTTRANSPORTATION Methane Emissions 

### C02 

### Emissions, IndustrySegment 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
Forthe 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 differentproducts generated from crude oil. Starting in refining, emissions from individual fuel products are directlyrelated to the emission sources associated withthoseproducts; before the refining segment, a directrelation is not possible. Some portion ofemissions generated from crude production and transport must 

### be assumed to be associated with individual fuel products. For the purpose ofthis study,the fuels ofinterest (i.e., those comparable 

### with the primary uses of natural gas and coal-residentialheating and generating electricity) are distillate and residual fuel oils. Emissions associated with these fuel oils are assumed to beproportional to the ratio of the mass ofdistillate and residual fuel produced inrefining to the mass ofthe total refinery crude charge: Fuel oil produced (mass) z Total fuel oil emissions (mass) Refinery crude charge (mass) Total crude emissions (mass) (B7) Therefore, thetotal 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 ofC02

### or methane from production through product transportation The mass offuel oil produced for market in 1992 is 2.215x 108 

### tons. This is based 

### on !.09xIO' 

### bbls ofdistillate" with a specific gravity of0.8654,24 

### resulting in I.65x 108

### tons distillate produced in 

### 1992. In addition, residual production of5.64xI07

### tons is based on 326xi08 

### bbls ofresidual23 with 

### a specific gravity of0.982 (which is estimated from the specific gravities offuel oilsNos. 2, 4, 5, and 6 weighted 

### by the relative volumes ofeach produced).24 

### The mass ofrefmery crude charge for !992 is 7.53 x !08

### tons (based on 4.91 xJ09 

### bbls ofcrude and an average crude specific gravity of0.876). 23" 

### The resulting ratio offuel oil to crude charge is approximately 0.294. Thegeneralmethodology forestimating emissions from the fuel cycle ofdistillate 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 ofend use emissions from distillate and residual fuels (not included 

### in the API study). The combined higherheating value for distillate and residual fuel oil is 19,194 Btu/lb based onthe individual HHVs (19,524 Btu/lb for distillate and 18,228 Btu/lb for residual)25 

### weighted by 

### the relative production rate ofeach fuel (presented above). The resulting 

### C02 

### emissions from production through producttransport 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 C02

### 1Mlv1Btu for a G\VP of6.5 and 

### 2.0 Jb equivalent C0 2 

### /MMBtu 

### for a GWP of34.
B-22End use emissions ofmethane, from the combustion ofpetroleumproducts in turbines orboilers, are negligible. However, C0 2end 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 C02x gal fuel 

## = lb C02 

### gal fuel Ib fuel 12 Ib C MMBtu MMBtu (BIO) Thisassumes 

### all ofthe carbon present in the fuel oil is combustedto fonn 

### C02• The properties ofdistillate 

### and residual fuel oils 

### and the corresponding 

### C0 2 combustion emissions 

### are sho\\tll 

### in Table B-10. 

### Property• Density, lb/ga! %Carbon 

### HHV, MMBtu/ga! lb 

### C02 /MMBtu 

### TABLE B-10. PROPERTIES OFFUEL OILS DistillateFuel Oil 7.206 86.4 

### 0.141 161.9 

### ResidualFuel Oil 8.212 85.7 0.150 172.0 These values were combined to generate oneend use emission estimate for fuel oils based on a weighted average with respect to theproduction rate ofeach 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 summarizesthe emissionestimates for the fuel cycle ofresidual and distillate fuel oils.



### B-23TABLE B-11. C02EQUIVALENT EMISSIONS FROMFUEL 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 WarmingConclusions Table B-12 lists the greenhouse gas emissions, expressed as pounds of equivalent CO,perMMBtu for natural gas, coal, and oil. To quantify the relative impacts on global warming ofcoal and oil compared to natural gas, the equivalent 

### C0 2 emissions per

### unit ofenergy for coal andoii are divided bythe 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 FORNATURAL GAS, OIL, AND COAL



### .. Fuel Source Ibs CO,JMMBtu
. EquivalentCO,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 ofnatural gas. Similarly, coal contributes 50 to 60% more equivalent 

### C02 

### emissions than natural gas, resulting 

### in 1.5 to 1.6 times the impactonglobal wanning. These results are in 

### basic agreement with 

### IPCC's conclusions on fuel switching to reduce greenhouse gas emissions: B-24Switching from coal to oil or natural gas would reduce carbon emissions 

### in proportion to the carbon intensity ofthe fuel. Forexample, sv.ri.tching from coal 

### to natural gas wouldreduce emissions by 40%. In addition, the higherenergy efficiency available 

### with natural gas would reduce emissions further-for example, a shift from coal to natural gas inpower generation by 20%. 1 The net result is that switchingfrom otherfuels to natural gas can help the United Statesreach its goals on limiting greenhouse gas emissions a:J.d theirpotential impact on global wanning.



### B-25

### B.6 REFERENCES 1. World Meteorological Organization. Climate Change 1995Impacts, Adaptations 

### andMitigation of Climate Change: Scientific-TechnicalAnalyses. 

### Intergovernmental Panel on Climate Change, United Nations Environment Programme, 1996. 2. Ehhalt, D.H. The Atmospheric Cycle ofMethane, Tellus, 

### 26 55-70, 1974. 3. Seiler, W.R. Conrad and D. Scharffe. "Field Studies ofMethane Emission from Termite Nests into the Atmosphere and Measurements ofMethane Uptake by Tropical Soils, J. 

### Atrrws. Chem, 

### 1, 171-186, 1984. 4. Crutzen, P.J. "Role ofthe Tropics in Atmospheric Chemistry," Geophysiology of Amazonia, 

### edited by R.E. Dickinson, pp. 107-130, John Wiley, New York, NY, 1987. 

### 5. Sheppard, J.C., H. Westberg, J.F. Hopper, K. Ganessan, and P. Zimmerman. "Inventory ofGlobal Methane Sources and Their Production Rates," J. 

### Geophys. Res., 

### 87, 

### 1305-1312, 1982. 6. World Meteorological Organization. Climate Change 1995 The Science of Climate Change. 

### Intergovernmental Panel on Climate Change, United Nations Environment Programme, I

### 996. 7. World Meteorological Organization. Climate Change, 1990. 

### !ntergoverurnental Panel on Climate Change, United Nations EnvironmentProgramme, I

### 990. 8. 

### World Meteorological Organization. Climate Change, 

### 1992.1ntergovernmental Panel on Climate Change, United Nations EnvironmentProgramme, 1992. 9. World Meteorological Organization. Climate Change, 1994. 

### intergoverurnental Panel on Climate Change, United Nations Environment Programme, 1995. 10. Columbia Gas.

### AnEngineering Estimate of the Incremental Change in Methane Emissions with Increasing Throughput in aModelNatural Gas System, Final 

### Report, GRJ-94/0257.32, Gas 

### Research Institute, I

### 993. 11. Energy Information Administration, 

### Emissions of Greenhouse Gases in the UnitedStates 1987-1994,

### Department ofEnergy, DOEIE!A-0573(87- 94),Washington, DC, October 1995.
B-2612.
13.

14. 15. 16. 17.

18.

19.

20.

21. 

### U.S. EnvironmentalProtection Agency. Inventory of US. Greenhouse Gas 

### Emissions andSinks: 1990-1993, EPA-230/R-014 (NTIS PB95-138079), Office ofPolicy, Planning and Evaluation, Washington, DC, September 1994. 

### International Workshop on Methane Emissions from Natural Gas Systems, Coal Mining, and Waste Management, Sponsored by

### the Environment Agency of Japan, U.S. Agency for International Development, and U.S. EPA, April 9-11, 1990. 

### Energy International. Energy Utilization andGreenhouse Gas Emissions: End

### Use Analysis, Final Report, GRI-93/0335, Gas Research Institute, June 1994. Energy Infonnation Administration. 

### Coal IndustryAnnual1993, Department of Energy, DOE/EIA-0584(93), Washington, DC, December 1994. 

### American Gas Association, GasFacts: 1992Data, 

### "Supply and Disposition of Gas in the United States, 1969-1992,"Arlington, VA, 1993. 

### Shires, T.M. and M.R. Harrison. Methane Emissions from the Natural Gas Industry, Volume 6: VentedandCombustion Source Summary, 

### Final Report, GRI94/0257,23 andEPA-600/R-96-080f. Gas Research Institute and U.S. 

### Environmental Protection Agency, June 1996. U.S. Environmental Protection Agency, Compilation of AirPollution Emission 

### Factors: Volume I StationaryPoint andAreaSources, AP-42 (GPO 055-000-005- 001), Table 3.2-2, U.S. EPA Office ofAir Quality Planning and Standards, 5th Edition, January 1995. 

### Stapper, C.J. Methane Emissions from the Natural GasIndustry, Volume 11: 

### Compressor DriverExhaust, 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 AirPollution Emission Factors: Volume I StationaryPointandAreaSources, AP-42 (GPO 055-000-005- 001), Table 1.4-3, U.S. EPA Office ofAir Qnality Planning and Standards, 5th Edition, January 1995. Energy Infonnation Administration. 

### Cost andQuality of Fuels for Electric Utility Plants 1993, Department ofEnergy, DOE/EIA-0191(93), Washington, DC, July 1994.

B-27

### 22.
23. 

### 24. 25. 

### Radian International LLC. Methane andCarbonDioxide Emission Estimates from US. Petroleum Sources, Draft Report, American Petroleum Institute, January 

### 1996. Energy Information Administration. Petroleum SupplyAnnual199 3, 

### Volume !. 

### DepartmentofEnergy, DOE/EIA-0340(93)/1, Washington, DC, June 1994. Combustion Engineering. Combustion FossilPower, 

### ABB/Combustion 

### Engineering, Windsor,CT, 1991. Baumeister, T., E.A. Avallone, and T. BaumeisterIll. Mark'sStandard Handbook/orMechanicalEngineers, 

### Eighth Edition, McGraw-Hill Book Company, New York, NY, 1978, p. 7-14.

B-28

### APPENDIXC Conversion Table

C-1Unit Conversion Table English to Metric Conversions 

### 1scfmethane 

## = 19.23 gmethane 1Bscfmethane 

## = 0.01923 T g methane 1 Bscfmethane 

## = 19,230 metric tonnes methane 1Bscf 

## = 28.32 million standard cubic meters 1 short ton (ton) 

## = 907.2 kg 1lb = 

### 0.4536 kg lft' 

## = 0.02832 m3 

### 1 ft3 

## = 28.32 liters 1 gallon 

## = 3.785 liters 1barrel (bbl) 

## = !58.97!iters 1 inch 

## = 2.540 em 1 ft 

## = 0.3048m 

### I mile 

## = 1.609 km 

### 1hp = 

### 0.7457 kW 1hp-hr = 

### 0.7457 kW-hr lBtu 

## = 1055joules lMMBtu 

## = 293 kW-hr llb/MMBtu = 

### 430 g/GJ T ('F) 

## = 1.8 T ('C)+ 

### 32 1psi 

## = 51.71 mm Hg
Global Warming Conversions 

### Calculating carbon equivalents ofany gas:

( MW carbon) MMTCE = (MMT of gas) x ' x (GWP) MW, gas


### C-2

### Calculating C02 

### equivalents for methane:
( Mw,

# co,) MMT of C02 equiv. = (MMT CH,) x x (GWP) MW, CH, where MW (molecular weight) ofCO, =44, MWcarbon= 12, and MW CH,= 16.

N!!i§ scf Bscf MMscf Mscf Tg Giga (G) 

### Metric tonnes psig 

### psia 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'). !000kg. 

### Gauge pressure. Absolute pressure (note psia = 

### psig +atmospheric pressure). Global Warming Potential ofa particular greenhouse gas for a given. 

### time period.

= 

### Million metric tonnes ofagas.

= 

### Million metric tonnes, carbon equivalent. MMT ofC02eq. = 

### Million metric tonnes, carbon dioxide equivalent. 

### C-3

### APPENDIXD Project Reviewers

D-1

### PROJECT REVIEWERS* Name Company Ackell, John Oil HeatTask

**Fo~e** Ammirato, Vincent ColumbiaGas Ball, Richard H. U.S. DepartmentofEnergy Benjey, Bill PA Bjerklie, John Consolidated NaturalGas Boss, Terry INGAA Bradford, Ray biUips 66 Brasseur,Guy National Center for Atmospheric Research Busch, William NOAA Carter, Doug 

### DOE Chai, Eric Shell Development Childress,P.O. ColoradoInterstateGas Ching,Jason EPA Cohen,Jonathan ICFKaiser Cook. Tracy SoC aI Cormier, Michael Amoco Production Co. Cuig, Bruce

**~atural** GasSupplyAssoc. Derkowski, CaJTie Coastal Doyle, Terry

. ;Enron Corp Doyle, William J. MarathonOil Company Eberle, Art ColumbiaGas Enright,Jeffrey ICFKaiser Erickson,John American GasAssot:iation Farrand, David WilliamsNatural Gas Fisher, Diane Environmental Defense Fund Fitzgibbon, Timothy ICF Fritz, Eric NaturalGasPipeline Fung, Inez NASA Goddard Institute for Space Studies Gibbs, Michael ICF Godec, Michael ICF Goens, Dick Union GasLtd. Haines, Deanna SoCaJGas Hansen, Anne NGL Hansford, James E. Enrcn Gas Pipeline Hare, Marik.a ConsumersGas Hay, Nelson Americ:an Gas Association (A.G.A.) Hogan, Kathleen EPA-OAR lnnerarity, Mike TennecoEnergy Isaacson, Ron GRI .Johnson, Donald rgonne National Laboratory Kalkstein, Larry EPA Kirchgessner, Dave EPA Klein, Gary API,Oil HeatTask Force Kni2ht, Bruce Marathon Oil D-2 (Continued)

### PROJECTREVIEWERS* (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,MichaelJ. Niagara Mohawk Power Corporation Mercado, Donna American Gas

**Ass~iation** Meshkati, Shabed SoCal Minotti, Marcello Tenneco Mize, Ed Williams Natural Gas Mobley, DavidJ. 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 Enron 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)

### PROJECTREVIEWERS* (Coot'd)

**Nam~** Company

- Tixier, Charles 

### iShell Traweek, Lori American Gas Association VanWyck, Robert ConEdison VanDerZanden, Daniel lcbevron Warner,John Amoco Weynand, Gordon EPA Woodbury,Jonathan ICF Yundt, Paul Gas Technology Canada Zinkham,Jeffrey Amow 

### *Projectreviewers have participated 

### in one ormore review meetings forthis project over the

timeperiod !990-1996.

D-4I ' '

------ 

## ' '

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

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**~Q~_t !.!atll!'.~**  gas contributes less to potential
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Stationary Sources Global WarmingU.S. ENVIRONMENTAL PROTECTION AGENCY Office of Research and Development National Risk Management Research Laboratory Technology Transferand Support Division Cincinnati, Ohio 45268 OFFICIAL BUSINESS PENALTV FOR PRIVATE USE. 5300 AN EQUAL OPPORTUNITY EMPLOYER

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## Publication No. EPA- 600 iR-96-0BOb